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HomeMy WebLinkAboutStudy of Alternative Power Supply Organizational Structures for CEA, HEA, MEA, 1983Report on the Study of Alternative Power Supply Organizational Structures for Chugach Electric Association, Inc. Anchorage, Alaska Homer Electric Association, Inc. Homer, Alaska Matanuska Electric Association, Inc. Palmer, Alaska RARY COPY 1983 82-113-4-000 Barns & M“Donnell ENGINEERS - ARCHITECTS - CONSULTANTS Report on the Study of Alternative Power Supply Organizational Structures for Chugach Electric Association, Inc. Anchorage, Alaska Homer Electric Association, Inc. Homer, Alaska Matanuska Electric Association, Inc. Palmer, Alaska 1983 82-113-4-000 Burns & M“Donnell ENGINEERS - ARCHITECTS - CONSULTANTS Burns & MSDonneil ENGINEERS - ARCHITECTS - CONSULTANTS May 25, 1983 Board of Directors Chugach Electric Association P.O. Box 3518 Anchorage, Alaska 99501 Board of Directors Homer Electric Association P.O. Box 429 Homer, Alaska 99603 Board of Directors Matanuska Electric Association P.O. Box 1148 Palmer, Alaska 99645 Chugach, Homer and Matanuska Electric Associations Study of Alternative Power Supply Organizational Structures Final Report Project 82-113-4-000 Members of the Boards: In accordance with your authorization, we have performed a study of alternative types of organizations which Chugach Electric Association, Homer Electric Association, and Matanuska Electric Association (the Cooperatives) might adopt to supply power to their systems in the future. This document is the final report on our study. The scope of the study included reviewing the existing electric systems and power supply organization of the Cooperatives, developing load forecasts and long-range power supply expansion plans, reviewing alternative forms of power supply facilities ownership, defining organization structures for detailed study, and performing a comparative economic analysis of the organizations defined for detailed study. We consider it important to emphasize that the focus of this study was on the comparative evaluation of power supply organization alternatives. With this objective in mind, it was possible to make many simplifying assumptions for study purposes. Because of these simplifying assumptions, it is not appropriate to use the results presented in this report as a basis for comparing the relative economic feasibility of the long-range power supply expansion scenarios considered in this study. Any conclusions concerning alternative long-range power supply expansion scenarios or specific expansion plans should be formulated only on the basis of the 4800 EAST 63rd STREET, PO. BOX 173, KANSAS CITY, MISSOURI 64141 e TEL: 816-333-4375 TWX: 910-771-3059 Board of Directors Page 2 May 25, 1983 results of a detailed power supply planning study, such as the one currently being performed for Chugach Electric by Burns & McDonnell. We would also like to emphasize that it was beyond the scope of this study to develop for the Cooperatives the details of the organizational structure, contractual arrangements and other aspects of the power supply organization type recommended for implementation. While it was necessary during the course of the study to make specific assumptions concerning alternative power supply organization types, it was recognized that the actual detailed organizational arrangements and terms of the arms-length agreements pertaining to the organization type ultimately selected for implementation would need to be developed and negotiated by representatives of the Cooperatives after a decision to go forward with a particular organization type has been made. The organizational alternatives considered in the study included continuation of the existing power supply arrangement or formation of a new organization. New organization types examined included a generation and transmission (G&T) cooperative, a public power agency, a taxable utility and some possible combination (hybrid) of these organizations. In general, it was assumed the membership or ownership of any new power supply organization would either involve only Chugach alone, or Chugach, Homer, and Matanuska, jointly. After considering the advantages, disadvantages and problems associated with various organizational alternatives, two alternatives were selected for more detailed study. One alternative assumed continuation of the present power supply situation with Chugach, as a distribution cooperative, continuing to own and operate the majority of the generation and transmission facilities supplying power to all three cooperatives. This alternative also assumed Chugach would be required to maintain a minimum Times Interest Earned Ratio (TIER) of 1.5 on all long-term loans beginning January 1, 1983. Thus, it was assumed that the agreements with the Rural Electrification Administration (REA) and the National Rural Utilities Cooperative Finance Corporation (CFC) which allow a TIER ratio of only 1.15 on generation and transmission-related loans would not be extended beyond the end of 1983. Correspondence from REA and CFC indicated these organizations are not willing to allow Chugach to operate as a split-TIER organization (minimum TIER of 1.5 on distribution facility loans and 1.0 on generation and transmission facility loans). The other alternative selected for detailed study was the formation of a G&T cooperative. It was assumed for study purposes that a G&T could commence operation on January 1, 1984. The position of REA and CFC on TIER levels for distribution and G&T cooperatives can, perhaps, be summarized from the findings of the Report To Committee on Objectives and Planning of National Rural Utilities Cooperative Finance Corporation by’ the investment banking firm of Lehman Brothers Kuhn Loeb (LBKL) dated November 19, 1982. This was a major study of the future capital requirements of the rural electric program and possible means by which Board of Directors Page 3 May 25, 1983 these requirements can be met, with particular emphasis on financing alternatives to the REA's present lending programs. According to the LBKL report: "It is a well-established and accepted principle in the rural electrification program that equity is accumulated at the distribution level. Likewise, distribution cooperative TIERs are maintained at levels which in most cases provide more than two times coverage of interest expense by net margins and patronage capital. On the other hand, the ‘all requirements’ power contract between G&Ts and their members mandate that G&Ts design rates which ‘are sufficient, but only sufficient’ to cover all costs, including debt expense and the establishment of ‘reasonable reserves.’ Rating agencies have accepted the resulting minimal G&T TIER and DSC ratios, and negligible equity to asset ratios, only on the basis of this principle of credit strength at the distribution level. Their rating evaluations of G&Ts thus rely heavily on a composite credit evaluation of member systems." It was recognized that in terms of the formation of a G&T cooperative, several further alternatives are possible. The basic G&T alternatives involve the formation of a G&T cooperative by Chugach alone or a joint G&T involving Chugach, Homer and Matanuska. Other alternatives possible include the formation of a joint G&T involving Chugach and Golden Valley Electric Association (GVEA) or all three cooperatives and GVEA. The practicality of a possible G&T relationship involving the Cooperatives and GVEA should be significantly increased with completion of the Anchorage-Fairbanks Intertie project scheduled for December 1984. However, because the possible formation of a G&T with GVEA was beyond the scope of this study, it was not analyzed as part of this study. An economic analysis was performed comparing the alternative of continuing the present power supply organization with the alternative of forming a joint G&T involving the Cooperatives. No economic analysis was performed for the case in which Chugach would formulate a G&T alone because the overall power supply cost impact on the Cooperatives was considered to be approximately the same in either case when compared to the alternative of perpetuating the existing power supply organization. Three long-range expansion scenarios were addressed in the study. These include a hydro expansion scenario which assumed the development of the Susitna Project, a gas-fired expansion scenario, and a coal-fired expansion scenario. Power supply related revenue requirements from members were projected for all three scenarios over the period 1983-2015 for both of the organizational alternatives. ong a Board of Directors Page 4 May 25, 1983 The economic analysis assumed an average TIER level of 2.0 would be maintained if the present situation were to be continued and that an average TIER level of 1.2 would be maintained under the G&T alternative. These assumed TIER levels, which are higher than the minimums of 1.5 and 1.0, reflect the need for cooperatives to target their average TIER levels well above the minimum requirements to ensure that actual TIER levels will consistently remain above the minimum levels. TIER levels higher than the minimum are desirable because of regulatory lag in obtaining needed rate increases and to allow for contingencies and uncertainty. In fact, a 2.0 TIER level for a distribution cooperative is probably minimal as a TIER target level. The LBKL Report also noted that along "with the rest of the utility industry there has been a deterioration of the TIER of CFC's distribution members from a weighted average of 2.34x in 1977 to 2.05x in 1981. Since they provide the primary credit support for CFC's debt obligations, this is an area requiring constant attention.” Another important assumption of the economic analysis was that capital credits (member equity or accumulated operating margins) would be retired (returned to members) on a 20-year rotation schedule. Sensitivity analyses were also conducted which assumed that capital credits would be retired on a 10-year rotation schedule. The CFC/NRECA Capital Credits Study Committee report of February, 1976 recommended a 10- to 20-year capital credits rotation schedule for distribution cooperatives. The results of the economic analysis indicate that for the expansion scenarios evaluated, revenue requirements from members in the short-run will be considerably higher assuming continuation of the present arrangement compared to the G&T alternative. This can be seen in Table 1 which presents the results for the gas-fired long-range expansion plan assuming a 20-year capital credits rotation period. Revenue requirements from members under the G&T are projected to be 24.7 percent lower in 1984 (the initial year assumed for the G&T's operation) and to drop to 3.1 percent lower by 1990 compared to the existing arrangement. By 1991, the advantage is projected to shift to the existing arrangement. It should be noted that the revenue requirements presented in Table 1 include credits to members for capital credits retirements. That is, capital credits assumed to be returned to members in a given year have been subtracted from revenue obtained through member rates in that year to produce the revenue requirements of Table 1. Since capital credits retirements would be greater under the existing organizational alternative (due to a more rapid equity build up because of the higher TIER), member rates would actually be relatively higher than suggested by the results in Table 1 for the existing arrangement as compared to the G&T cooperative for the years after 2002 (capital credits retirements are assumed to commence in 2003 under a 20-year rotation). On a present value basis, the two organizational alternatives are approximately equal over the 1983-2015 study period under the gas expansion scenario (0.3 percent advantage for the G&T) as can be seen in Table 2. This relatively small present value difference is to be expected since a cooperative is consumer owned and all equity eventually accrues to the oe Board of Directors Page 5 May 25, 1983 membership, regardless of TIER assumption all other factors being equal. Also, as might be expected, a more capital intensive expansion scenario more strongly favors the G&T cooperative on a present value basis. As shown in Table 2, the present value advantage of the G&T cooperative for the more capital intensive coal-fired expansion scenario was projected to be $63.7 million (1.5 percent) while the existing arrangement has a $29.6 million (0.9 percent) advantage under the hydroelectric expansion scenario where the bulk of capital was assumed to be invested by the State of Alaska instead of the Cooperatives. This indicates that the greater the required investment in power supply facilities by the Cooperatives, the greater the present value advantage of the G&T form of organization. An important point to consider in contemplating the results of the economic analysis is that the expansion plans evaluated assumed a constant annual load growth rate of 3.43 percent per year over the period 1983-2015. Preliminary results of the Power Requirements Study Burns & McDonnell is currently performing for Chugach, which unfortunately were not available in time to factor into this study, indicate that this load growth rate may well be too low. The moderate growth scenario from the Power Requirements Study projects a growth rate for peak demand of 6.6 percent per year over the period 1982-1992. As a result, it is likely that the capacity expansion plans used in the economic evaluations of this study are very conservative on the low side in their assumptions concerning the amount of investment in power supply facilities which may be required of the Cooperatives during the next 10 years. In fact, the preliminary results of the Power Supply Planning Study we are performing for Chugach indicate this will indeed be the case. Thus, it is likely that the impact on member revenue requirements will be much greater than indicated by the results of our analyses in this study if a G&T is formed. In summary, the economic analysis results indicate that the formation of a G&T cooperative will result in substantially lower member revenue requirements in the short run. Additionally, the magnitude of this short-run advantage and its duration will be greater if the required power supply facilities investment is larger than we have assumed for this study. In the long run, the two organizational alternatives would be approximately equivalent in terms of the present value of member revenue requirements if only modest investment in additional power supply facilities is required of the Cooperatives. More capital intensive expansion plans will more strongly favor the G&T cooperative on a present value basis. In fact, the greater the required power supply facilities investment and the longer the period of capital credits retirement, the greater the economic advantage of the G&T. Under the existing arrangement members would pay significantly higher rates up front, building up equity which would eventually be returned to them in the form of capital credits. The Cooperatives would, in effect, be borrowing much more money from their members through higher rates under the existing arrangement than under the Gat. Board of Directors Page 6 May 25, 1983 Assuming the Cooperatives would prefer to maintain substantially lower member rates in the short term, the results of our study indicate it would be economically preferable to form a G&T cooperative rather than continue with the present power supply situation. There are, of course, many factors which come into play and many uncertainties involved in making a decision of this nature. After weighing and considering the results of our economic analyses and the other information available to us concerning the power supply situation of the Cooperatives, it is our opinion that a G&T is the preferred power supply organization type. Formation of a G&T cooperative would lower member rates and revenue requirements in the short run; be consistent with the express desires of CFC, REA, and the APUC; would not require enabling legislation; would be a logical extension of the current form of organization (rural electric cooperative); could be expanded to add new member systems; and would provide a more flexible organization to deal with the complex and dynamic power supply environment of South Central Alaska. There is also considerable precedent for the formation of a G&T cooperative since this is the form of organization being utilized by virtually all other rural electric cooperatives in the United States that have pursued major power supply programs. Also supporting this conclusion are the preliminary results of the Power Supply Planning Study which we are performing for Chugach. The results of this study indicate a much greater capital investment requirement for power supply facilities over the next decade than projected for purposes of developing the results of this study. This difference is primarily due to the higher load growth rate being used in the Power Supply Planning Study. For these reasons, we recommend the formation of a G&T cooperative. The formation of a G&T cooperative, however, will not be easy if this is the course selected by the Cooperatives. A number of important decisions and major commitments must be made by all concerned if such an organization is to be formed. Perhaps, the most important initial decision would involve a decision by Chugach to either form a G&T alone or a joint G&T with Homer and Matanuska and/or possibly GVEA. The formation of a G&T by Chugach alone could no doubt be accomplished more quickly because only one party (Chugach) would be involved. Forming a joint G&T would be complicated by the need to gain additional approvals and to negotiate and come to a mutual agreement among the parties on various aspects of the G&T's structure. From the perspective of Chugach, there are also a number of significant concerns which would need to be addressed if a joint G&T is to be formed. For Chugach, a disadvantage associated with the formation of a joint G&T is that Chugach would lose exclusive control and ownership of its power supply facilities. Related concerns are that the members of Chugach might lose the benefit of existing favorable fuel contracts and have their vested equity in power supply facilities diluted. The results of our investigation and experience suggest these concerns can be resolved to the mutual satisfaction of all parties. For example, concerns about relative control of decision making might be accommodated through some form of weighted voting on key issues. The issue of existing equity in power supply facilities could be resolved by appropriate compensation from the G&T. In fact, the figures we have developed indicate that the combined amount of equity in power supply road ol amy ey, Board of Directors Page 7 May 25, 1983 facilities of the Cooperatives is relatively small (roughly $7.5 million) compared to the outstanding loan principle balance (about $217 million) on G&T facilities. Regarding the fuel contracts, the Cooperatives already share the benefits of these contracts under the existing power sales agreements. A valid concern of Chugach would be that these benefits not be diluted in the future. It would seem that appropriate arrangements to mitigate this concern, such as weighted voting, could be negotiated during the G&T formation process. Thus, we believe that the major apparent obstacles to the formation of a joint G&T can be overcome. At the same time, we believe there are significant advantages to be gained by the Cooperatives from the formation of a joint G&T cooperative. For Homer and Matanuska, an important benefit of a joint G&T is that it would provide them (and their consumers) with a voice in power supply matters. For all three cooperatives, the most important benefit may be the creation of a strong power supply organization with the resources to operate successfully in the highly dynamic environment of South Central Alaska. The importance of a strong cooperative power supply organization dedicated to reliably supplying the power needs of its members at the lowest possible cost cannot be overemphasized. Also, a joint G&T is the form of organization preferred by REA. For these reasons, we consider a joint G&T to be the preferred form of power supply organization for the Cooperatives. Because of the economic and other benefits to be derived from the formation of a G&T and the expiration at the end of 1983 of Chugach's agreement with REA and CFC permitting a 1.15 TIER on G&T properties, we recommend that the necessary steps leading to the formation of a G&T cooperative be initiated as soon as possible. The formation of an operating G&T, especially a joint G&T, is a complex process as discussed in Part VII of our report. The complexity of forming a G&T can be expected to be compounded by the many other demands on the time of the boards and staffs of the Cooperatives, the need to obtain member approval, and the need to negotiate mutually acceptable arrangements if a joint G&T is established. It should also be realized that a G&T cooperative would have to depend heavily on the existing Chugach organization and would probably have to contract with Chugach for staff and logistic support during the initial years following its formation. At the same time it is important to recognize that a new G&T would be much more than a paper organization in that it would own and control substantial power supply resources, have a sizeable staff, and have major contractual obligations. It should also be noted that the formation of a G&T is likely to result in significant additional expense resulting from some duplication of staff and facilities. We have estimated for purposes of our analyses an eventual incremental cost of $2.0 million per year to operate a separate G&T compared to continuation with the present organization. While this is a significant additional cost, we believe that savings from increased efficiencies which should result from the operation of an organization dedicated exclusively to power supply will substantially offset or exceed this additional expense. ~ =, Board of Directors Page 8 May 25, 1983 However, because such savings are difficult to reliably quantify, we have included no allowance for savings from any increased organizational efficiency possible through the formation of a G&T in our study. We would also like to mention that our study assumed that financing for power supply facilities would continue to be available to the Cooperatives under the REA guaranteed loan program. Obviously, there is no assurance that funds under this program will continue to be available to the Cooperatives in the future, and the Cooperatives may be forced at some future point in time to seek other sources of financing. On the other hand, we believe the maintenance of the status quo regarding the Cooperative's source of financing to be a reasonable assumption because any other assumption would be much more speculative in view of the unpredictability of future actions concerning such matters by the federal government. At the same time, we are of the opinion that a strong G&T Cooperative would facilitate the direct entry of the Cooperative's into the private capital markets if this should ever become necessary. This view appears to be supported by the following conclusion of the LBKL Study: "G&T systems have the potential for expanding their access to private capital, but within the context of a strong continuing REA guarantee program. The Committee on Objectives and Planning projects a total of $49.3 billion of capital commitments for construction programs through 1990. In our judgment, even the fullest possible exploitation of available private financing alternatives would fall short of meeting these requirements. It is particularly important to stress that even the perception of substantially diminishing REA support would limit the full utilization of available private market alternatives--that is to say, that access to the private market will be maximized if a strong ongoing REA financial and administrative commitment is assured. Given this assurance, we believe that G&T systems have several alternatives for expanding their access to private capital." We hope that the findings and recommendations of our study will facilitate your consideration of the power supply organizational alternatives and assist you in making decisions which will be in the best interest of all consumers of the Cooperatives. We note again that the current agreements with REA and CFC allowing the Coperatives to maintain a TIER of only 1.15 on generation and transmission facilities expire at the end of this year. Thus, it would appear prudent for the Cooperatives to move as quickly as possible toward a resolution of the organizational status of their power supply. Board of Directors Page 9 May 25, 1983 We would like to express our appreciation to the general managers and staffs of the Cooperatives for their excellent support in the form of providing data and input to our study. If you wish, we will be glad to discuss the results of our study with you in detail at your convenience. Respectfully submitted, BURNS & McDONNELL oC em] N. A. Campbell, *E Lo: “7 - A. Campbell, ™E. 2x5 49TH eh President ‘ CO Ox. fe ae , VB, MIE RP C x Matt. Qo... Wa Cc. K. Martin, P.E. Nea ie Vice President Wank” (the. Sf Peter Steitz, P.E. Chief, Power Supply Analysis Section NAC/RM/rab356 Table 1 COMPARISON OF PROJECTED MEMBER REVENUE REQUIREMENTS FOR GAS-FIRED EXPANSION PLAN! (LESS RETIRED CAPITAL CREDITS BEGINNING 20037) Existing Arrangement G&T Cooperative G&T Above (Below) Assuming 2.0 TIER Assuming 1.2 TIER Existing Arrangement Calendar Year {$ Million) —-_(Mills/kWh)_ (8 Million) §=—_{Mills/kWh)_ (Million) ——_{Mills/kWh)_ (0) 1983 48.0 _ 28.6 48.1 28.7 0.1 0.1 0.3 1984 73.3 42.1 55.1 31.7 (18.2) (10.4) (24.7) 1985 90.0 50.0 76.3 42.4 (13.7) (7.6) (15.2) 1986 94.1 50.4 78.2 41.9 (15.9) (8.5) (16.9) 1987 90.5 46.8 80.9 41.8 (9.6) (5.0) (10.7) 1988 123.7 61.7 115.9 57.8 (7.8) (3.9) (6.3) 1989 128.4 64.0 122.7 61.2 (5.7) (2.8) (4.4) 1990 129.8 61.4 125.9 59.5 (3.9) (1.9) (3.1) 1991 176.9 79.2 179.2 80.3 2.3 12 1.4 1992 184.0 79.6 194.5 84.1 10.5 4.5 5.7 1993 205.6 85.7 217.6 90.8 12.0 5.1 6.0 1994 226.7 91.2 240.3 96.6 13.6 5.4 5.9 1995 330.9 128.6 349.0 135.6 18.1 7.0 5.4 1996 455.1 170.6 471.1 176.7 16.0 6.1 3.6 1997 664.9 240.6 677.5 245.1 12.6 4.5 1.9 1998 754.2 263.2 765.1 266.9 10.9 3.7 1.4 1999 831.3 280.1 844.1 284.4 12.8 4.3 1.5 2000 938.6 305.1 954.0 310.2 15.4 5.1 1:7. 2001 1,064.3 333.8 1,062.7- 333.3 (1.6) (0.5) (0.1) 2002 1,173.3 355.0 1,177.0 356.1 3.7 Ty 0.3 2003 1,284.2 374.9 1,290.7 376.7 6.5 1.8 0.5 2004 1,413.5 398.3 1,443.1 406.6 29.6 8.3 2.1 2005 1,580.3 429.9 1,616.8 439.8 36.5 9.9 2.3 2006 1,794.4 470.7 1,834.0 481.1 39.6 10.4 2.2 2007 1,979.0 501.2 2,019.8 $11.5 40.8 10.3 2.1 2008 2,300.1 562.2 2,284.5 558.4 (15.6) (3.8) (0.7) 2009 2,547.6 600.4 2,512.5 592.2 (35.1) (8.2) (1.4) 2010 2,824.6 642.7 2,801.8 637.5 (22.8) (5.2) (0.8) 2011 3,067.2, 674.0 3,053.5 671.0 (13.7) (3.0) (0.4) 2012 3,433.8 727.7 3,428.2 726.5 (5.6) (1.2) (0.2) 2013 3,924.6 802.6 3,956.9 809.2 32.3 6.6 0.8 2014 4,369.0 862.2 4,334.2 855.4 (34.8) (6.8) (0.8) 2015 4,804.3 915.3 4,790.9 912.7 (13.4) (2.6) (0.3) i Key Assumptions: Interest Rate on REA Guaranteed Funds: 11.0 percent Interest Earned on Cash Balance: 8.0 percent : Assumes 20- Year Capital Credits Rotation. . . - “ a * me - ~ oe om et em ama) — ame) — rc? 3 ery rosy Table 2 COMPARISON OF PRESENT VALUE OF MEMBER REVENUE REQUIREMENTS FOR LONG RANGE EXPANSION SCENARIOS! (1983$) 20 YEAR CAPITAL CREDITS ROTATION Present Value 1983-2000 Present Value 1983-2015 G&T Above (Below) G&T Above (Below) Existing Existing Arrangement Existing Existing Arrai jt Expansion Arrangement G&T Arrangement G&T Plan ($ Million) ($ Million) ($ Million) (%) ($ Million) ($ Million) ($ Million) (%) Gas 1,652.5 1,630.9 (21.6) (1.3) 4,129.8 4,116.8 (13.0) (0.3) Coal 1,652.5 1,630.9 (21.6) (1.3) 4,190.4 4,126.7 (63.7) (1.5) Hydro? 1,882.5 1,860.8 "(21 -7) (1.2) 3,419.6 3,449.2 29.6 0.9 ! Assumes 11.0 percent discount rate. 2 Assumes development of Susitna project funded in part (45 percent) with State of Alaska grants. 8 | oni ere TABLE OF. CONTENTS SUMMARY AND CONCLUSIONS Study Purpose and Objectives Background Study Scope and Approach Alternative Power Supply Organizations Existing Arrangement Generation & Transmission Cooperative Current Arrangement. with Split TIER Public Power Agency Investor-Owned Utility Taxable G&T Cooperative Hybrid Organization Economic Analysis Assumptions. Economic Analysis of Power Supply Plans Conclusions and Recommendations : G&T Implementation Pre-G&T Formation Activities Post G&T Formation Activities PART I - INTRODUCTION Purpose Background The Cooperatives Chugach Homer Matanuska Study Scope and Approach PART II - EXISTING ORGANIZATION AND POWER SUPPLY Chugach Generation and Power Purchases Transmission Chugach's Contracts With Homer and Matanuska Fuel Supply Homer Matanuska PART III - ALTERNATIVE POWER SUPPLY ORGANIZATIONS Existing Arrangement No Change in TIER Split TIER Generation and Transmission Cooperative Public Power Agency Taxable Utility Hybrid Organization TC-1 “Page No. s-1 s-2 8-5 S-7 S-7' s-9 8-17 8-17 8-18 s-18 8-18 $-18 $-25 S-33 $-40 $-40 S-43 I-1 I-2 I-9 I=9 I-9 I-10 I-10 II-1 II-2 II-4 II-5 II-9 II-10 II-11 III-1 III-2 III-4 III-5 III-12 IITI-15 III-18 Organization Types Selected for Further Study Current Arrangement With Split TIER Public Power Agency Investor-Owned Utility Taxable G&T Cooperative Hybrid Organization Existing Arrangement Organization Staffing Facilities Financing and Rates Operation of Facilities Lease Agreements With Homer and Matanuska Generation and Transmission Cooperative Organization Start-Up Costs Staffing Facilities Financing and Rates Operation of Facilities Contractual Agreements PART V - DEVELOPMENT OF POWER SUPPLY EXPANSION PLANS Projected Power Requirements Projected Capacity Deficits Power Supply Alternatives: ~ Planned Gas Turbine Installation Anchorage-Fairbanks Transmission Intertie State of Alaska Generation Projects Natural Gas-Fired Combined-Cycle Plants Coal-Fired Generating Units Development of Power Supply Expansion Plans Hydroelectric Expansion Scenario Gas-Fired Eexpansion Scenario Coal-Fired Expansion Scenario Transmission Requirements PART VI - ECONOMIC ANALYSIS Method of Analysis Key Economic Analysis Input Parameters Economic Analysis of Power Supply Plans Conclusions and Recommendations PART VII - G&T IMPLEMENTATION General G&T Cooperative Implementation Pre-G&T Formation Activities Post G&T Formation Activities TC-2 Page No. III-18 III-19 III-19 III-20 III-20 III-21 PART IV - DEVELOPMENT OF SELECTED ORGANIZATIONAL ALTERNATIVES IV-3 Iv-3 IV-3 Iv=-4 IvV-8 Iv-9 IV-10 Iv-10 Iv=11 IV-11 IV-19 Iv-19 IV-22 IV-22 v-1 V-4 v-6 v-6 v-6 v-10 V=13 V-13 V-14 v-18 V-18 V-19 V-19 vI-1 VI-3 VI-5 VI-17 VII-1 VII-3 VII-4 VII-6 erent hereon — wend Severe heroes” heememngs Nereus remo) mes mm Lemon! g ’ t 4 y : ere eS ro APPENDIX A APPENDIX B APPENDIX C APPENDIX D APPENDIX E FINANCIAL FORECAST COMPUTER OUTPUT DESCRIPTION FINANCIAL FORECAST COMPUTER OUTPUT PROJECTED OPERATING RESULTS TIER REQUIREMENTS VERIFICATION FROM REA AND CFC SUMMARY OF 1981 ENERGY SALES AND CUSTOMERS FOR THE COOPERATIVES TC-3 Page No. A-1 B-1 c-1 D-1 Table No. s-1 s-2 S-3 s-4 S-5 II-1 Iv-2 IvV-3 v-1 V-2 V-3 V-4 vV-5 v-6 VI-1 VI-2 VI-3 VI-4 VI-5 VI-6 VI-7 LIST OF TABLES Page No. SUMMARY AND CONCLUSIONS Summary of Power Supply Expansion Scenarios Capacity Additions §-22 Comparison of Projected Member Revenue Requirements Gas-Fired Expansion Plan S-26 Coal-Fired Expansion Plan S-28 Hydroelectric Expansion Plan S-30 Comparison of Present Value of Member Revenue Requirements for Long-Range Expansion Scenarios S-31 PART II - EXISTING ORGANIZATION AND POWER SUPPLY Summary of Existing Generation Resources II-3 PART IV - DEVELOPMENT OF SELECTED ORGANIZATIONAL ALTERNATIVES Summary of Existing Power Supply Related Plant Assets Assuming Continuation of Existing Organizational Structure Projected Incremental Staffing for Chugach and G&T Summary of Existing Power Supply Related Plant Assets Assuming Formation of G&T Cooperative PART V - DEVELOPMENT OF POWER SUPPLY EXPANSION PLANS Load Projection For the Cooperatives .- Balance of Projected Loads and Resources for the. Cooperatives Profiles of Generation Alternatives Assumed Allocation of Capacity: from State of Alaska Projects Projected Purchased Power Costs Summary of Power Supply Expansion Scenarios Capacity Additions PART VI - ECONOMIC ANALYSIS Key Economic Analysis Input Parameters Comparison of Projected Member Revenue Requirements ; Gas-Fired Expansion Plan (Less Retired Capital Credits Beginning 2003) Coal-Fired Expansion Plan (Less Retired Capital Credits Beginning 2003) Hydroelectric Expansion Plan (Less Retired Capital Credits Beginning 2003) Gas-Fired Expansion Plan (Less Retired Capital Credits Beginning 1993) Coal-Fired Expansion Plan (Less Retired Capital Credits Beginning 1993) Hydroelectric Expansion Plan (Less Retired Capital Credits Beginning 1993 TC-4 IV-7 _IV-16 Iv-20 vI-4 VI-7 vI-9 VI-10 VI-12 VI-13 VI-14 Naess ssh ns a hacen be! fs. fa Fafa So Fo ts. es Peg fr 2 oo om —e Pa rr ro VI-8 Summary of Present Value of Member Revenue Requirements for Long-Range Expansion Scenarios TC-5 VI-15 Figure No. Iv-1 Iv-2 IV-3 VI-1 VI-2 VI-3 LIST OF FIGURES PART IV - DEVELOPMENT OF SELECTED ORGANIZATIONAL ALTERNATIVES Preliminary Organization Structure for Chugach (Proposed) Assumed Organization Structure - Chugach and G&T (Day After G&T Formation) Assumed Organization Structure - G&T Along (Five Years After G&? Formation) PART V - DEVELOPMENT OF POWER SUPPLY EXPANSION PLANS Balance of Projected Loads and Resources for the Cooperatives : PART VI - ECONOMIC ANALYSIS Comparison of Revenue Requirements for Gas-Fired Expansion Plan Comparison of Revenue Requirements for Coal-Fired Expansion Plan Comparison of Revenue Requirements for Hydroelectric Expansion Plan ese 2 2 TC-6 Page No. Iv-13 IV-17 V-7 VI-19 vI-21 VI-23 woven emcee! Late SUMMARY AND CONCLUSIONS a os rm pla SUMMARY AND CONCLUSIONS STUDY PURPOSE AND OBJECTIVES The purpose of this study was to assist Chugach Electric Association, Homer Electric Association and Matanuska Electric Association (the Cooperatives) in determining the preferred form of organization under which to own and operate the generation and transmission facilities which will supply power to their systems in the future. As part of the study, economic analyses were performed comparing the wholesale cost of power to the Cooperatives under three different long-range expansion scenarios. The objective was to determine a preferred power supply organizational type based on the results of the economic analysis and consideration of noneconomic factors. It is important to note that the focus of this study was the assessment of organizational alternatives. The economic analyses performed as part of this study involved many simplifying assumpsions. Thus, it is not appropriate to use the results of this study as a basis for comparing the relative economic merits of the alternative expansion scenarios studied. Such comparisons should be made only on the basis of the results of a detailed power supply study. It should also be emphasized that it was beyond the scope of this study to outline in detail the organizational structure, contractual arrangements and other aspects of the power supply organization type recommended for implementation by the Cooperatives. Rather, the focus of this study was on deriving information, based upon reasonable assumptions and analyses, which the Cooperatives could use in selecting an appropriate organization type to supply S-1 their future power needs. While it was necessary for study purposes to make specific assumptions concerning alternative power supply organization types, it was recognized that the actual detailed organizational arrangements and arms-length agreements pertaining to the organization type ultimately selected for implementation would need to be developed and negotiated by representatives of the three Cooperatives after a decision to go forward with that particular organization type has been made. Thus, the purpose of this study was to provide information which could be used by the Cooperatives to decide on a particular power supply organization type, but not to develop the detailed specifications for that organization. BACKGROUND Chugach, Homer and Matanuska Electric Associations are rural electric distribution cooperatives financed under’ the auspices of the Rural Electrification Administration (REA) established by the Rural Electrification Act of 1936. The Cooperatives supply electricity at retail to their members located in south central Alaska. Chugach is the largest of the three Cooperatives. Chugach owns and operates sufficient generation and transmission to supply not only most of its own needs, but also to supply most of the needs of Homer and Matanuska. The balance of the power required by the Cooperatives is purchased from the Alaska Power Administration or supplied from minor standby generation at Homer's Seldovia plant. Chugach sells power at wholesale to Homer under a contract signed on May 27, 1963 and to Matanuska under a similar contract signed on May 1, 1974. Both of these contracts provide for the sale of power and energy and also for the lease S-2 by Chugach of certain generation and transmission facilities owned by Homer and Matanuska. As discussed below, these contracts were amended in 1982. Although Chugach owns and operates substantial generation and transmission facilities, it must comply with all the requirements and restrictions imposed upon borrowers classified as "distribution borrowers" by the REA and the National Rural Utilities Cooperative Finance Corporation (CFC). One of the most significant requirements imposed by these organizations is that distribution cooperatives maintain a minimum Times Interest Earned Ratio (TIER) of 1.5. Generation and Transmission (G&T) Cooperatives, on the other hand, are required to maintain a minimum TIER ratio of only 1.0. The TIER relates a cooperative's margin (revenues less expenses) to its interest payments. Thus, a 1.5 TIER requirement means that a cooperative must earn margins equal to at least 50 percent of its net long-term interest expense to satisfy its loan contract commitments. A 1.0 TIER requirement means that a cooperative need not earn a margin at all. For a cooperative borrowing relatively large amounts of capital at high interest rates, the difference between maintaining a 1.5 and 1.0 TIER can be significant in terms of the impact on its member rates. The position of REA and CFC on TIER levels for distribution and G&T cooperatives can, perhaps, be summarized from the findings of the Report to Committee on Objectives and Planning of National Rural Utilities Cooperative Finance Corporation by the investment banking firm of Lehman Brothers Kuhn Loeb (LBKL) dated November 19, 1982. This was a major study of the future capital 8-3 requirements of the rural electric program and possible means by which these requirements can be met, with particular emphasis on financing alternatives to the REA's present lending programs. According to the LBKL Report: "It is a well-established and accepted principle in the rural electrification program that equity is accumulated at the distribution level. Likewise, distribution cooperative TIERs are maintained at levels which in most cases provide more than two times coverage of interest expense by net margins and patronage capital. On the other hand, the ‘all requirements’ power contract between G&Ts and their members mandate that G&Ts design rates which ‘are sufficient, but only sufficient’ to cover all costs, including debt expense and the establishment of ‘reasonable reserves’. Rating agencies have accepted the resulting minimal G&T TIER and DSC ratios, and negligible equity to asset ratios, only on the basis of this principle of credit strength at the distribution level. Their rating evaluations of G&Ts thus rely heavily on a composite credit evaluation of member systems." The primary impetus for this study was the financial difficulty which Chugach has experienced in recent years. Until a substantial retail rate increase was granted to Chugach by the Alaska Public Utilities Commission (APUC) in July, 1982, the retail rates of Chugach had not been sufficient to permit Chugach to maintain even a 1.0 TIER. A related problem is that the rate provisions of the wholesale power contracts with Homer and Matanuska were structured so that Chugach was not earning a 1.5 TIER on assets allocated for the generation and delivery of power to these two cooperatives. As a result of Chugach's financial difficulty, Homer and Matanuska agreed to amend their bipartite power supply agreements with Chugach by entering into a tripartite agreement with Chugach for a period not to extend beyond December 31, 1983. Under this agreement, Homer and Matanuska will pay for electric power and energy based on a TIER of 1.15 on Chugach's debt - ken wen associated with the Chugach generation and transmission facilities identified as being applicable for the generation and delivery of power to these two cooperatives. Chugach has also obtained agreements from REA and CFC to waive the 1.5 TIER requirement and to permit Chugach to maintain a minimum TIER of only 1.15 on its generation- and transmission-related loans until December 31, 1983. Because of the perceived economic benefits associated with a lower TIER; REA, CFC and the APUC have been urging Chugach to form a G&T cooperative. Homer and Matanuska also support the concept of forming a G&T in which they would be involved as members. While there has been considerable pressure from organizations outside of Chugach for the formation of a G&T, there has been concern at Chugach that the formation of a G&T would result in a loss of control over the substantial power supply facilities and relatively favorable natural gas contracts owned by Chugach. STUDY SCOPE AND APPROACH The study involved a review of the present power supply situation of the Cooperatives including the existing organizational structure, generation and transmission facilities, power sales contracts, and fuel supply contracts. Following this review, the advantages and disadvantages of alternative organization types which might be applied to the power supply situation of the Cooperatives were examined. On the basis of this examination, those organization types which appeared to be most feasible and applicable to the power supply situation of the Cooperatives were selected for further study. In conjunction with the review of organizational alternatives, a review of generation, purchase, and transmission alternatives for supplying power to the Cooperatives in the future was conducted. This review resulted in the development of three reconnaissance grade exploratory expansion plans which were used to compare the relative economic merits of the selected organizational alternatives. Three long-range expansion scenarios were represented by the exploratory expansion plans. These included one plan which assumed the development of the Susitna hydroelectric project by the Alaska Power Authority, one which assumed the long-range expansion of generation in the area would involve primarily gas-fired generation, and one plan which assumed the long-range expansion of generation in the area would involve primarily coal-fired generation. These three expansion scenarios were considered in order to assess the range of possible impacts which the scenarios might have on the various power supply organizational structures because the amount of capital investment required by the Cooperatives would vary significantly under the alternative scenarios. As previously emphasized, the power cost projections developed in this study for a particular power expansion scenario were not intended to provide a basis for comparison with the power cost projections of another scenario. This is due to the fact that power supply analyses performed in this study were limited and of a preliminary nature. Therefore, conclusions concerning the relative merits of various power supply expansion scenarios are not appropriate. For example, the results presented in this report are not a suitable basis for comparing the Susitna expansion scenario, for example, with the coal-based expansion scenario to determine which of these two alternative expansion scenarios might be more S-6 economical. Conclusions concerning the economic feasibility of power supply expansion alternatives should only be formulated from the results of a more thorough and complete power supply study. ALTERNATIVE POWER SUPPLY ORGANIZATIONS A number of alternative organization types which the Cooperatives might employ to provide their power supply in the future were reviewed in the study. These alternatives include continuation of the existing power supply arrangement or formation of a new organization. New organizations which might be formed include a G&T cooperative, a public power agency, a taxable utility or some possible combination (hybrid) of these organizations. In general, the membership or ownership of a new power supply organization was assumed to involve either Chugach alone or Chugach jointly with Homer and Matanuska. The new organization would supply power at wholesale to all three Cooperatives. After considering the relative advantages and disadvantages of the different organization tries, it was concluded that the alternatives meriting further study are a continuation of the existing arrangement and the formation of a G&T cooperative. The advantages and disadvantages these two organization types and the rationale for rejecting the others are summarized below. Existing Arrangement One possible option would be for Chugach to continue to operate under the present arrangement without a change in minimum TIER on G&T facilities (1.15 through 1983 and 1.5 thereafter). REA, CFC, the APUC, and others have criticized the current arrangement primarily because of the impact of the 1.5 8-7 minimum TIER on the wholesale power costs of Chugach and ultimately on the retail rates of the Cooperatives. While this alternative may be a desirable option from Chugach's perspective, it may not be a tenable one unless it can be shown that operation with a 1.5 minimum TIER will not significantly affect the wholesale power costs of the Cooperatives compared to other alternatives. The primary concern at Chugach is that the adoption of another form of organization may involve a transfer of assets and property rights to a new, as yet undefined, entity without adequate compensation and subsequently equitable controlling interest. It is also perceived that Chugach's role in the power supply decision-making process could be significantly diminished. From the perspective of Chugach, advantages of continuing with the current arrangement include: 1. Chugach would retain exclusive control over the generation and transmission facilities which it owns. 2. Chugach would continue to retain exclusive control over its existing fuel supply contracts. 3. Chugach would not lose any of its decision-making prerogatives concerning power supply matters. 4. Management resources and funds would not be diverted from the many other complex problems presently confronting Chugach. serene deem car eee ria oy From the perspective of all three Cooperatives, disadvantages associated with continuation of the current power supply organization in its present form include: 1. Wholesale revenue requirements would be determined on the basis of a 1.5 minimum TIER level after 1983. Although REA and CFC have relaxed the minimum TIER requirement to 1.15 through December 1983, it appears reasonable to assume that the relaxed TIER level will not be extended beyond 1983. The resumption of the standard 1.5 minimum TIER requirement in 1984 would result in increased wholesale power costs to the Cooperatives. 2. Continuation of the present arrangement would likely result in a weaker cooperative power supply organization than might be possible through the merging of the Cooperatives' resources. From the perspective of Chugach, continuation with the present arrangement would be contrary to the expressed wishes of REA, CFC and the APUC. Generation & Transmission Cooperative Under this alternative, a new generation and transmission cooperative would be formed. This cooperative could be formed either by Chugach alone or by Chugach jointly with Homer and Matanuska (joint G&T). Formation of a G&T by Chugach alone was assumed for purposes of this study to involve splitting Chugach into two separate entities with separate boards and accounting functions. All generation, transmission, and applicable general plant properties would be s-9 assigned to the new G&T organization and distribution-related properties would remain with the distribution entity. In the case of the formation of a joint G&T with Homer and Matanuska, it is assumed the generation, transmission, and power supply-related general plant properties of Chugach would be combined with the power supply-related properties of Homer and Matanuska (primarily transmission). It should be noted that the possibilities in forming a joint G&T organization are not necessarily limited to Chugach, Homer and Matanuska, especially once the planned Fairbanks-Anchorage Transmission Intertie project is constructed. The Anchorage-Fairbanks Transmission Intertie project consists of 171 miles of 345-kV transmission which will initially operate at 138 kV. The purpose of the line is to provide economy interchange and reserve capacity sharing between the Anchorage and Fairbanks load centers. It is planned to be in service by December 1984. The availability of this intertie could facilitate the formation of a joint G&T cooperative comprised of Golden Valley Electric Association (GVEA) and Chugach alone or GVEA and Chugach, Matanuska, and Homer. While the development of a joint G&T withh GVEA presents a very real possibility for the Cooperatives, the evaluation of this alternative was considered to be beyond the scope of this study and, therefore, it was not analyzed. In the case of creating a joint G&T including Chugach, Homer, and Matanuska, the actual details of how the facilities and property rights of the respective cooperatives would be allocated and appropriate compensation, if any, would need to be negotiated among the Cooperatives. For purposes of this study, however, it was assumed that formation of a joint G&T would involve dividing Chugach by S-10 -s pe i) transferring all generation and transmission facilities and other related assets and liabilities applicable to the wholesale power supply function to the new G&T. Also, any contractual arrangements applicable primarily to the wholesale power supply function would be assigned to the new G&T. The balance of the Chugach facilities, properties, and contracts would remain with Chugach and would form the basis for a distribution cooperative. Similarly, generation and transmission facilities and contracts applicable to the power supply function and owned by Homer and Matanuska would also be transferred to the new G&T. A Board of Directors would be elected, staff would be assigned, and the new G&T would begin to operate as an independent entity generating, purchasing and transmitting power for delivery at wholesale to the three distribution cooperatives. The new G&T cooperative would possess substantial resources and also major commitments from the first day of its operation. It can be envisioned, that at the outset, the G&T may be what is often referred to as a “paper G&T." However, because of its very substantial facilities and commitments, this organization would, in fact, be much more that just a "paper G&T." It would have its own Board of Directors, require its own staff, own and operate major power supply facilities, and be responsible for the delivery of power at wholesale to supply the needs of the customers of the three distribution cooperatives. Because the obligations and responsibilities of the G&T would be substantial, it could be expected to eventually grow into a full-fledged, separate power supply organization with facilities substantially independent of those of Chugach. However, initially the new G&I would need to depend heavily on the existing Chugach organization for administration and operation. It can be anticipated S-11 that new G&T would need to contract with Chugach for staff and logistic support during the early years of its operation. Among the advantages which the formation of a G&T cooperative can present to the Cooperatives are: 2. 4. Formation of a G&T organization would permit the Cooperatives to reduce their TIER on loans for G&T properties to a minimum of 1.0. Formation of a joint G&T would combine the resources of the Cooperatives into one power supply organization. This type of organization should be financially and politically stronger than Chugach alone. Formation of a joint G&T would provide a framework for the inclusion of additional distribution cooperatives in the future. Possible candidates are Copper Valley Electric Association and Golden Valley Electric Association which supply power to their members in the rural areas in or around Valdez and Fairbanks, respectively. However, the incorporation of these Cooperatives into a possible G&T organization would depend upon the development of the necessary transmission interties. From the perspective of Homer and Matanuska, the formation of a joint G&T would provide these Cooperatives with a greater measure of control and input to their power supply. $-12 - wie 6. Formation of a G&T (joint or Chugach alone) would enable Chugach to comply with the desires of REA, CFC, and the APUC. A G&T cooperative could be converted into a taxable entity to provide certain benefits associated with leasing which may be available to taxable entities (see discussion page III-15). There would also be some disadvantages associated with the formation of a new G&T cooperative. These include: Additional costs would be incurred in order to organize and start-up a separate G&T. These costs would be associated with establishing another Board of Directors, additional staffing, legal and consulting fees and possibly additional facilities. Additional costs would also be incurred in operating the new G&T as an on-going concern relative to the costs of performing G&T functions by the existing Chugach distribution cooperative. These costs would include annual expenses necessary to maintain a separate G&T Board of Directors, additional staffing and eventually additional facilities. The additional staffing would be necessary to perform G&T functions currently fulfilled by personnel who are also carrying out distribution activities. S-13 3. The new G&T may possibly be subject to APUC jurisdiction and, as_ such, the rates for power and energy sold to distribution members could be subject to regulatory control. The inherent nature of regulatory control encompasses a degree of lag in approval of rates, and as such it may prove difficult to obtain rates at the minimum TIER level. iit should be noted, however, that APUC jurisdiction over wholesale power transactions between the Cooperatives may come about even if a G&T is not formed. 4. It is possible that transfer of assets and related obligations to the new G&T would involve a debt to the distribution cooperatives, primarily Chugach, for their equity in these assets at date of transfer. It should also be noted that the Cooperatives’ lenders would have to approve the organization and structure of the G&T, the terms of wholesale power contracts, and the terms of any management agreement between the cooperatives and the G&T. To the extent the APUC may validly exercise jurisdiction over a new G&T, that agency may likewise have to approve the organization and structure of the G&T, the terms of wholesale power contracts, and the terms of any management agreement between the cooperatives and the G&T. It is obvious that there are a number of advantages and disadvantages to forming a joint G&T cooperative. The relative weight of the advantages and disadvantages depends upon whether one adopts the perspective of Chugach or the perspective of Homer and Matanuska. Chugach appears to have less to gain from S-14 wu tence fermen a) weseccee oa FE the formation of a G&T cooperative since it currently owns the majority of the generation and transmission facilities in the area and also owns and controls the favorable gas supply contracts for the Beluga Generating Plant. There is a significant "going concern" value which one can ascribe to the existing generation and transmission controlled by Chugach. Homer and Matanuska, on the other hand, would appear to have more to gain from the formation of a G&T since these cooperatives have no significant control or voice in power supply matters. All three Cooperatives, however, would benefit from a lower minimum TIER applied to generation and transmission facilities which the formation of a joint G&T cooperative would make possible and all three should also benefit from a stronger G&T organization. Perhaps, it is most important to recognize that the relative weight of any advantages and disadvantages will depend upon the nature of the G&T cooperative formed and the agreements reached by the Cooperatives with respect to the transfer of facilities and contracts. For example, concerns on the part of Chugach about the loss of control could be mitigated by weighting the number of board members of the G&T based upon the relative kilowatt hour sales or number of customers of the respective Cooperatives (see Appendix E for comparison of kilowatt-hour sales and numbers of customers for the Cooperatives). Alternatively, there might be provisions for weighted voting for certain key issues. Thus, there is considerable flexibility in how a new G&T Cooperative might be formed and, therefore, it would seem that if a mutually acceptable agreement can be signed by the parties, many of the concerns about the relative advantages and disadvantages of a G&T might be addressed to the satisfaction of all parties. S-15 One item of particular concern expressed by Chugach is the transfer of property rights of the existing natural gas contracts for the Beluga Plant. The concern is that formation of a G&T might reduce benefits derived from these contracts by the existing Chugach customers and transfer the lost benefits to Homer, Matanuska, and possibly others. Our review of the situation indicates that Homer and Matanuska are already sharing in the benefits of these gas contracts through their wholesale power agreements with Chugach. This is due to the fact that Homer and Matanuska are currently purchasing power based upon Chugach's average cost of production. Thus, relative to the formation of a G&T with Homer and Matanuska, the transfer of the gas contract property rights to a G&T should not immediately present any change in these benefits to the Chugach members. Also, it would be possible to place certain restrictions on the G&T formation agreement to provide assurances that the economic benefits presently derived from the gas contracts by Chugach and shared with the existing wholesale customers of Chugach will not be further diluted in the future. Another item of concern is that Chugach might have to share or give up a portion of its equity in power supply facilities. Concerns about equity could be accommodated with appropriate compensation, determined through negotiations, from the G&T to cooperatives having equity in the facilities transferred to the G&T. In fact, it does not appear that this should be a major stumbling block since the combined equity in power supply facilities appears to be relatively small (roughly $7.5 million) compared to the outstanding principal balance ($217 million) on G&T facilities (see Table IV-2). S-16 borers —— mm 4 4 ' | Current Arrangement With Split TIER The possibility that the current power supply arrangement might be perpetuated if Chugach can obtain approval from REA and CFC for a split minimum TIER (1.5 on distribution and 1.0 on generation and transmission) was not considered further because of the apparently low probability that such an arrangement might be approved (see letters from REA and CFC in Appendix D). Public Power Agency As indicated previously, there are a number of major disadvantages associated with the formation of a public power agency. Perhaps, the overriding issue involves the form which such an agency should take. There are a number of possibilities and each of these could require enabling legislation whose outcome, in terms of the type of organization permissible and the degree of control exercised by the Cooperatives or their members, would by no means be certain. Another potential problem is that it may be necessary to refinance the outstanding REA debt on facilities transferred to such an agency. This would most likely increase power supply costs to members since the cost of refinancing with tax-exempt bonds may be greater than Chugach's current weighted cost of debt on G&T assets. The problem is compounded by the fact that the agency would not qualify for tax-exempt financing with Chugach, Homer, and Matanuska as members unless the Cooperatives also changed their form of organization to gain eligibility for tax-exempt financing. Thus, the alternative of forming a public power agency is a far more complex, potentially costly, and likely time- consuming alternative than the others addressed. For these reasons, this organization type was not considered further in the study. S-17 Investor-Owned Utility This alternative was rejected from further consideration because its implementation would certainly increase power supply costs, be difficult to implement, and most likely be opposed by the membership. Taxable G&T Cooperative This alternative is really nothing more than a variant of the G&T Cooperative organization type. The ability to form a taxable Cooperative without incurring significant economic penalties is an advantage of a G&T form of organization. However, the economic benefits of a taxable G&T relative to the current arrangement or a tax-exempt G&T, if any, cannot readily be quantified. Thus, this alternative was dropped from further study. Hybrid Organization No doubt, the most nebulous of the alternative organization types addressed in this study is that of the hybrid organization which might combine any one of a variety of the features of the others. The reasons for rejecting this alternative are essentially the same as those for rejecting the other alternative types dropped from further consideration. A myriad of possibilities for hybrid organizations exist, and complications and disadvantages are readily identified. In the absence of a serious proposal for a _ specific hybrid organization, this alternative was dropped from further consideration. ECONOMIC ANALYSIS ASSUMPTIONS The economic evaluations of the study involved projecting wholesale power costs with the aid of a financial forecast computer program for each of the $-18 ~~ exploratory plans and alternative organizational types considered over the period 1983-2015. The economic evaluations assumed that the relevant power supply facilities consist of the existing generation and transmission facilities of Chugach, transmission facilities currently leased by Chugach from Homer and Matanuska, and future generation and transmission facilities which may be constructed to supply power to the Cooperatives. To provide a valid comparison, the facilities and capital investment in power supply facilities were assumed to be sneecialiy constant among the organizational alternatives evaluated under each exploratory expansion plan. Any differences identified were intended to reflect incremental differences which would result from the development of a particular organization type. Based upon the results of the economic evaluations and after taking into account various factors not readily quantified in an economic analysis, a preferred organizational alternative was identified. A preliminary plan for implementing this alternative was also developed. The assumptions of the economic analysis were based on information available at the time the exploratory expansion plans and financial forecast were developed. The hydroelectric expansion scenario assumes that long-term power supply expansion would be accomplished primarily with the Susitna Project. The gas- fired expansion scenario assumes all long-term power supply expansion would be met by participation in 200-MW natural gas-fired combined cycle units. The coal-fired expansion scenario assumes all long-term power supply expansion would be met by participation in 200-MW net coal-fired steam electric units. Cost estimates for the Susitna Project used in this study are based on Acres American's "Susitna Hydroelectric Project, Summary Report", March 1982 for the 8-19 Alaska Power Authority. A scenario involving partial funding for the project by the State of Alaska has been assumed in which the state would fund approximately 45 percent of the project and the remaining 55 percent would be funded through issuance of tax exempt bonds. The base cost estimate for this project developed by Acres American is $5.1 billion, in 1982 dollars. In estimating the total cost of power from the project, we have included interest during construction on funds assumed to be provided by the issuance of tax exempt bonds, escalated the total capital cost by 8 percent per year, and amortized the total capitalized cost over a 50-year period. Fixed and variable operation and maintenance expenses have also been estimated for this project. The Bradley Lake project is a hydroelectric project being pursued by the State of Alaska. Projected costs for this project were also estimated based on analyses and studies performed for the Alaska Power Administration. Again, it was assumed that the total capitalized cost of this project was financed 45 percent by the Alaska Power Authority and 55 percent using 10 percent tax exempt bonds. These costs are amortized over a 50-year period with fixed and variable operation and maintenance expenses also estimated for this project. Information concerning the capital cost of 200-MW gas-fired combined cycle units is based upon information provided in the "Natural Gas-Fired Combined Cycle Power Plant Alternatives for the Rail Belt Region of Alaska," dated June, 1982 by Battelle. Information concerning heat rates, availability, and fixed and variable operation and maintenance costs are generic estimates developed by Burns & McDonnell. S-20 wom — eo Generic cost estimates have been developed for a 200-MW net coal-fired steam electric generating unit as well. These cost estimates take into account the information available to us from studies which have been performed on the quality of coal near the Beluga Generating Station. Each power supply expansion plan was developed assuming short-term (1983-1989) incremental power supply requirements would be met by the installation of a 64-MW gas turbine in 1984 (Beluga 9), a 37-MW gas turbine in 1985 (Bernice Lake 5), the proposed Anchorage-Fairbanks intertie, and the purchase of approximately 68 megawatts of firm power from the Bradley Lake project beginning in 1988. Gas turbines were selected for the short-term expansion because of the short lead time required for installation and the current availability of Cook Inlet natural gas. The Bradley Lake project was selected due to the progress being made in its development and the apparent likelihood that the project will be constructed. The Final Environmental Impact Statement has been prepared by the U.S. Army Corps of Engineers and initial design work has commenced on the project. The three long-range expansion plans developed in this study are summarized in Table S-1. Transmission system improvements have been incorporated into this study based on the Cooperatives’ projected transmission improvements as outlined in Chugach's October 1982 financial forecast. Recommendations for these improvements were made in the "System Planning Report" for Chugach by Southern Engineering Company, dated May 1982. $-21 Table S-1 SUMMARY OF POWER SUPPLY EXPANSION SCENARIOS CAPACITY ADDITIONS (MW) Expansion Scenario 1984 1986 1986-1987 1988 1989.1992 1993 1994 1996-2000 2001 2002 2003-2007 2008 2009-2012 2013 2014-2016 Gas ect! 37cT? o e8n? o 0 o o joo cc® o o 200 cc® o 200CC8% 0 Coat eact! 37ct? 0 e8n? 0 0 o 0 too cs* o o 200 cs* o 200 cs* 0 Hydro eact! act? o osu? 0 sa0ut 165 4 ° 0 262107 0 0 o o 0 wo 1 N N pees 9. CT — Combustion Turbine B Bernice Lake 5. H — Hydroelectric Assumed Chugach allocation of Bradley Lake Hydroelectric project. 4 Assumed Chugach allocation of Watana portion of Susitna Hydroelectric project. 5 Assumed allocation of a 200 MW combined-cycle unit. 8 Assumed allocation of a 200 MW coal-fired unit. 7 Assumed Chugach allocation of Devil Canyon portion of Susitna Hydroelectric project. NOTE: All plans assume 51-MW are available to the cooperatives from the proposed Anchorage-Fairbanks intertie. CC — Combined Cycle CS — Coal Steam Turbine re. wer =m ea It was assumed that all future financing requirements of the Cooperatives would be met through Federal Financing Bank guaranteed REA loans at an annual interest rate of 11 percent. The term of these loans was assumed to be 35 years with a 7-year deferral of principal payments, resulting in a loan amortization period of 28 years. An escalation rate of 8 percent per year was used to project capital costs and annual operation and maintenance costs in this study. The following 1983 base prices and escalation rates (percent) were assumed for fuel prices: Escalation Fuel Price Rate (Percent) (Cents/MBtu) Cook Inlet Natural Gas (01d) 2a 21 North Slope Natural Gas 8.0 639 Beluga Coal 10.1 164 Enstar Natural Gas 9.8 118 Cook Inlet Natural Gas (New)! 8.0 232 ' snalysis assumed 150 cents/MBtu for 1983 only. Annual administrative and general expenses for new generation facilities were assumed to be equal to 40 percent of the projected annual fixed operation and maintenance expense for these facilities. Administrative and general expenses on existing plant were based on projections in Chugach's October 1982 Financial Forecast. For the plans in which a G&T is assumed to be formed, additional expenses have been added to reflect incremental consultant, attorney and auditor fees associated with forming a G&T, as well as, incremental expenses for labor and expenses required to start-up and operate an on-going G&T. S-23 A discount rate of 11 percent per year was used in computing the present value of the annual revenue requirements over the study period. This discount rate was by convention set equal to the assumed 11 percent interest rate for long- term loans. It was assumed that interest at a rate of 8 percent would be earned on the average balance of general cash funds. These interest earnings would be available to meet operating expenses and reduce revenues required from rate payers. It was also assumed that every reasonable effort would be made to keep the average cash balance below 8 percent of gross generation and transmission plant assets. It was assumed that surplus cash above 8 percent of plant assets would be invested in plant additions in lieu of borrowing or used to retire outstanding debt. When analyzing plans under the existing organizational arrangement, a TIER of 2.0 has been assumed for the years 1984 through 2015. When analyzing the plans assuming the formation of a G&T, a TIER of 1.2 was assumed for these years. All plans assumed a TIER of 1.15 for 1983 to reflect the terms of the amended power supply contracts Chugach has with Homer and Mantanuska. Capital credits generated with margins resulting from TIER levels in excess of 1.0 were assumed to be rotated (returned to the membership) every twenty years. Sensitivity analyses were performed assuming a 10-year capital credits rotation period. Capital credits assumed to be returned to members in a given year were credited against member revenue requirements in that year. $-24 o- ECONOMIC ANALYSIS OF POWER SUPPLY PLANS Tables S-2, S-3 and S-4 present the results of the economic analysis for the gas-fired, coal-fired, and hydroelectric long-range expansion plans, respectively, assuming a 20-year capital credits retirement period. These tables show projected annual revenue requirements in terms of millions of dollars and mills per kilowatt hour for the two organizational alternatives studied. The last three columns of each table show the amount by which the G&T projected member revenue requirements are above or below the projected member revenue requirements for the existing arrangement. It should be noted that the revenue requirements presented in these tables for any year have been reduced by the projected capital credits retirement. That is, capital credits assumed to be returned to members in a given year have been subtracted from projected revenues from member rates in that year to achieved the revenue requirements shown on these tables. Since capital. credits retirements would be greater under the existing alternative (due to a more rapid equity buildup because of the higher TIER), member rates would actually be relatively higher than suggested by the results in these tables for the existing arrangement as compared to the G&T cooperative for the years after 2002 (capital credits retirements are assumed to commence in 2003 under a 20-year rotation). As can be seen in Table S-2, for the gas-fired expansion scenario, revenue requirements from members under the G&T cooperative are projected to be 24.7 percent lower in 1984 and to decline steadily to only 3.1 percent lower in 1990 compared to those projected under the existing arrangement. By 1991, the advantage is projected to shift to the existing arrangement and it is not until $-25 Calendar Year 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 + 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Existing Arrangement Assuming 2.0 TIER ($ Million) 48.0 73.3 90.0 94.1 90.5 123.7 128.4 129.8 176.9 184.0 205.6 226.7 330.9 455.1 664.9 754.2 831.3 938.6 1,064.3 1,173.3 1,284.2 1,413.5 1,580.3 1,794.4 1,979.0 2,300.1 2,547.6 2,824.6 3,067.2 3,433.8 3,924.6 4,369.0 4,804.3 i Key Assumptions: Interest Rate on REA Guaranteed Funds: 11.0 percent Interest Earned on Cash Balance: 8.0 percent (Mills/kWh) 28.6 42.1 50.0 50.4 46.8 61.7 64.0 61.4 79.2 79.6 85.7 91.2 128.6 170.6 240.6 263.2 280.1 305.1 333.8 355.0 374.9 398.3 429.9 470.7 501.2 562.2 600.4 642.7 674.0 727.7 802.6 862.2 915.3 2 assumes 20-Year Capital Credits Rotation. Table S-2 COMPARISON OF PROJECTED MEMBER REVENUE REQUIREMENTS FOR GAS-FIRED EXPANSION PLAN? (LESS RETIRED CAPITAL CREDITS BEGINNING 2003) G&T Cooperative Assuming 1.2 TIER ($ Million) (Mills/kWh) 48.1 28.7 55:1 31.7 76.3 42.4 78.2 41.9 80.9 41.8 115.9 57.8 122.7 61.2 125.9 59.5 179.2 80.3 194.5 84.1 217.6 90.8 240.3 96.6 349.0 135.6 471.1 176.7 677.5 245.1 765.1 266.9 844.1 284.4 954.0 310.2 1,062.7 333.3 1,177.0 356.1 1,290.7 376.7 1,443.1 406.6 1,616.8 439.8 1,834.0 481.1 2,019.8 511.5 2,284.5 558.4 2,512.5 592.2 2,801.8 637.5 3,053.5 671.0 3,428.2 726.5 3,956.9 809.2 4,334.2 855.4 4,790.9 912.7 S$-26 ($ Million) 0.1 (18.2) (13.7) (15.9) (9.6) (7.8) (5.7) (3.9) 2.3 10.5 12.0 13.6 18.1 16.0 12.6 10.9 12.8 15.4 (1.6) 3.7 6.5 29.6 36.5 39.6 40.8 (15.6) (35.1) (22.8) (13.7) (5.6) 32.3 (34.8) (13.4) G&T Above (Below) Existing Arrangement (Mills/kWh) 0.1 (10.4) (7.6) (8.5) (5.0) (3.9) (2.8) (1.9) 1.1 4.5 5.1 5.4 7.0 6.1 4.5 3.7 4.3 5.1 (0.5) 11 1.8 8.3 9.9 10.4 10.3 (3.8) (8.2) (5.2) (3.0) (1.2) 6.6 (6.8) (2.6) (%) 0.3 (24.7) (15.2) (16.9) (10.7) (6.3) (4.4) (3.1) 1.4 5.7 6.0 5.9 5.4 3.6 1.9 1.4 1.5 17, (0.1) 0.3 0.5 2.1 2.3 2.2 2.1 (0.7) (1.4) (0.8) (0.4) (0.2) 0.8 (0.8) (0.3) 2008 under this scenario that the revenue requirements of the G&T are again projected to be lower for the gas-fired expansion plan. Also, capital credits retirements are assumed to commence in 2003 under the 20-year rotation schedule, shifting the advantage in terms of revenue requirements to the existing arrangement. Up through 2002, Tables S-2 through S-4 provide a comparison of projected revenue requirements through rates. Since the coal-fired expansion plan and gas-fired expansion plan used in this study are identical through the year 2000, Table S-2 and Table S-3 are identical for the years 1983-2000. In 2001, the relative revenue requirements of the G&T are again projected to be lower for the coal-fired expansion plan since a new coal plant is assumed to be placed in service that year. Table S-3 shows that after 2001, revenue requirements under the G&T are projected to be lower than those under the existing arrangement for all but four years during the period 2001-2015. This serves to illustrate that a major capital investment, as would be required for the development of a coal-fired plant, would substantially shift the advantage in terms of lower revenue requirements to the G&T for a number of years. It should also be noted that a load growth rate greater than the 3.4 percent annual peak demand growth rate assumed in this study would require new capacity to be brought on line earlier than assumed in the expansion plans used in this analysis. The resulting larger capital expenditures program would result in a greater revenue requirement advantage for the G&T than indicated in Tables S-2 and S-3. S-27 Calendar Yoor {8 Million) 1983 48.0 1984 73.3 1985 90.0 1986 94.1 1987 90.5 1988 123.7 1989 128.4 1990 129.8 1991 176.9 1992 184.0 1993 205.6 1994 226.7 1995 330.9 1996 455.1 1997 664.9 1998 754.2 1999 831.3 2000 938.6 2001 1,112.8 2002 1,219.0 2003 1,320.5 2004 1,442.0 2005 1,599.0 2006 1,805.5 2007 1,979.2 2008 2,395.2 2009 2,658.0 2010 2,903.8 2011 3,113.1 2012 3,448.7 2013 4,045.2 2014 4,520.0 2015 4,886.0 1 Key Assumptions: Existing Arrangement Assuming 2.0 TIER (Mills/kWh) 28.6 42.1 50.0 50.4 46.8 61.7 64.0 61.4 79.2 79.6 85.7 91.2 128.6 170.6 240.6 263.2 280.1 305.1 349.1 368.8 385.4 406.3 434.9 473.6 501.2 585.5 626.4 660.7 684.0 730.8 827.2 892.1 930.9 Table S-3 COMPARISON OF PROJECTED MEMBER REVENUE REQUIREMENTS FOR COAL-FIRED EXPANSION PLAN! (LESS RETIRED CAPITAL CREDITS BEGINNING 20037) Interest Rate on REA Guaranteed Funds: 11.0 percent 2 Interest Earned on Cash Balance: 8.0 percent Assumes 20-Year Capital Credits Rotation. G&T Cooperative G&T Above (Below) Assuming 1.2 TIER Existing Arrangement {¢.Milion) | —_(Mille/kWh)_ {8 Milflon) IMiis/eWh) (90) 48.1 28.7 0.1 0.1 0.3 55.1 31.7 (18.2) (10.4) (24.7) 76.3 42.4 (13.7) (7.6) (15.2) 78.2 41.9 (15.9) (8.5) (16.9) 80.9 41.8 (9.6) (5.0) (10.7) 115.9 57.8 (7.8) (3.9) (6.3) 122.7 61.2 (5.7) (2.8) (4.4) 125.9 59.5 (3.9) (1.9) (3.1) 179.2 80.3 2.3 tel) 1.4 194.5 84.1 10.5 4.5 5.7 217.6 90.8 12.0 5.1 6.0 240.3 96.6 13.6 5.4 5.9 349.0 135.6 18.1 7.0 5.4 471.1 176.7 16.0 6.1 3.6 677.5 245.1 12.6 4.5 1.9 765.1 266.9 10.9 3.7 1.4 844.1 284.4 12.8 4.3 1.5 954.0 310.2 15.4 5.1 ees 1,077.7 338.0 (35.1) (11.1) (3.2) 1,189.7 360.0 (29.3) (8.8) (2.4) 1,297.0 378.6 (23.5) (6.8) (1.8) 1,444.7 407.1 (2.7) 0.8 0.2 1,611.4 438.4 12.4 3.5 0.8 1,824.2 478.6 18.7 5.0 tel 2,002.2 507.0 23.0 5.8 1.2 2,315.9 566.1 (79.3) (19.4) (3.3) 2,542.3 599.2 (115.7) (27.2) (4.3) 2,810.9 639.6 (92.9) (21.1) (3.2) 3,039.8 668.0 (73.3) (16.0) (2.3) 3,394.1 719.2 (54.6) (11.6) (1.6) 4,021.7 822.4 (23.5) (4.8) (0.6) 4,390.8 866.6 (129.2) (25.5) (2.9) 4,796.9 913.9 (89.1) (17.0) (1.8) S-28 ae a wees wien el wag 4 nme ‘ — 9 4 3 em i The results shown for the hydroelectric expansion plan in Table S-4 are the same as those for both the gas-fired and coal-fired expansion plans through the year 1992 since the expansion plans are identical up until that time. After 1992, revenue requirements from members under the G&T are shown to range from 5.4 percent higher in 2004 to 1.5 percent higher in 1998 than projected revenue requirements under the existing arrangement. Table S-5 presents a comparison of present value of member revenue requirements for the long-range expansion scenarios. The results presented in this table are for both a 20-year capital credits rotation and a 10-year capital credits rotation. Present values have been shown for the time period 1983-2000 as well as for the time period 1983-2015. On a present value basis, over the 1983-2015 study period assuming a 20-year capital credits rotation, the gas-fired expansion plan shows a 0.3 percent advantage for the G&I cooperative. The hydroelectric expansion plan shows a 0.9 percent advantage for the existing arrangement while the coal-fired expansion plan shows a 1.5 percent advantage for the G&T cooperative. Decreasing the capital credits rotation to 10 years decreases the present value advantage of the G&T cooperative. The relatively small percentage differences shown in Table S-5 are to be expected since a cooperative is consumer owned and all equity eventually accrues to the membership, regardless of TIER assumption all other factors being equal. As might be expected, the more capital intensive the expansion scenario, the greater the advantage for the G&T cooperative. As shown in Table S-5 for the study period 1983-2015, the present value advantage of the G&T for the capital intensive coal-fired expansion scenario is projected to be either $63.7 million 8-29 Calendar Year 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Existing Arrangement Assuming 2.0 TIER ($ Million) (Milis/kWh) Table S-4 COMPARISON OF PROJECTED MEMBER REVENUE REQUIREMENTS FOR HYDROELECTRIC EXPANSION PLAN! (LESS RETIRED CAPITAL CREDITS BEGINNING 20037) G&T Above (Below) 48.0 73.3 90.0 94.1 90.5 123.7 128.4 129.8 176.9 184.0 405.3 524.2 553.8 596.8 683.1 730.7 760.7 814.7 878.1 868.7 908.7 905.2 1,013.6 1,155.2 1,249.0 1,261.4 1,436.4 1,550.5 1,707.8 2,012.3 2,109.2 2,445.5 2,877.5 i Key Assumptions: Interest Rate on REA Guaranteed Funds: 11.0 percent Interest Earned on Cash Balance: 8.0 percent 28.6 42.1 50.0 50.4 46.8 61.7 64.0 61.4 79.2 79.6 169.0 210.8 215.2 223.8 247.1 254.9 256.3 264.9 275.4 262.9 265.2 255.1 275.8 303.1 316.3 308.3 338.5 352.8 375.3 426.4 431.3 482.6 548.2 2 Assumes 20-Year Capital Credits Rotation. G&T Cooperative Assuming 1.2 TIER ($ Million) (Mills/kWh) 48.1 28.7 55.1 31.7 76.3 42.4 78.2 41.9 80.9 41.8 115.9 57.8 122.7 61.2 125.9 59.5 179.2 80.3 194.5 84.1 417.3 174.0 537.9 216.3 571.9 222.2 612.9 229.8 695.6 251.7 741.5 258.7 773.6 260.7 830.1 269.9 900.5 282.5 895.8 271.1 927.0 270.6 954.7 269.0 1,060.9 288.6 1,210.5 317.6 1,306.8 330.9 1,305.6 319.2 1,495.1 352.4 1,600.7 364.2 1,767.2 388.3 2,057.7 436.1 2,158.7 441.5 ~ 2,491.5 491.7 2,941.3 560.4 S-30 Existing Arrangement ($ Million) (Mills/kWh) (%) 0.1 0.1 0.3 (18.2) (10.4) (24.7) (13.7) (7.6) (15.2) (15.9) (8.5) (16.9) (9.6) (5.0) (10.7) (7.8) (3.9) (6.3) (5.7) (2.8) (4.4) (3.9) (1.9) (3.1) 2.3 11 1.4 10.5 4.5 5.7 12.0 5.0 3.0 13.7 5.5 2.6 18.1 7.0 3.3 16.1 6.0 2.7 12.5 4.6 1.9 10.8 3.8 1.5 12.9 4.4 17 15.4 5.0 1.9 22.4 eel 2.6 27.1 8.2 3.1 18.3 5.4 2.0 49.5 13.9 5.4 47.3 12.8 4.6 55.3 14.5 4.8 57.8 14.6 4.6 44.2 10.9 3.5 58.7 13.9 4.1 50.2 11.4 3.2 59.4 13.0 3.5 45.4 9.7 2.3 49.5 10.2 2.4 46.0 9.1 19 63.8 12.2 2.2 Té=-s ~_— os —— —os oo Table S-5 COMPARISON OF PRESENT VALUE OF MEMBER REVENUE REQUIREMENTS FOR LONG RANGE EXPANSION SCENARIOS! (1983S) 20 YEAR CAPITAL CREDITS ROTATION Present Value 1983-2000 Present Value 1983-2015 G&T Above (Below) G&T Above (Below) Existing Existing Arra t Existing Existing Arrangement Expansion Arrangement G&T Arrangement G&T Plan ($ Million) ($ Million) ($ Million) ; (%) ($ Million) ($ Million) ($ Million) (%) Gas 1,652.5 1,630.9 (21.6) (1.3) 4,129.8 4,116.8 (13.0) (0.3) Coal 1,652.5 1,630.9 (21.6) (1.3) 4,190.4 4,126.7 (63.7) (1.5) Hydro? 1,882.5 1,860.8 (21.7) (1.2) 3,419.6 3,449.2 29.6 0.9 10 YEAR CAPITAL CREDITS ROTATION Present Value 1983-2000 Present Value 1983-2015 G&T Above (Below) 3 G&T Above (Below) Existing Existing Arrangement Existing Exi Arr t Expansion Arrangement G&T Arrangement G&T Plan ($ Million) ($ Million) ($ Million) (%) ($ Million) ($ Million) ($ Million) 4%) Gas 1,614.0 1,620.7 6.7 0.4 4,099.3 4,107.9 8.6 0.2 Coal 1,614.0 1,620.7 6.7 0.4 4,150.6 4,115.8 (34.8) (0.8) Hydro? 1,844.0 1,850.6 6.6 0.4 3,396.4 3,442.2 45.8 1.3 A Assumes 11.0 percent discount rate. 2 Assumes development of Susitna project funded in part (45 percent) with State of Alaska grants. (1.5 percent) for the 20-year capital credit rotation assumption or $34.8 million (0.8 percent) for the 10-year capital credit rotation assumption. In comparison, the existing arrangement has a $29.6 million (0.9 percent) advantage under the hydroelectric expansion scenario assuming a 20-year capital credits rotation and a $45.8 million (1.3 percent) advantage assuming a 10-year capital credits rotation. As has been pointed out, the hydroelectric expansion scenario assumes capital will be invested by the State of Alaska instead of by the cooperatives. This confirms that the greater the load growth and the greater the amount of power supply facilities investment by the Cooperatives, the greater the short-term and long-term advantage of the G&T. In summary, the economic analysis results indicate that the formation of a G&T cooperative will result in significantly lower member rates in the short run, and the greater the required power supply facilities investment in the short run, the longer the period and the greater the magnitude of this short-run advantage. In the long run, the two organizational alternatives would be approximately equivalent in terms of the present value of member revenue requirements if only modest investment in additional power supply facilities is required of the Cooperatives. More capital intensive expansion plans will more strongly favor the G&T cooperative on a present value basis. In fact, the greater the required power supply facilities investment and the longer the period of capital credits retirement, the greater the economic advantage of the G&T. Under the existing arrangement members would pay significantly higher rates up front, building up equity which would eventually be returned to them in the form of capital credits. The Cooperatives would, in effect, be borrowing 8-32 ad = —_ ’ much more money from their members through higher rates under the existing arrangement than under the G&T. CONCLUSIONS AND RECOMMENDATIONS Although a number of alternative organization types might be implemented to supply the power requirements of the Cooperatives in the future, the results of our study suggest that the formation of a G&T cooperative is the most viable alternative to continuation with the existing power supply. The principal advantages of a G&T cooperative are that this form of organization: 1. Represents a logical extension of the current form of organization (rural electric cooperative) supplying the needs of the members of the cooperatives. 2. Would not require enabling or any other form of legislation. 3. Could be formed by the cooperatives themselves without loss of control or sharing of control over their power supply with other entities. 4. Would be consistent with the desires of REA, CFC, and the APUC. 5. Would permit the Cooperatives to maintain a minimum 1.0 TIER on generation and transmission facilities, thereby significantly reducing member rates, especially in the short run. S-33 6. Could be structured to alleviate concern about the relative control of facilities and fuel supply contracts. 7. Could be expanded to add new member cooperatives. 8. Could become a taxable entity without significant tax penalties since G&Ts are required to maintain only a 1.0 TIER. An important point to consider in contemplating the results of the economic analysis is that the expansion plans evaluated assumed a constant annual load growth rate of 3.43 percent per year over the period 1983-2015. Preliminary results of the Power Requirements Study we are currently performing for Chugach indicate that this load growth rate may well be conservative in that loads are likely to grow at a significantly higher rate over the next decade. As a result, it is likely that the capacity expansion plans used in the economic evaluations of this study are conservatively low in their assumptions concerning the amount of investment in power supply facilities which may be required of the Cooperatives during the next 10 years. Thus, it is likely that the short-run impact of a G&T on member revenue requirements will be greater than indicated by the results of our analyses. In summary, the economic analyses results indicate that the formation of a Gé&T cooperative will result in significantly lower member rates in the short run, and the greater the required power supply facilities investment in the short run, the longer the period and the greater the magnitude of this short-run S-34 ae ae nay ons oo] ~ vase id advantage. In the long run, the two organizational alternatives would be approximately equivalent in terms of present value of member revenue requirements with the capital intensive expansion plans favoring the Gé&T cooperative. The greater the required power supply facilities investment and the longer the period of capital credits retirement, the more the present value advantage would shift to the G&T. In other words, under the existing arrangement members would pay significantly higher rates up front, building up equity which would eventually be returned to them in the form of capital credits. The coopertives would, in effect, be borrowing much more money from their members through higher rates under the existing arrangement than under the Gat. Assuming the Cooperatives would prefer to maintain substantially lower member rates in the short term, the results of our study indicate it would be economically preferable to form a G&T cooperative rather than continue with the present power supply situation. There are, of course, many factors which come into play and many uncertainties involved in a decision of this nature. After weighing and considering the results of our economic analyses and the other information available to us concerning the power supply situation of the Cooperatives, it is our opinion that a G&T is the preferred power supply organization type. Formation of a G&T cooperative would lower member rates and revenue requirements in the short run; be consistent with the express desires of CFC, REA, and the APUC; would not require enabling legislation; would be a logical extension of the current form of organization (rural electric cooperative); could be expanded to add new member systems; and would provide a more flexible organization to deal with the complex and dynamic power supply S-35 environment of South Central Alaska. There is also considerable precedent for the formation of a G&T cooperative since this is the form of organization being utilized by virtually all other rural electric cooperatives in the United States that have pursued major power supply programs. Also supporting this conclusion are the preliminary results of the Power Supply Planning Study which we are performing for Chugach. The results of this study indicate a much greater capital investment requirement for power supply facilities over the next decade than projected for purposes of developing the results of this study. This difference is primarily due to the higher load growth rate being used in the Power Supply Planning Study. For these reasons, we recommend the formation of a G&T cooperative. The formation of a G&T cooperative, however, will not be easy if this is the course selected by the Cooperatives. A number of important decisions and major commitments must be made by all concerned if such an organization is to be formed. Perhaps, the most important initial decision would involve a decision by Chugach to either form a G&T alone or a joint G&T with Homer and Matanuska and/or possibly GVEA. The formation of a G&T by Chugach alone could no doubt be accomplished more quickly because only one party (Chugach) would be involved. Forming a joint G&T would be complicated by the need to gain additional approvals and to negotiate and come to a mutual agreement among the parties on various aspects of the G&T's structure. From the perspective of Chugach, there are also a number of significant concerns which would need to be addressed if a joint G&T is to be formed. S-36 eens ” = For Chugach, a disadvantage associated with the formation of a joint G&T is that Chugach would lose exclusive control and ownership of its power supply facilities. Related concerns are that the members of Chugach might lose the benefit of existing favorable fuel contracts and have their vested equity in power supply facilities diluted. The results of our investigation and experience suggest these concerns can be resolved to the mutual satisfaction of all parties. For example, concerns about relative control of decision making might be accommodated through some form of weighted voting on key issues. The issue of existing equity in power supply facilities could be resolved by appropriate compensation from the G&T. In fact, the figures we have developed indicate that the combined amount of equity in power supply facilities of the Cooperatives is relatively small (roughly $7.5 million) compared to the outstanding loan principle balance (about $217 million) on G&T facilities. Regarding the fuel contracts, the Cooperatives already share the benefits of these contracts under the existing power sales agreements. A valid concern of Chugach would be that these benefits not be diluted in the future. It would seem that appropriate arrangements to mitigate this concern, such as weighted voting, could be negotiated during the G&T formation process. Thus, we believe that the major apparent obstacles to the formation of a joint G&T can be overcome. At the same time, we believe there are significant advantages to be gained by the Cooperatives from the formation of a joint G&T cooperative. For Homer and Matanuska, an important benefit of a joint G&T is that it would provide them (and their consumers) with a voice in power supply matters. For all three cooperatives, the most important benefit may be creation of a stronger power S-37 supply organization, one with the clout and resources to operate successfully in the highly dynamic environment of South Central Alaska. The importance of a strong G&T power supply organization dedicated to reliably supplying the power needs of its member cooperatives at the lowest possible cost cannot be overemphasized. Also, a joint G&T is the form of organization preferred by REA. For these reasons, we consider a joint G&T to be the preferred form of power supply organization for the Cooperatives. Because of the economic and other benefits to be derived from the formation of a G&T and the expiration at the end of 1983 of Chugach's agreement with REA and CFC permitting a 1.15 TIER on G&T properties, we recommend that the necessary steps leading to the formation of a G&T cooperative be initiated as soon as possible. The formation of an operating G&T, especially a joint G&T, is a complex process as discussed in Part VII of our report. The complexity of forming a G&T can be expected to be compounded by the many other demands on the time of the boards and staffs of the Cooperatives, the need to obtain member approval, and the need to negotiate mutually acceptable arrangements if a joint G&T is established. It should also be realized that a G&T cooperative would have to depend heavily on the existing Chugach organization and would probably have to contract with Chugach for staff and logistic support during the initial years following its formation. At the same time it is important to recognize that a new G&T would be much more than a paper organization in that it would own and control substantial power supply resources, have a sizeable staff, and have major contractual obligations. 8-38 oro a a rp —4 It should also be noted that the formation of a G&T is likely to result in significant additional expense resulting from some duplication of staff and facilities. We have estimated for purposes of our analyses an eventual incremental cost of $2.0 million per year to operate a separate G&T compared to continuation with the present organization. While this is a significant additional cost, we believe that savings from increased efficiencies which should result from the operation of an organization dedicated exclusively to power supply will substantially offset this additional expense. However, because such savings are difficult to reliably quantify, we have included no allowance for savings from any increased organizational efficiency possible through the formation of a G&T in our study. We would also like to mention that our study assumed that financing for power supply facilities would continue to be available to the Cooperatives under the REA guaranteed loan program. Obviously, there is no assurance that funds under this program will continue to be available to the Cooperatives in the future, and the Cooperatives may be forced at some future point in time to seek other sources of financing. On the other hand, we believe the maintenance of the status quo regarding the Cooperative's source of financing to be a reasonable assumption because any other assumption would be much more speculative in view of the unpredictability of future actions concerning such matters by the federal government. At the same time, we are of the opinion that a strong G&T Cooperative would facilitate the direct entry of the Cooperatives into the private capital markets if this should ever become necessary. This view appears to be supported by the following conclusion of the LBKL Study: 8-39 "G&T systems have the potential for expanding their access to private capital, but within the context of a strong continuing REA guarantee program. The Committee on Objectives and Planning projects a total of $49.3 billion of capital commitments for construction programs through 1990. In our judgment, even the fullest possible exploitation of available private financing alternatives would fall short of meeting these requirements. It is particularly important to stress that even the perception of substantially diminishing REA support would limit the full utilization of available private market alternatives--that is to say, that access to the private market will be maximized if a strong on-going REA financial and administrative commitment is assured. Given this assurance, we believe that G&T systems have several alternatives for expanding their access to private capital.” G&T IMPLEMENTATION Establishment of a G&T cooperative, if decision is made to form such an organization, would require the interaction and cooperation of many entities. Specific steps which need to be accomplished prior to and during the formation stage of establishing a G&T cooperative are outlined below. This list of activities is not necessarily intended to be complete or to represent a priority listing. In fact, many of these activities could be accomplished concurrently. For purposes of consistency, this list assumes the formation of a joint G&T cooperative. Pre-G&T Formation Activities 1. Affirmative resolution and commitment by each of the Cooperatives' boards to study G&T formation. 2. Appointment of G&T Coordinating Committee with representatives from each cooperative. S-40 10. 1. Selection by Coordinating Committee of a chairman and other persons to review legal and engineering aspects and affects on employees, members of the public, rates and regulations, operating policies and practices, power supply, capital structure and financial outlook. Coordination meetings between the Coordinating Committee and cooperative boards. Dissemination of progress reports to employees, members and the public. Preparation of G&T formation agreement. Approval of G&T formation agreement by boards of directors. Approval of G&T formation agreement by general membership. Approval of G&T formation agreement by REA and CFC. Appointment of general manager to direct new G&T (see REA Bulletin 109-4). Formation of new G&T board of directors. s-41 12. 13. 14. 15. 16. 17. 18. 19. Appointment of transition staff to develop new G&T. Development of new G&T organizational structure and organizational outline. Drafting of G&T cooperative bylaws (see REA Bulletin 101-5). Drafting of articles of incorporation and filing of same with state of Alaska. Filing of application for tax exemption with district director of the Internal Revenue Service. Selection of corporate attorney (see REA Bulletin 100-1). Review of existing contractual agreements between Chugach and others including: a. Fuel contracts. be Purchase contracts. c. Interconnection agreements Development of new power sales contracts with City of Seward, Homer, Matanuska and newly formed Chugach distribution cooperative (approval by new G&T cooperative board of directors, REA, APUC). S-42 r eon 20. 21. Development of separate accounting system and staff for G&T operations. Initiation of separate billing procedures including Chugach distribution cooperative. Post G&T Formation Activities to wholesale Obtain outside accountant for independent audit (CPA). customers Establish a new employee benefits program for G&T employees including: Ae be Ce d. Life insurance. Hospital and surgical coverage. Employee income protection. Retirement plan. Develop safety program (see REA Bulletin 168-7) including: Rules and regulations. Policy. Job training program. Enforcement program. Safety accreditation program. Accident reporting program. $-43 10. 11. 12. Develop self-training program. Develop member services program. Prepare operating budgets. Establish G&T cooperative newsletter. Hold initial annual meeting. Prepare first annual report to members (see REA Bulletin 101-4). Review insurance policies to accommodate separation of G&T properties into new corporation. Develop public and employee relations program. Complete transfer of production and transmission personnel to of new G&T cooperative. S-44 umbrella worn — ~ at r i rt L 13. Separate responsibilities of administrative personnel of Chugach and G&T r into separate G&T and distribution functions. b 14. Perform cost-of-service study and rate design work. o—- 4 eee eH —_ om am $-45 ~ PART I—INTRODUCTION tr 1 s a ae 3 ’ y ' 1 ; ee ae PART I INTRODUCTION This document is the final report on a study of alternative organization types which Chugach Electric Association, Homer Electric Association and Matanuska Electric Association (the Cooperatives) might adopt to supply their collective power requirements in the future. This Part summarizes the purpose for performing the study, provides some background on the Cooperatives and the reasons for performing the study, and describes the study approach and scope. PURPOSE The purpose of this study was to assist the Cooperatives in determining the preferred form of organization under which to own and operate the generation and transmission facilities which will supply power to their systems in the future. As part of the study, economic analyses were performed to estimate the wholesale cost of power to the Cooperatives under alternative organizational types. A preferred power supply organizational type for the Cooperatives was recommended based on the results of the economic analyses and consideration of noneconomic factors. It should also be emphasized that it was beyond the scope of this study to develop for the Cooperatives the details of the organizational structure, contractual arrangements and other aspects of the power supply organization type recommended for implementation. Rather, the focus of this study was on deriving information, based upon reasonable assumptions and analyses, which the Cooperatives could use in selecting an appropriate organization type to supply I-1 their future power needs. While it was necessary for study purposes to make specific assumptions concerning alternative power supply organization types, it was recognized that the actual detailed organizational arrangements and arms-length agreements pertaining to the organization type ultimately selected for implementation would need to be developed and negotiated by representatives of the three Cooperatives after a decision to go forward with that particular organization type has been made. BACKGROUND Chugach, Homer and Matanuska Electric Associations are rural electric distribution cooperatives financed under’ the auspices of the Rural Electrification Administration (REA) established by the Rural Electrification Act of 1936. The Cooperatives supply electricity at retail to their members located in south-central Alaska. Chugach is the largest of the three Cooperatives. Chugach owns and operates sufficient generation and transmission to supply not only most of its own needs, but also to supply most of the needs of Homer and Matanuska. The balance of the power required by the Cooperatives is purchased from the Alaska Power Administration or supplied from minor standby generation at Homer's Seldovia Plant. Chugach sells power at wholesale to Homer under a contract signed on May 27, 1963 and to Matanuska under a similar contract signed on May 1, 1974. Both of these contracts provide for the sale of power and energy and also for the lease by Chugach of certain generation and transmission facilities owned by Homer and Matanuska. As discussed below, these contracts were amended in 1982. I-2 err screw enter wen emans oe eee at Although about 80 percent of Chugach's current plant investment is in generation and transmission facilities, Chugach must comply with all the requirements and restrictions imposed upon borrowers classified as "distribution borrowers" by the REA and the National Rural Utilities Cooperative Finance Corporation (CFC). One of the most significant requirements imposed by these organizations is that distribution cooperatives maintain a minimum Times Interest Earned Ratio (TIER) of 1.5. Generation and Transmission (G&T) Cooperatives, on the other hand, are required to maintain a minimum TIER ratio of only 1.0. The sources of Chugach's long-term financing are primarily REA, CFC, and the Federal Financing Bank (FFB). At the end of 1982, the total outstanding long- term debt to these organizations for all Chugach properties (generation, transmission, and distribution) was approximately as follows: Chugach Long-Term Debt Summary (Estimated End of 1982) Outstanding Loan Balance Percent Organization ($ Million) of Total REA (2% and 5%) $156 52% CFC 14 3% FFB 133 44% Other ili 1% Totals $301 100% As can be seen, the major sources of long-term financing for Chugach are REA and FFB. REA funds are made available primarily to distribution cooperatives through REA's Revolving Fund program. Funding from REA is generally supplemented by distribution cooperatives, and to some extent G&T cooperatives, with CFC financing. CFC obtains its funds by issuing bonds in the private capital markets. To make its bonds attractive to investors at favorable rates, CFC requires that its distribution cooperative members maintain minimum TIER ratios of 1.5. Financing for major generation and transmission projects, on the other hand, is accomplished primarily through long-term guaranteed loans from the Federal Financing Bank which obtains its funds by issuing U.S. Treasury Bonds in the open market. Since these bonds carry the full faith and credit of the U.S. government, they can be issued at favorable rates with the requirement that only a 1.0 TIER level be maintained by borrowers. Since the bulk of funding for G&T cooperatives is derived from this source, REA and CFC permit G&T cooperatives to maintain a minimum TIER level of only 1.0. Another reason for permitting G&T Cooperatives to maintain lower TIER levels is to avoid excessive buildup of equity in G&T organizations. Apparently, REA and CFC consider it sufficient to build up equity only in distribution organizations since the financial stability of the G&T organization is insured through its long-term power supply contracts with its distribution cooperative members. The TIER relates a cooperative's margin (revenues less expenses) to its interest payments. A 1.5 TIER requirement means that a cooperative must earn margins equal to at least 50 percent of its long-term interest expense to satisfy its loan contract commitments. A 1.0 TIER requirement means that a cooperative need not earn a margin at all. For a cooperative borrowing relatively large amounts of capital at high interest rates, the difference between maintaining a 1.5 and 1.0 minimum TIER can be significant in terms of the impact on its member rates. The position of REA and CFC on TIER levels for distribution and G&T cooperatives can, perhaps, be summarized from the findings of the Report to Committee on I-4 Objectives and Planning of National Rural Utilities Cooperative Finance Corporation by the investment bonding firm of Lehman Brothers Kuhn Loeb (LBKL) 5 dated November 19, 1982. This was a major study of the future capital 7 requirements of the rural electric program and possible means by which these requirements can be met, with particular emphasis on financing alternatives to t the REA's present lending programs. According to the LBKL Report: ' "It is a well-established and accepted principle in the rural electriciation program that equity is accumulated at the distribution level. Likewise, distribution cooperative TIERs are maintained at levels which in most cases provide more than two times coverage of interest expense by net margins and patronage capital. On the other i hand, the ‘all requirements’ power contract between G&Ts and their members mandate that G&Ts design rates which ‘are sufficient, but only { sufficient’ to cover all costs, including debt expense and the establishment of ‘reasonable reserves'. Rating agencies have accepted the resulting minimal G&T TIER and DSC ratios, and negligible equity ' to asset ratios, only on the basis of this principle of credit | strength at the distribution level. Their rating evaluations of G&Ts thus rely heavily on a composite credit evaluation of member systems." It should be noted that these are minimum TIER requirements. In order to ensure : that these minimum TIER levels are maintained, it is necessary for cooperatives to strive for higher average TIER levels in their operations. Thus, member rates must be designed to provide revenues resulting in average TIER levels which exceed the minimum requirements. The primary impetus for this study was the financial difficulty which Chugach has experienced in recent years. Until a substantial retail rate increase was granted to Chugach by the Alaska Public Utilities Commission (APUC) in July, 1982, the retail rates of Chugach had not been sufficient to permit Chugach to maintain even a 1.0 TIER. The rate increase was granted in the form of an APUC Bench Order as an interim, but refundable, rate increase. The same I-5 order also directed Chugach to "immediately begin to take whatever steps are necessary to establish a separate G&T cooperative." The directive also required that Chugach provide monthly progress reports to the APUC and it was indicated that any umnecessary delay in establishing the new G&T could result in a reduction in the allowed rate increase. Also contributing to Chugach's financial difficulties were the rate provisions of the bipartite wholesale power contracts between Chugach and Homer and Chugach and Matanuska. These were structured so that Chugach was not earning a 1.5 TIER on assets allocated for the generation and delivery of power to these two cooperatives. On April 20, 1982, the Cooperatives amended their bipartite power supply agreements by entering into a tripartite agreement which expires on December 31, 1983. Under this tripartite agreement, Homer and Matanuska pay for electric power and energy based on a TIER of 1.15 on Chugach's debt associated with generation and transmission facilities applicable to the generation and delivery of power to these two cooperatives. In conjunction with the amendment of the wholesale contracts with Homer and Matanuska, REA and CFC agreed on May 27, 1982 to permit Chugach to maintain a minimum TIER of only 1.15 on its generation and transmission properties. Chugach must continue to maintain a TIER of at least 1.5 on its distribution properties. This agreement also expires on December 31, 1983. one} ea Because of the perceived economic benefits associated with a lower TIER; REA, CFC and the APUC have been urging Chugach to form a G&T cooperative. Homer and Matanuska have also supported the concept of forming a G&T in which they would be involved as members. However, while there has been considerable pressure from organizations outside of Chugach for the formation of a G&T, there has been concern at Chugach that the formation of a G&T would result in a transfer of assets and property rights to a new, as yet, undefined entity without adequate compensation or subsequent equitable controlling interest. In the spring of 1982, Chugach commissioned a study by Smith & Gruening, Inc. (attorneys of Anchorage, Alaska) and Wald, Harkrader & Ross (attorneys of Washington, DC) to assess the implications of alternative organizational structures for Chugach. The report to the Chugach Board of Directors, dated July 27, 1982, described the study as a preliminary analysis of certain legal, regulatory, and practical implications of the alternative organizational structures reasonably available to Chugach. The study addressed the implications of Chugach forming a separate G&T cooperative, alone or with others, or taking other steps that might achieve Chugach's goals without restructuring the entity. The goals identified in the report included placing Chugach on a sound footing with its lenders, relieving Chugach from unfavorable contracts with its wholesale customers, and complying with such orders of the Alaska Public Utility Commission as may be lawful. In preparation for their analysis and to gain a full understanding of Chugach's situation, the two legal firms took a number of steps including principally the following: 1. Reviewed the agreements currently in effect between Chugach and its lenders, its wholesale customers, and its fuel suppliers; 2. Interviewed representatives of Chugach, its wholesale customers and relevant governmental agencies; 3. Reviewed the Alaska law applicable to the formation, governance and regulation of electric cooperatives; 4. Reviewed the relevant federal law concerning taxation of electric cooperatives, the regulation of wholesale power sales, and sale of natural gas. As a result of these reviews, the report focused on two alternatives: (1) continuation of Chugach as an integrated utility, or (2) formation of a G&T cooperative. It was noted that other alternatives, including formation of a private utility, were considered but rejected as offering no particular advantage, and in some instances substantial disadvantages, in comparison to the two alternatives analyzed in the report. The report then went on to discuss the advantages and disadvantages of maintaining Chugach as an integrated utility or forming a G&T cooperative and posed choices available to the Chugach Board of Directors as the basis for a possible decision. I-8 beens feerernes eee THE COOPERATIVES Chugach Chugach was formed in 1948 as an electric cooperative. Chugach currently serves over 50,000 consumers at retail in the Anchorage area and on the Kenai Peninsula. Chugach also sells power on a wholesale basis to Homer, Matanuska and the City of Seward. Chugach relies primarily on its own generation to provide power to these customers. Most of this generation comes from the Beluga Generating Plant located northwest of Anchorage. Additional power is provided by other gas-fired generating plants and purchases from the Alaska Power Administration's 30-MW Eklutna Hydroelectric Plant. Homer Homer is an electric distribution cooperative along the western edge of the Kenai Peninsula and extending inland approximately 25 miles from the Soldotna-Sterling area. Homer's headquarters is in Homer, Alaska near the southern tip of its service area. Homer does not currently own any generation facilities except standby capacity totalling 2.1 MW at the Seldovia diesel plant. Homer does own some transmission facilities which it leases to Chugach in accordance with the wholesale power contract. Except for minimal generation at Seldovia, Homer purchases its entire power requirements from Chugach. I-9 Matanuska Matanuska, with its headquarters in Palmer, Alaska, is an electric distribution cooperative providing power primarily in the northern Anchorage and Matanuska-Susitna borough. Although Matanuska does not provide any of its own generation in the Anchorage or Matanuska-Susitna borough area, it does own transmission facilities which it leases to Chugach in accordance with the wholesale power contract. Matanuska is responsible for the 1.15-MW Unalakleet diesel engine generating plant which provides power to the City of Unalakleet. This is a small isolated load, however, and is not considered in this study. Chugach provides the majority of Matanuska's power requirements. Matanuska also contracts with the Alaska Power Administration for 5 MW of firm capacity from the Eklutna Hydroelectric Plant. STUDY SCOPE AND APPROACH After collecting data, the first phase of the study involved a review of the present power supply situation of the Cooperatives including the existing organizational structure, generation and transmission facilities, power sales contracts, fuel supply contracts, and long-term debt. Following this review, the advantages and disadvantages of alternative organization types which might be applied to the power supply situation of the Cooperatives were examined. On the basis of this examination, those organization types which appeared to be most feasible and applicable to the power supply situation of the Cooperatives were selected for further study. In conjunction with the review of the organizational alternatives, a review of generation, purchase, and transmission alternatives for supplying power to the I-10 error were ra rN oe] oy ¢ 4 Cooperatives in the future was conducted. This review resulted in the development of three reconnaissance grade exploratory expansion plans which were used to compare the relative economic merits of the selected organizational alternatives. Based upon the results of the economic evaluations and after taking into account various factors not readily quantified in an economic analysis, a preferred organizational alternative was identified. A preliminary list of requirements for implementing this alternative was also developed. The economic evaluations performed in this study assume that the relevant power supply facilities consist of the existing generation and transmission facilities of Chugach, transmission facilities currently leased by Chugach from Homer and Matanuska, and future generation and transmission facilities which may be constructed to provide power to the Cooperatives. To provide a valid comparison, the facilities and capital investment in power supply facilities were assumed to be essentially constant among the organizational alternatives evaluated under each exploratory expansion plan. Any differences identified were intended to reflect incremental differences which would result from the development of a particular organization structure. The economic evaluations of the study involved projecting wholesale power costs with the aid of a financial forecast computer model for each of the exploratory plans and alternative organizational types considered over the period 1983-2015. Three long-range expansion scenarios were represented by the exploratory expansion plans. These included one plan which assumed the development of the Susitna hydroelectric project by the Alaska Power Authority, one plan which assumed the long-range expansion of generation in the area would involve I-11 primarily gas-fired generation, and one plan which assumed the long-range expansion of generation in the area would involve primarily coal-fired generation. These three expansion scenarios were considered in order to assess the range of possible impacts which the scenarios might have on the power supply organizational structures. These impacts would vary depending on the amount of capital investment and related long-term financing required by the Cooperatives under the alternative scenarios. It should be noted that for purposes of evaluating the results of the study, the economic projections associated with one particular scenario were not intended to provide a basis for comparison with the economic projections of another scenario. This is due to the fact that the economic comparisons in this study were of a limited and preliminary nature. Therefore, conclusions concerning the relative merits of various power supply expansion scenarios are not appropriate. Thus, the results presented in this report should not be used to compare the Susitna expansion scenario, for example, with the coal-based expansion scenario to determine which of these two alternative expansion scenarios might be more economical. Conclusions concerning the relative economic feasibility of power supply expansion alternatives should only be formulated from the results of a more thorough and complete power supply study. Pe es |e I-12 a ood . —_— ——_ ee 0 ee — — a ||| ie Pre) || Gps) | | pee) beeen || eat tbe ee ae Qo PART Il — EXISTING ORGANIZATION AND POWER SUPPLY PART II EXISTING ORGANIZATION AND POWER SUPPLY This part describes the existing power supply situation and organization of the Cooperatives. This includes a discussion of the existing power supply contracts which Chugach has with Homer and Matanuska, the power supply sources currently available to the Cooperatives, fuel supply arrangements and the existing transmission systems. CHUGACH Chugach is an electric utility which has experienced rapid growth over the past decade. The peak demand on Chugach's system has grown from 108 MW in 1971 to 352 MW in 1981 or at an average annual compound growth rate of 13 percent. Chugach has the largest system load of any electric utility in Alaska. Chugach supplies its retail and wholesale customers with power generated from its own gas-fired, waste heat and hydroelectric generation facilities. In addition to power generated from its own plants, Chugach also purchases 9 MW of firm capacity and associated energy from the Alaska Power Administration. Power is distributed to customers over distribution and transmission facilities which Chugach owns and transmission facilities leased from Homer and Matanuska. The generation, transmission, distribution and other plant facilities owned by Chugach have a book value of over $330 million. The following paragraphs describe Chugach's generation and transmission facilities, power sales contracts and fuel supply. II-1 Generation and Power Purchases Generating plants owned and operated by Chugach include the Beluga Station, Bernice Lake Power Plant, Cooper Lake Power Plant, International Station and the Knik Arm Power Plant. Chugach also purchases firm capacity and energy from the Alaska Power Administration. Chugach's generating units and the operating characteristics used for these units in this study are summarized in Table II-1. These operating characteristics are generally based on historical data and projected operating data from the revised financial forecast prepared by Chugach in October 1982. Chugach's 518 MW of capacity consists of 445 MW of gas-fired generation, the 17-MW Cooper Lake hydroelectric power plant and the 56-MW Beluga 8 waste heat generating unit. Beluga Unit 8 is driven by the waste heat from Beluga Units 6 and 7. All of the gas-fired generating plants are combustion turbines except the Knik Arm Power Plant which is a steam plant. Power purchased from the Alaska Power Administration is generated at the Administration's Eklutna Hydroelectric Generating Plant. Chugach receives firm capacity of 9.0 MW and firm energy of 45,900 MWh per year. Chugach does not incur a demand cost for the firm capacity from the Administration, instead paying only an energy charge which is currently approximately 13 mills/kWh. The contract for purchase of this power expires on December 31, 1988. We have assumed for purposes of this study that this contract will be extended or renewed with provisions similar to those of the existing contract. II-2 oe Cd _— ” Generating Unit Beluga 1 Beluga 2 Beluga 3 Beluga 4 Beluga 5 Beluga 6 Beluga 7 Beluga 8 Bernice Lake 1 Bernice Lake 2 Bernice Lake 3 Bernice Lake 4 Cooper Lake 1 Cooper Lake 2 International 1 International 2 International 3 Knik Arm Total Generation Capacity Eklutna Purchase Total Available Capacity ! Based on ‘Ten Year Review (1971-1980), Report on Equipment Availability, '’ by the National Electric Reliability Council Generating Availability Data System. 7 Excludes fuel expense. Net Capability (Mw) 18.0 18.0 56.2 10.0 61.3 69.4 70.0 56.0 8.3 19.6 28.0 28.0 8.6 8.6 14.5 14.5 19.2 10.0 518.2 14.0 532.2 In Service Year 1968 1968 1972 1976 1972 1976 1976 1982 1963 1971 1978 1982 1961 1961 1965 1965 1965 1952 N/A SUMMARY OF EXISTING RESOURCES Generation Type Comb. Turbine Comb. Turbine Comb. Turbine Comb. Turbine Comb. Turbine Comb. Turbine Comb. Turbine Waste Heat Comb. Turbine Comb. Turbine Comb. Turbine Comb. Turbine Hydro Hydro Comb. Turbine Comb. Turbine Comb. Turbine Steam Prod. Firm Purchase 3 Net actual capacity available at 0°F from information received from Chugach. Based on historical data from Chugach’s REA Form 12. . Estimated cost based on contractual agreements and current costs. Table ti-1 Fuel Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Waste Heat Natural Gas Natural Gas Natural Gas Natural Gas Water Water Natural Gas Natural Gas Natural Gas Natural Gas Water fa fea CoS Fea tes fon OC ry Ea 1983 Operation and Average Maintenance4 Annual Net Heat 1983 Operating Rate Fuel Cost Availability! Fixed Variable? (Btu/kWh)4 (¢/MBtu)> (%) ($/kW-Yr) (Mills/kWh) 13,800 21.0 83.0 8.43 0.56 13,800 21.0 83.0 8.43 0.56 13,800 21.0 83.0 8.43 0.56 13,800 21.0 83.0 8.43 0.56 13,800 21.0 83.0 8.43 0.56 13,800 21.0 83.0 8.43 0.56 13,800 21.0 83.0 8.43 0.56 13,800 0.0 83.0 8.43 0.56 20,000 118.0 83.0 5.37 0.36 20,000 118.0 83.0 5.37 0.36 20,000 118.0 83.0 5.37 0.36 20,000 118.0 83.0 5.37 0.36 0 0.0 95.1 10.50 0.63 0 0.0 95.1 10.50 0.63 34,100 118.0 83.0 5.07 0.63 34,100 118.0 83.0 5.07 0.63 34,100 118.0 83.0 5.07 0.63 24,200 118.0 83.0 48.72 3.35 0 0.0 100.0 —_ = Transmission Chugach currently operates its own transmission system including the transmission facilities leased from Homer and Matanuska. Chugach has only one transmission interconnection besides those with its wholesale customers. This is an interconnection at Chugach's University substation which provides a 50-MW exchange capability with Anchorage Municipal Light & Power (ML&P). Chugach does not currently utilize this interconnection to transmit or receive power from ML&P except during periods of unplanned outages of either utilities’ generating units. Chugach's transmission system is primarily comprised of a 138-kV system which interconnects the Beluga Station with the Anchorage area and Matanuska. This system includes two 43-mile lines from the Beluga Station to the Point MacKenzie Substation. One set of lines extends from Point MacKenzie through four circuits of 138-kV submarine cable under the Knik Arm to the Point Woronzof Substation. The other 138-kV line from Beluga Station extends 26 miles to the Walter Teeland Substation to provide service to Matanuska. Many parts of this portion of the transmission system are being upgraded or expanded to a 230-kV system. The 138-kV system also connects (1) the Point Woronzof and International Substations (2) the International and University Substations and (3) the Point MacKenzie and University Substations through the East and West Terminal Substations. II-4 wre -s Chugach also has 115-kV transmission lines including: 1. A 27-mile line from the University Substation to the Alaska Power Administration at the Anchorage Substation. 2. A 165-mile line between the University Substation and the Bernice Lake Generating Plant. Part of this line is leased from Homer. Matanuska and Homer own transmission lines and substations as part of their electric distribution systems. Part of these transmission facilities are currently leased to Chugach in accordance with the terms of the amended wholesale power sales contract between Chugach and Homer and Matanuska. These facilities are further described in Part IV. Chugach's Contracts with Homer and Matanuska Chugach entered into similar contracts for the sale and purchase of electric power and lease of generation and transmission facilities with Homer and Matanuska on May 27, 1963 and May 1, 1974, respectively. These contracts were amended on April 20, 1982 to relieve the financial strain on Chugach. The key provisions of these amended contracts relative to this study include the following: 1. The rate for wholesale power and energy sold to Homer and Matanuska is established as the actual cost for Chugach to generate and transmit such power and energy plus a TIER factor of 1.15 on applicable debt. The II-5 rate is established annually on a pro forma basis and adjusted quarterly based on actual results. Chugach leases the following transmission plant facilities from Homer: d. Quartz Creek to Soldotna transmission station (69 kV). Soldotna transmission station to Bernice Lake power plant (69 kV). Quartz Creek to Soldotna transmission station (115 kV). Soldotna transmission station to Bernice Lake power plant (115 kV). Soldotna transmission substation. Chugach leases the following transmission plant facilities from Matanuska: db. Ce Lucas Substation to Four Corners Substation 115-kV transmission line. Four Corners Substation to Herning Substation 115-kV transmission line. Herning Substation to Walter Teeland Substation 115-kV transmission line. TI-6 oa em d. Palmer Substation to Lucas Substation 115-kV transmission line. e. Shaw, Briggs and Reed Substations. Chugach will operate and maintain the facilities leased from Homer and Matanuska and will make capital replacements if agreement is made to do so by Chugach and Homer or Matanuska, respectively. Chugach will maintain insurance on the transmission facilities leased from Homer and Matanuska as required by the REA Administrator. Chugach will pay taxes legally assessed and leveed on the transmission facilities leased from Homer and Matanuska. Chugach will make payments to Homer and Matanuska for the transmission facilities leased equal to the sum of: a. Depreciation expense on leased facilities. be Interest expense on the long-term debt associated with the leased facility. ce Contribution to equity at the rate of 15 percent of interest paid on a long-term debt associated with leased facilities. II-7 10. In determining the cost of power to Homer and Matanuska, a line loss factor of 2.75 percent of kWh generated is used. Homer and Matanuska become and remain members of Chugach during the life of the amendment and are entitled to all rights and privileges thereof. Generation and transmission plant which provide the basis for the sales price of energy and power sold by Chugach will include in addition to the transmission facilities leased from Homer and Matanuska, the following facilities of Chugach: a. Production plant including Knik Arm Power Plant, Cooper Lake Hydroelectric Project, Bernice Lake Power Plant, International Station and Beluga Station. b. Transmission plant bulk substations including Quartz Creek, Anchorage, International, Bernice Lake, University, Walter Teeland and Point MacKenzie. c. Transmission stepup substations including Knik Arm, Cooper Lake, Bernice Lake, International and Beluga. d. Transmission lines including: Knik Arm to Anchorage Substation (34.5 kV), Quartz Creek Substation to Anchorage Substation (115 kV), Cooper Lake to Quartz Creek Substation (69 kV), International to II-8 tase! — Led fener ewe eet ew ~ ove t & oat: Qu ey rae wom ‘ me University Substation (115 kV), Beluga Lines (138 kV) and Knik Arm Lines (138 kV and 115 kV). Fuel Supply Chugach currently purchases natural gas for its generation plants at relatively favorable rates. The natural gas for each of the generation plants is produced from wells in the Cook Inlet area. Natural gas for Chugach's largest plant, the Beluga Plant, is produced from the Beluga River Unit equally owned by Atlantic-Richfield, Standard 0il of California and Shell Oil Company. The current contracts for the Beluga River Field natural gas were executed in January 1973 and amended in March 1974. The contracts in their present form specify a maximum of 373,000,000 mcf will be taken from the Beluga River Unit. A total of approximately 142,000,000 mcf (estimated) has been taken through December 1982. The current contract is a take-or-pay contract specifying that Chugach will pay for a minimum of 55,000 mcf per day. The maximum amount which Chugach may draw from Beluga River is 60,000 mcf per day. At the current rate of usage, it is estimated Chugach will consume all of its natural gas alloted under this contract in the mid 1990s. By that time, another source of natural gas, probably at substantially higher prices than under the current contract, must be found. Sufficient gas is not currently available under the agreement for gas from the Beluga River Field to operate Beluga 1, 2 and 4 under normal base loading of Beluga Units 3, 5, 6, 7, and 8. This results from the maximum take provisions of the long-term contract for gas from the Beluga River Field. Chugach has negotiated a short-term to purchase up to 20,000 mcf of additional natural gas II-9 per day to operate Beluga 1, 2 and 4 through May 1983. This gas will cost approximately $1.50/MBtu in 1983. We have assumed this cost will increase to approximately $2.50/MBtu in 1984. The cost of this natural gas, identified as new Beluga gas, was assumed to increase at approximately 8 percent per year after 1984. Based on information in the Battelle reports regarding long-term availability of natural gas in the Cook Inlet area, we have assumed that this new Beluga gas would not be available in sufficient quantities beginning in 1995 for utility usage. Therefore, beginning in 1991 we have assumed a 5-year phased withdrawal from usage of new Beluga gas for Beluga 1, 2 and 4. This gas is assumed to be replaced with gas from Alaska's North Slope area. The natural gas supplies for Bernice Lake, International and Knik Arm are obtained from Enstar Natural Gas Company (formerly the Alaska Gas and Service Company). This natural gas is supplied under a tariff filed with the Alaska Public Service Commission (APUC).. HOMER Homer currently purchases almost all of its power requirements from Chugach. This power is delivered to the northern portion of Homer's service area over a 115-kV and a 69-kV transmission line from the Quartz Creek Substation. Power to the southern area of Homer's system is delivered over a 115-kV line from the Soldotna Substation. The slight amount of power which Homer does not purchase from Chugach is generated at the Seldovia standby diesel plant. The net generation at this plant during recent years has totalled less than 0.5 percent of Homer's net II-10 saeoas Cons! ree 4 7 oe —— t “4 wee red energy requirements. Homer's standby plant at Seldovia has a total installed capacity of 2.1 MW. MATANUSKA Matanuska currently receives power from Chugach and the Alaska Power Administration. The power received from Chugach is delivered to Matanuska over 115-kV transmission lines. Matanuska also purchases 5 MW of firm capacity and 25,500 MWh of firm energy from the Alaska Power Administration's Eklutna hydroelectric plant. Power purchased from the Alaska Power Administration is assumed for purposes of this study to be available after Matanuska's current contract with the Alaska Power Administration expires on December 31, 1988. We have assumed that this power will continue to be available in quantities which are identical to existing contract amounts. As we discussed in Part I, Matanuska also provides power to the community of Unalakleet. This power is provided from a 1.15-MW diesel plant in Unalakleet which is not interconnected with the remainder of Matanuska's transmission system. ee ee II-11 tc, FF” _ PART IIl— ALTERNATIVE POWER SUPPLY ORGANIZATIONS ra os rs a Se ro PART III ALTERNATIVE POWER SUPPLY ORGANIZATIONS This part describes the alternative organization types which the Cooperatives might employ to provide their power supply in the future. These alternatives include continuation of the existing power supply arrangement or formation of a new organization. New organizations which might be formed include a generation and transmission cooperative, a public power agency, a taxable utility or some possible combination (hybrid) of these organizations. In general, the alternatives to continuation of the existing arrangement were assumed to include the formation of a new power supply organization whose membership or ownership would involve either all three Cooperatives or Chugach alone. The new organization was assumed to supply power at wholesale to all three Cooperatives. The advantages and disadvantages of each of these organization types and the rationale for selecting specific organizations for further study are discussed in this part. EXISTING ARRANGEMENT One alternative available is the continuation of the present power supply organizational arrangement. Under this alternative, Chugach would continue to own and operate the majority of the generation and transmission facilities used to supply power to the Cooperatives and, in addition to generating and delivering power at wholesale, would continue to supply its own customers at retail. Chugach would continue to function with a single Board of Directors, General Manager, and staff for the accomplishment of the distribution, transmission and generation functions. Two variations of this alternative are III-1 particularly relevant to this investigation. Under one variation, there would be no change from the current situation in which Chugach is required to maintain a minimum TIER of 1.5 on distribution facilities and 1.15 on transmission and generation facilities by REA and CFC. Under this variation, we have assumed the minimum TIER requirement on G&T related investments would increase to 1.5 after 1983 per agreements with REA and CFC. Under the other variation, Chugach would be permitted to carry a minimum TIER of only 1.0 on its generation and transmission facilities while continuing to maintain a minimum TIER of 1.5 on its distribution facilities. Each of these two variations is discussed below. No Change in TIER One possible option would be for Chugach to continue to operate under the present arrangement without a change in minimum TIER on G&Tf facilities (1.15 through 1983 and 1.5 thereafter). REA, CFC, the APUC, and others have criticized the current arrangement primarily because of the impact of the 1.5 minimum TIER on the wholesale power costs of Chugach and ultimately on the retail rates of the Cooperatives. While this alternative may be a desirable option from Chugach's perspective, it may not be a tenable one unless it can be shown that operation with a 1.5 minimum TIER will not significantly affect the wholesale power costs of the Cooperatives compared to other alternatives. The primary concern at Chugach is that the adoption of another form of organization may involve a transfer of assets and property rights to a new, as yet undefined, entity without just compensation and subsequently equitable controlling interest. It is also perceived that Chugach's role in the power supply decision-making process could be significantly diminished. From the III-2 i. perspective of Chugach, advantages of continuing with the current arrangement v include: 1. Chugach would retain exclusive control over the generation and transmission facilities which it owns. 2. Chugach would continue to retain exclusive control over its existing é ‘. fuel supply contracts. 3. Chugach would not lose any of its decision-making prerogatives i concerning power supply matters. \ 4. Management resources and funds would not be diverted from the many other u complex problems presently confronting Chugach. From the perspective of all three Cooperatives, disadvantages associated with continuation of the power supply organization in its present form include: 1. Wholesale revenue requirements would be determined on the basis of a 1.5 minimum TIER level after 1983. Although REA and CFC have relaxed the minimum TIER requirement to 1.15 through December 1983, it appears reasonable to assume that the relaxed TIER level will not be extended beyond 1983. The resumption of the standard 1.5 minimum’ TIER requirement in 1984 would result in increased wholesale power costs to i the Cooperatives. ELT} 2. Continuation of the present arrangement would likely result in a weaker cooperative power supply organization than might be possible through the merging of the Cooperatives’ resources. From the perspective of Chugach, continuation with the present arrangement would be contrary to the expressed wishes of REA, CFC and the APUC. Split TIER Another possibility would be for Chugach to negotiate with REA and CFC to permit an extended or permanent relaxation of these organizations’ requirement that a distribution cooperative maintain a minimum TIER of 1.5 on all facilities including generation and transmission facilities. If this minimum TIER requirement on generation and transmission properties could be relaxed on a permanent or extended basis without formally organizing a G&T Cooperative, one of the major disadvantages of the perpetuation of the current arrangement would be eliminated. In order to assess the probability that REA and CFC might relax their policy, we sent letters to these two organizations inquiring into the probability that this might indeed occur. The responses of these organizations, included in Appendix D of this report, indicate they will not relax the 1.5 TIER requirement. Both responses advocate formation of a G&T or other power supply organization as a completely separate entity. III-4 m GENERATION & TRANSMISSION COOPERATIVE Under this alternative, a new generation and transmission cooperative would be formed. This cooperative could be formed either by Chugach alone or by Chugach jointly with Homer and Matanuska (joint G&T). Formation of a G&T by Chugach alone was assumed for purposes of this study to involve splitting Chugach into two separate entities with separate boards and accounting functions. All generation, transmission, and applicable general plant properties would be assigned to the new G&T organization and distribution-related properties would remain with the distribution entity. In the case of the formation of a joint G&T with Homer and Matanuska, it is assumed the generation, transmission, and power supply-related general plant properties of Chugach would be combined with the power supply-related properties of Homer and Matanuska (primarily transmission). It should be noted that the possibilities in forming a joint G&T organization are not necessarily limited to Chugach, Homer and Matanuska especially once the planned Fairbanks-Anchorage Transmission Intertie project is constructed. The Anchorage-Fairbanks Transmission Intertie project consists of 171 miles of 345-kV transmission which will initially operate at 138 kV. The purpose of the line is to provide economy interchange and reserve capacity sharing between the Anchorage and Fairbanks load centers. It is planned to be in service by December 1984. The availability of this intertie could facilitate the formation of a joint G&T cooperative comprised of Golden Valley Electric Association (GVEA) and Chugach alone or GVEA and Chugach, Matanuska, and Homer. While the development of a joint G&T with GVEA presents a very real possibility for the III-5 Cooperatives, the evaluation of this alternative is beyond the scope of this study and, therefore, it was not analyzed. In the case of creating a joint G&T including Chugach, Homer, and Matanuska, the actual details of how the facilities and property rights of the respective cooperatives would be allocated and appropriate compensation, if any, would need to be negotiated among the Cooperatives. For purposes of this study, however, it was assumed that formation of a joint G&T would involve dividing Chugach by transferring all generation and transmission facilities and other related assets and liabilities applicable to the wholesale power supply function to the new G&T. Also, any contractual arrangements applicable primarily to the wholesale power supply function would be assigned to the new G&T. The balance of the Chugach facilities, properties, and contracts would remain with Chugach and would form the basis for a distribution cooperative. Similarly, generation and transmission facilities and contracts applicable to the power supply function and owned by Homer and Matanuska would also be transferred to the new G&T. A Board of Directors would be elected, staff would be assigned, and the new G&T would begin to operate as an independent entity generating, purchasing and transmitting power for delivery at wholesale to the three distribution cooperatives. The new G&T cooperative would possess substantial resources and also major commitments from the first day of its operation. It can be envisioned, that at the outset, the G&T may be what is often referred to as a “paper G&T." However, because of its very substantial facilities and commitments, this organization would, in fact, be much more than just a "paper G&T." It would have its own III-6 ee noe e 3 . Eee fa 2 rs ee Board of Directors, require its own staff, own and operate major power supply facilities, and be responsible for the delivery of power at wholesale to supply the needs of the customers of the three distribution cooperatives. Because the obligations and responsibilities of the G&T would be substantial, it could be expected to eventually grow into a full-fledged, separate power supply organization with facilities substantially independent of those of Chugach. However, initially the new G&T would need to depend heavily on the existing Chugach organization for administration and operation. It can be anticipated that a new G&T would need to contract with Chugach for staff and logistic support during the early years of its operation. Among the advantages which the formation of a G&T cooperative can present to the Cooperatives are: 1. Formation of a G&T organization would permit the Cooperatives to reduce their TIER on loans for G&T properties to a minimum of 1.0. 2. Formation of a joint G&T would combine the resources of the Cooperatives into one power supply organization. This type of organization should be financially and politically stronger than Chugach alone. 3. Formation of a joint G&T would provide a framework for the inclusion of additional distribution cooperatives in the future. Possible candidates are Copper Valley Electric Association and Golden Valley Electric Association which supply power to their members in the rural areas in or around Valdez and Fairbanks, respectively. However, the incorporation TIl-7 of these Cooperatives into a possible G&T organization would depend upon the development of the necessary transmission interties. From the perspective of Homer and Matanuska, the formation of a joint G&T would provide these Cooperatives with a greater measure of control and input to their power supply. Formation of a G&T (joint or Chugach alone) would enable Chugach to comply with the desires of REA, CFC, and the APUC. A G&T cooperative could be converted into a taxable entity to provide certain benefits associated with leasing which may be available to taxable entities (see discussion page III-15). There would also be some disadvantages associated with the formation of a new G&T cooperative. These include: 1. Additional costs would be incurred in order to organize and start-up a separate G&T. These costs would be associated with establishing another Board of Directors, additional staffing, legal and consulting fees and possibly additional facilities. Additional costs would also be incurred in operating the new G&T as an on-going concern relative to the costs of performing G&T functions by the existing Chugach distribution cooperative. These costs would include annual expenses necessary to maintain a separate G&T Board of III-8 ieee) ee Directors, additional staffing and eventually additional facilities. The additional staffing would be necessary to perform G&T functions currently fulfilled by personnel who are also carrying out distribution activities. 3. The new G&T may possibly be subject to APUC jurisdiction and, as such, the rates for power and energy sold to distribution members could be subject to regulatory control. The inherent nature of regulatory control encompasses a degree of lag in approval of rates, and as such it may prove difficult to obtain rates at the minimum TIER level. It should be noted, however, that APUC jurisdiction over wholesale power transactions between the Cooperatives may come about even if a G&T is not formed. 4. It is possible that transfer of assets and related obligations to the new G&T would involve a debt to the distribution cooperatives, primarily Chugach, for their equity in these assets at date of transfer. It should also be noted that the Cooperatives’ lenders would have to approve the organization and structure of the G&T, the terms of wholesale power contracts, and the terms of any management agreement between the Cooperatives and the G&T. To the extent the APUC may validly exercise jurisdiction over a new G&T, that agency may likewise have to approve the organization and structure of the G&T, the terms of wholesale power contracts, and the terms of any management agreement between the Cooperatives and the G&T. III-9 It is obvious that there are advantages and disadvantages to forming a joint G&T cooperative. The relative weight of the advantages and disadvantages depends upon whether one adopts the perspective of Chugach or the perspective of Homer and Matanuska. Chugach appears to have less to gain from the formation of a G&T cooperative since it currently owns the majority of the generation and transmission facilities in the area and also owns and controls the favorable gas supply contracts for the Beluga Generating Plant. There is a significant “going concern" value which one can ascribe to the existing generation and transmission controlled by Chugach. Homer and Matanuska, on the other hand, would appear to have more to gain from the formation of a G&T since these cooperatives have no significant control or voice in power supply matters. All three Cooperatives, however, would benefit from a lower minimum TIER applied to generation and transmission facilities which the formation of a joint G&T cooperative would make possible and all three should also benefit from a stronger G&T organization. Perhaps, it is most important to recognize that the relative weight of any advantages and disadvantages will depend upon the nature of the G&T cooperative formed and the agreements reached by the Cooperatives with respect to the transfer of facilities and contracts. For example, concerns on the part of Chugach about the loss of control could be mitigated by weighting the number of board members of the G&T based upon the relative kilowatt-hour sales or number of customers of the respective Cooperatives (See Appendix E for comparative values of kilowatt-hour sales and numbers of customers for the Cooperatives). Alternatively, there might be provisions for weighted voting for certain key issues. Thus, there is considerable flexibility in how a new G&T Cooperative III-10 eee might be formed and, therefore, it would seem that if a mutually acceptable agreement can be signed by the parties, many of the concerns about the relative advantages and disadvantages of a G&T might be addressed to the satisfaction of all parties. One item of particular concern expressed by Chugach is the transfer of property rights of the existing natural gas contracts for the Beluga Plant. The concern is that formation of a G&T might reduce benefits derived from these contracts by the existing Chugach customers and transfer the lost benefits to Homer, Matanuska, and possibly others. Our review of the situation indicates that Homer and Matanuska are already sharing in the benefits of these gas contracts through their wholesale power agreements with Chugach. This is due to the fact that Homer and Matanuska are currently purchasing power based upon Chugach's average cost of production. Thus, relative to the formation of a G&T with Homer and Matanuska, the transfer of the gas contract property rights to a G&T should not immediately present any change in these benefits to the Chugach members. Also, it would be possible to place certain restrictions on the G&T formation agreement to provide assurances that the economic benefits presently derived from the gas contracts by Chugach and shared with the existing wholesale customers of Chugach will not be further diluted in the future. Another item of concern is that Chugach might have to share or give up a portion of its equity in power supply facilities. Concerns about equity could be accomodated with appropriate compensation, determined through negotiations, from the G&T to cooperatives having equity in the facilities transferred to the G&T. In fact, it does not appear that this should be a major stumbling block since III-11 the combined equity in power supply facilities appears to be relatively small (roughly $7.5 million) compared to the outstanding principal balance ($217 million) on G&T facilities (See Table IV-2). PUBLIC POWER AGENCY Another possibility which has been advanced is for the Cooperatives to organize a public power agency. The formation of a public power agency would represent a significant departure from their traditional form of supplying power to their members, namely the member-owned-cooperative concept developed under the umbrella of the Rural Electrification Act. A public power agency would most likely become some form of political subdivision of the State of Alaska. A public power agency could take one of several forms including a joint-action agency, a public utility district, or a power authority. Whatever form such an agency might take, it would require the passage of enabling legislation by the State of Alaska. A joint-action power agency is a power supply organization whose membership is typically comprised of electric systems which perform primarily a distribution function. The majority of the joint-action power supply agencies in the United States today are municipal joint-action agencies. A municipal joint action agency is, in fact, the municipal utility system counterpart of the G&T cooperative of the rural electric systems. A major advantage of a joint-action agency is that it would permit the inclusion of municipal utilities, such as Seward and Anchorage, in the organization. One advantage of a public power agency is that such agencies can issue tax-exempt bonds for financing provided that the agency meets the requirements for such financing of the Internal ITI-12 . ' 1 — — Boe ua Ene = ec reo oy ey Revenue Service. This could present problems for the Cooperatives since the regulations of the IRS require that no more than 25 percent of a project financed with tax-exempt bonds can be devoted to the benefit of entities not eligible for tax-exempt financing. Since the Cooperatives would no doubt represent the major share of the load of such a joint-action agency, the agency's ability to finance using tax-exempt bonds could be severely restricted. This problem might be alleviated by converting the Cooperatives into public utility districts. This would permit the formation of a joint-action agency whose membership would be comprised entirely of entities eligible for tax-exempt bond financing. If the Cooperatives were to reorganize into public utility districts, it is possible they may be required by REA and CFC to refinance outstanding loans with these organizations. Power supply costs could be increased depending on the interest rate at which refinancing could occur. The current weighted average interest rate on the Cooperatives’ applicable G&T debt is approximately 9.5 percent. The ability to refinance at a lower rate is subject to various market and political factors which are difficult to predict. Another possibility would be for the Cooperatives to form a power supply authority somewhat along the lines of the Alaska Power Authority. However, this authority may require legislation to be established. Such a new agency might also find itself competing in unwanted ways with the Alaska Power Authority, and the degree of control which the Cooperatives might have over such an organization or the form of such control would be difficult to predict. III-13 In summary, the advantages of a public power agency would include: 1. 2. The possibility of bringing noncooperative entities into the power supply organization. The possibility of issuing tax-exempt bonds. There also would be significant disadvantages with the formation of a public power agency including: 1. A public power agency could be far more complex to implement because enabling legislation may be required to define the organization. The legislation which might ultimately be enacted might not match the desires of the Cooperatives because of the vagaries of the political process. Much more time may be required to implement a public power agency compared to a G&T because of the need to enact legislation and also the additional time required to determine its form and structure and to gain support. Significant complications might arise with the transfer of the Cooperatives’ power supply assets to a public power supply agency. Formation of a public power agency (or any other organizational structure for that matter) might possibly require refinancing of existing debt. Section 7 of the 1936 Rural Electrification Act states III-14 that no borrower of funds shall, without approval of the REA Administrator, sell or dispose of its property, rights, or franchises until any loan obtained from the REA, including all interest and charges, shall have been repaid. In summary, the formation of a public power agency might have some advantages relative to continuation of the existing situation or forming a G&T cooperative, but there are also significant drawbacks. Perhaps, the biggest drawback is that formation of such an agency would represent a substantial departure from the traditional methods of supplying power to the Cooperatives’ members. Forming a public power agency would be far more complicated and a much longer period of time would likely be required to form such an agency. The agency which ‘might ultimately evolve from such efforts may not be in the form which the Cooperatives had in mind, either in the form of the organization, the scope of the membership, or the level of control to be exercised by the Cooperatives. TAXABLE UTILITY The formation of a taxable power supply organization would involve loss of the tax-exempt status allowed the Cooperatives under Section 501(C)(12) of the Internal Revenue Code. This section of the Code allows a cooperative to be exempt from federal income taxation if 85 percent or more of its revenues are derived from members to meet expenses and losses. A taxable utility could be established through either formation of an investor-owned utility or a taxable cooperative. III-15 Advantages accruing through the formation of an investor-owned organization would be primarily in the form of some additional flexibility for financing arrangements. An investor-owned utility could raise new capital through either long-term debt or issuance of common or preferred equity. However, such capital would be more expensive than capital obtained under the guaranteed loan program made possible by REA and CFC. Several other significant disadvantages would also occur under formation of either type of taxable utility. Formation of a taxable utility would require payment of taxes on any profit or operating margin. Through use of accelerated amortization of utility plant or investment tax credits, a newly formed organization's tax obligations could be reduced but never to a point where benefits would accrue relative to either the current organizational structure or formation of a tax-exempt G&T Cooperative. Formation of an investor-owned utility would also be complicated by accounting changes required to bring the newly formed organization under regulation of the Federal Energy Regulatory Commission and Securities and Exchange Commission. In summary, formation of an investor-owned utility does not appear to be a viable alternative because: 1. Revenue requirements of an investor-owned organization would be higher due to the need to refinance existing debt, higher costs of capital in general, and the need to make income tax payments on profits. III-16 es 2. Formation of an investor-owned organization would be time consuming and expensive. The accounting procedures and organizational philosophy of the current power supply organization would need to be entirely revamped. 3. Forming an investor-owned utility would represent a drastic departure from the past objectives and philosophies of the Cooperatives. It appears that efforts to develop such a power supply organization would have little probability of success, if for no other reason than the opposition which could be expected from the members of the Cooperatives. Formation of a taxable G&T Cooperative is a possibility as a variation of the G&T alternative organization type. In fact, the possibility of forming a taxable G&T would represent an advantage of a G&T organization. Gat cooperatives often become taxable entities to gain certain benefits involving leasing of equipment or facilities not available to tax-exempt entities. Also, some G&Ts must become taxable entities because their revenue from power sales to nonmembers exceed 15 percent of their total revenues (violating the IRS requirement that 85 percent of member revenues must come from members if a cooperative is to remain tax exempt). In general, a taxable status has relatively little impact ona car since G&T cooperatives operate with minimal margins because they need to maintain only a 1.0 TIER. However, for a distribution cooperative, which must maintain relatively significant margins to satisfy the 1.5 TIER requirement, a taxable status could require significant income tax payments. III-17 HYBRID ORGANIZATION Conceivably, other types of power supply organizational structures could be formed. These types of organizational structures might combine various features of a G&T cooperative, various aspects of public agencies, or a taxable entity. An arrangement of this type may require refinancing of all or portions of the currently outstanding low-cost REA and CFC funds. As discussed under the public power agency alternative above, the additional cost, complexity, and unpredictability of the results of efforts to develop such an organization are likely to outweigh any benefits derived. One possible type of hybrid organization which might reduce costs below that of either the existing organizational arrangement or a G&T cooperative would be an arrangement whereby the state could provide a grant to retire the existing debt to REA and CFC on Chugach's G&T facilities. This would require action by the Alaska Legislature and the resulting organization would probably be a state-run organization. However, under such an arrangement the Cooperatives may lose control of the ownership, management and operation of the existing G&T facilities. ORGANIZATION TYPES SELECTED FOR FURTHER STUDY This part of the report has considered five power supply organization types which might be implemented by the Cooperatives. These alternatives are: 1. Continuation of the existing arrangement, 2. Formation of a G&T Cooperative, 3. Formation of a public power agency, III-18 —_—— -— — 4. Formation of a taxable utility, and 5. Formation of a hybrid organization (some combination of 1-4 above). After considering the relative advantages and disadvantages of these different organization types, we conclude that the most feasible alternative to continuation of the existing arrangement is the formation of a G&T cooperative. As indicated previously, formation of a G&T cooperative could involve either Chugach alone or Chugach jointly with Homer and Matanuska. Another alternative which may become available with the completion of the Anchorage-Fairbanks intertie is a joint G&T involving the Cooperatives and GVEA. Such a G&T might involve only GVEA and Chugach or GVEA and Chugach, Homer, and Matanuska. However, evaluation of the possibility of forming a joint G&T with GVEA is beyond the scope of this study and, therefore, was not analyzed as part of this study. The major reasons for rejecting the other alternatives and not considering them further in the study are summarized below. Current Arrangement With Split TIER The possibility that the current power supply arrangement might be perpetuated if Chugach can obtain approval from REA and CFC for a split minimum TIER (1.5 on distribution and 1.0 on generation and transmission) was not considered further because of the apparently low probability that such an arrangement might be approved (See letters from REA and CFC in Appendix D). Public Power Agency As indicated previously, there are a number of major disadvantages associated with the formation of a public power agency. Perhaps, the overriding issue TII-19 involves the form which such an agency should take. There are a number of possibilities and each of these would require enabling legislation whose outcome, in terms of the type of organization permissible and the degree of control exercised by the Cooperative's or their members, would by no means be certain. Another potential problem is that it may be necessary to refinance the outstanding REA debt on facilities transferred to such an agency. This would most likely increase power supply costs to members since the cost of refinancing with tax-exempt bonds may be greater than Chugach's current weighted average cost of debt on G&T assets. The problem is compounded by the fact that the agency would not qualify for tax-exempt financing with Chugach, Homer, and Matanuska as members unless the Cooperatives also changed their form of organization to gain eligibility for tax-exempt financing. Thus, the alternative of forming a public power agency is a far more complex, potentially costly, and likely time-consuming alternative than other possibilities addressed. For these reasons, this organization type was not considered further in the study. Investor-Owned Utility This alternative was rejected for further consideration because its implementation would certainly increase power supply costs, be difficult to implement, and most likely be opposed by the membership. Taxable G&T Cooperative This alternative is really nothing more than a variant of the G&T Cooperative organization type. The ability to form a taxable Cooperative without incurring significant economic penalties is an advantage of a G&T form of organization. III-20 eet ee a - — at ~~ However, the economic benefits of a taxable G&T relative to the current arrangement or a tax-exempt G&T, if any, cannot readily be quantified. Thus, this alternative was dropped from further study. Hybrid Organization No doubt, the most nebulous of the alternative organization types addressed in this study is that of the hybrid organization which might combine any one of a variety of the features of the others. The reasons for rejecting this alternative are essentially the same as those for rejecting the other alternative types dropped from further consideration. A myriad of possibilities for hybrid organizations exist, and complications and disadvantages are readily identified. In the absence of a serious proposal for a specific hybrid organization, this alternative was dropped from further consideration. a III-21 ' Citic anni Saat PART IV — DEVELOPMENT OF SELECTED ORGANIZATIONAL ALTERNATIVES we ——a PART IV DEVELOPMENT OF SELECTED ORGANIZATIONAL ALTERNATIVES In the previous Part, two organizational alternatives, continuation of the existing arrangement and formation of a generation and transmission cooperative, were selected for further evaluation. In this Part a framework (structure) is outlined and key assumptions are developed for each of these organization types for use in the economic analysis. For each organization type, this part. reviews the study assumptions concerning the organization, staffing requirements, facilities, margin and TIER requirements, tax status, capital structure, existing debt, and the treatment of Chugach's lease agreements with Homer and Matanuska. It should be noted that the descriptions and assumptions presented here were intended to be used for study purposes. The specifics and detailed arrangements associated with a power supply organization which might actually be formed by the Cooperatives may not necessarily be consistent with the assumptions of this study. However, the assumptions made in this study are believed to be reasonable for purposes of economically comparing the two organization types. It should be noted that a major assumption of the economic analysis of this study is that the power supply facilities owned and operated on behalf of the Cooperatives would be identical under either form of organization. In comparing the existing arrangement to formation of a G&T cooperative, only the generation and transmission facilities owned by Chugach, general plant owned by Chugach which is allocable to the generation and transmission functions, and transmission facilities currently leased by Chugach from Homer and Matanuska Iv-1 were considered. This assumption was necessary (and reasonable) for study purposes to provide a consistent basis for comparison of the two organization types. By assuming that the power supply related facilities owned and operated would be identical under either a continuation of the existing arrangement or the formation of a G&T Cooperative, it was possible to focus the economic analysis (described in Part VI) on the major tangible items which could be expected to result in differences in wholesale power costs between the two alternatives. These major items included the G&T organization start-up costs, the additional staffing and administrative expense associated with the operation of a new G&T, and the difference in TIER requirements. Since the economic analysis focused on wholesale power costs, it was necessary to only define the existing wholesale power supply organization and then to describe the major incremental changes and resulting costs which would be incurred with the formation of a G&T. This Part first defines for study purposes the existing power supply organization and then discusses the assumed G&T organization with the focus on incremental differences. A major assumption of the economic analysis was that a new G&T would initially depend heavily upon the existing Chugach organization for staffing and logistic support. It was assumed this could be accomplished by contract between the G&T and Chugach. It was also assumed that the formation of a G&T would involve a small incremental staffing (combined requirement of Chugach and G&T) initially and that the incremental staffing requirement would grow until the G&T staff could operate independently. For study purposes the G&T was assumed to commence Iv-2 operating independently of Chugach support five years after its formation. In fact, the period of time which a new G&T would require before it could operate independently is difficult to predict although five years seemed to be a reasonable period of time for study purposes. In fact, it might be necessary or desirable for a G&T to depend upon Chugach for services for an indefinite period of time following its formation. EXISTING ARRANGEMENT Organization Continuation of the existing arrangement is assumed for study purposes. to involve no major change in the existing power supply operation and ownership relationship among the Cooperatives. Under this alternative, it is assumed that Chugach would continue to own all generation and transmission facilities, except those leased from Homer and Matanuska, and provide wholesale power to Homer and Matanuska. Construction of additional generation and transmission was assumed to be the responsibility of Chugach. Additional key assumptions concerning the existing arrangement are summarized below. Staffing In our evaluation of the existing organization arrangement, we included labor costs and expenses associated with operating and maintaining the existing generation, transmission and general plant facilities. All labor expenses incurred in the operation and maintenance of generation and transmission expenses were estimated based on past experience and the assumed inflation rate over the study period. The staffing and associated labor expenses for general and administrative functions associated with power supply operations were IV-3 estimated based on information in Chugach's October 1982 financial forecast. Labor cost and expenses associated with the Chugach distribution operations have not been included in this study's economic analyses. For study purposes it has been assumed that the staff requirements under the existing organizational arrangement would only change to accommodate additional personnel needed to maintain, upgrade and add generation plants, transmission facilities and general plant or to meet administrative and general obligations. Chugach's current Board of Directors and General Manager would continue to serve their respective positions for both the G&T and distribution functions. Under continuation of the existing arrangement we have assumed that the staffing under the general manager would also continue in its basic format without any major changes. A chart of a recently proposed organizational structure for Chugach is shown in Figure IV-1. Facilities Chugach's current power supply related facilities include the generation plant properties, transmission substation and line properties, and general plant facilities allocated to establishing the cost of power at the wholesale level. The properties identified in this study as power supply related property are summarized in Table IV-1. In addition to the various generation and transmission plant additions discussed in Part V of this report, Chugach is constructing a new headquarters facility and dispatch center. This facility is estimated to cost approximately $7.6 million. It is anticipated that Chugach would be able to move its staff into this facility by March 1984. We have Iv-4 S-AI FIGURE IV-1 PRELIMINARY ORGANIZATION STRUCTURE FOR CHUGACH (PROPOSED) (January 21, 1983) GENERAL MANAGER EXECUTIVE ASSISTANT rea ios fos EXECUTIVE SECRETARY TO GEN. MANAGER TO GEN. MANAGER LEGAL COUNSEL DIRECTOR DIRECTOR GOVERNMENT AND POWER SUPPLY ENVIRONMENTAL AFFAIRS DIRECTOR DIRECTOR ENGINEERING AND ACCOUNTING AND OPERATIONS FINANCE DIRECTOR ADMINISTRATIVE SERVICES ~y Table IV-1 SUMMARY OF EXISTING POWER SUPPLY RELATED PLANT ASSETS ASSUMING CONTINUATION OF EXISTING ORGANIZATIONAL STRUCTURE ($1,000 on December 31, 1982) Capitalized Accumulated Description Cost of Provision for of Facility Facility! Depreciation> Generation Plant: Beluga Station 109,895 Bernice Lake Power Plant 16,924 International Station 4,761 Subtotal (CT) 131,580 17,015 Cooper Lake Hydro Plant 7,818 3,373 Knik Arm Power Plant 7,944 6,011 ' Subtotal 147,342 26,399 Transmission Plant: Bulk Substations? 11,006 Step-up Substations? 5,051 Transmission Lines* 92,999 Subtotal 109,056 12,896 General Plant: 2,738 1,041 Total Power Supply Related Plant 259,136 40,336 1 Data taken from ‘‘Amendment of Power Supply Agreements, Chugach, Homer, and Matanuska, April 14, 1982."" 2 Includes (1) Quartz Creek, (2) Anchorage, (3) International, (4) Bernice Lake, (5) University, (6) Walter Teeland, (7) Pt. MacKenzie, (8) Pt. Woronzof. 3 Includes Knik Arm, Cooper Lake, Bernice Lake, International and Beluga. 4 Includes Knik Arm to Anchorage Substation (34.5 kV), Anchorage Line — Quartz Creek to Anchorage Substation (115 kV), International to University Substation (115 kV), Beluga Lines (138 kV), and Knik Arm Line (138 kV and 115 kV). 5 exniit E, page | of 1, Accumulated Provision for Depreciation of Electric Plant Step II, Chugach Electric Association, Inc., Application for Permanent Rate Relief, Volume III, 3/10/82. 6 Capitalized cost of facility less accumulated provision for depreciation. IvV-7 Net Plant Investment® 114,565 4,445 1,933 120,943 Outstanding Balance! 93,393 14,145 2,787 110,325 4,668 1,950 116,943 8,290 3,069 83,386 94,745 211,688 We have assumed for study purposes that one-half of this new facility would be included in Chugach's wholesale rate base. Chugach also owns a barge which it uses to lay and repair submarine transmission cables. This barge, known as the Susitna Barge, is moored in the Foss Shipyard in Seattle when not in use. The Susitna Barge was used to lay and bury the 138-kV submarine cables under the Knik Arm. We have assumed that carrying charges are combinéd with the operation and maintenance expenses for the barge and included in wholesale expense allocations. Financing and Rates Chugach is temporarily operating under a 1.15 minimum TIER requirement. This TIER requirement has been approved by both REA and CFC in order to relieve Chugach's recent financial difficulties. Since this TIER requirement is only temporary, we have assumed that REA and CFC would once again require a minimum TIER of 1.50 for all Chugach loans in 1984 after the 1.15 TIER contract provision expires on December 31, 1983. Therefore, revenue requirements have been assumed to increase on December 31, 1983 in order to provide margins necessary to maintain a 1.50 minimum TIER. However, maintenance of a 1.5 minimum TIER requires a cooperative to target a higher average TIER level to account for uncertainty and regulatory lag. Based on discussions with the Chugach staff, we have assumed Chugach will strive for a TIER target of 2.0. This was the TIER level used in the economic analyses performed as part of this study. Iv-8 wow Pe | aé ae Chugach currently maintains a capital structure consisting of long-term debt and patronage capital. The long-term debt issued to finance G&T facilities consists of 2 percent and 5 percent loans from the REA's insured loan program and guaranteed loans at various interest rates from the Federal Financing Bank (FFB). The patronage capital consists of accrued margins which Chugach's members have accumulated to date. Under the existing organizational structure, we have assumed that Chugach would continue to finance additional G&T projects through issuance of REA insured and FFB guaranteed loans. Chugach would also continue to raise capital internally through collection of patronage capital included in members' electric rates. Operation of Facilities Chugach currently operates and maintains the existing generation facilities which provide power to the Cooperatives. Chugach also operates and maintains the transmission facilities which it owns. We have assumed that under a continuation of the existing arrangement the transmission facilities owned by Homer and Matanuska, but leased to Chugach, will continue to be operated by Homer and Matanuska. The operation and maintenance expenses on these facilities would continue to be billed to Chugach. Additionally, we assumed Chugach would continue to pay appropriate insurance and tax expenses. Chugach currently provides dispatching for power delivered to Homer and Matanuska wholesale power delivery points. Chugach would continue to maintain this responsibility and its responsibility to dispatch power to its own retail customers. Iv-9 Lease Agreements With Homer and Matanuska Homer and Matanuska currently lease transmission substation and line facilities to Chugach. A description of the leased facilities is provided in Part II of this report. These lease agreements specify that Chugach will pay Homer and Matanuska for interest and depreciation expense for the facilities leased. Additionally, Chugach must pay a 15 percent coverage expense on the interest payments, thus providing a TIER of 1.15 on the leased facilities. We have assumed that once the lease agreement expires on December 31, 1983, the coverage on the lease payments would increase to 50 percent in order to provide a 1.50 TIER. GENERATION AND TRANSMISSION COOPERATIVE Formation of a G&T cooperative would involve several key changes in power supply arrangements among the Cooperatives. Formation of a G&T cooperative most importantly involves the separation of Chugach's administration and operations into distribution and G&T functions. We have assumed for study purposes that formation of a G&T could be approved by the Cooperatives prior to December 31, 1983 and that the G&T cooperative would begin functioning in January 1984. As indicated previously, we have also assumed the new G&T would contract with Chugach to provide staffing and logistic support during the early years following its formation. For study purposes we have assumed the G&T would begin to operate as a totally independent entity within five years after its formation. More detailed information on the ensuing transition is provided below. IV-10 ween | i os Organization Start-Up Costs A number of activities would need to be accomplished in effecting a transfer of G&T facilities, staff and operations from the umbrella of Chugach as it exists today to a separate G&T entity. This section categorizes these activities and provides an estimate of the expenses which would be incurred by the G&T primarily for outside services before a new G&T would be in full operation. Estimated expenses for starting-up a G&T are as follows: Studies $125,000 Legal fees, research and negotiation 250,000 Accounting fees 35,000 Public and member relations costs (including meetings) 75 ,000 Other 65,000 Total $550,000 The total estimated expenses for organizing a G&T, exclusive of incremental Gé&T staff labor expenses, are $550,000. These expense estimates are based on conversations with Chugach personnel and past experience. In our economic analysis, these expenses have been spread over 1983, 1984 and 1985. Staffing The Chugach operations staff currently carries out the generation and transmission responsibilities necessary to supply the bulk power requirements of the Cooperatives. Chugach also has an administrative staff to carry out the accounting, engineering, customer service, planning, and general management of the G&T operations and the distribution of power to both wholesale and retail customers. In estimating additional staffing requirements, it has been assumed IV-11 that the formation of a G&T cooperative would eventually involve a _ complete separation of staffs to handle each of these functions. In order to separate the distribution and the G&T operations of Chugach, a series of activities would have to be completed. A preliminary list of these activities is provided in Part VII of this report. Additional staffing costs which would be incurred in forming a G&T cooperative relative to continuation of the existing arrangement will not be well defined until a detailed implementation plan has been developed. For purposes of evaluating this organizational alternative, we have assumed that the existing production, transmission and headquarters staff mecessary to provide wholesale electric service would be retained, however, the time of individuals would initially be allocated in whole or in part, as appropriate, to either the Chugach distribution system or to the G&T cooperative. Eventually, the time of all staff would be dedicated entirely to one of the two organizations. In estimating the incremental staffing requirements for a G&T, we looked at the combined requirements of Chugach and the proposed G&T for the day after the formation of a cat and five years after the formation of a G&T. We assumed that the day after the G&T is formed, Chugach and the new G&T would be an integrated organization sharing most of their staffing requirments but with some additional staff being brought on board and dedicated primarily to working with the G&T. We further asssumed that in five years, the G&T and Chugach would be split into two separate organizations. Figures IV-1 and IV-2 show the resulting overall organization charts we developed based upon proposed organization charts for Chugach dated January 21, 1983. We should note that we looked not only at the IV-12 = - - - ae —_—_— ——- ay aay ae el FIGURE IV-2 ASSUMED ORGANIZATION STRUCTURE CHUGACH AND G&T (Day After G&T Formation) GENERAL MANAGER j EXECUTIVE ASSISTANT | G&T —— — — — — — — | opERATIONS —| L_____-_] €T-Al EXECUTIVE ASSISTANT TO GEN. MANAGER DIRECTOR DIRECTOR ENGINEERING AND ACCOUNTING AND DIRECTOR DIRECTOR GOVERNMENT AND POWER SUPPLY OPERATIONS FINANCE ENVIRONMENTAL AFFIARS ‘gased upon review of Preliminary Organization Structure for Chugach dated January 21, 1983. staffing requirement for G&T was estimated to be seven persons. pce ta EXECUTIVE SECRETARY, TO GEN. MANAGER LEGAL COUNSEL DIRECTOR ADMINISTRATIVE SERVICES Total incremental iia ae overall organization charts shown in Figures IV-1 and IV-2, but also at six additional charts which broke the overall staffing down into the executive and major operating functions of Chugach in determining incremental staffing requirements. Figure IV-2 is the assumed Chugach organization the day after the formation of a G&T cooperative. As can be seen, we assumed that the Chugach organization remains essentially intact except that we have added an executive assistant for G&T operations. In addition, we have added six additional personnel not shown on this chart, but identified in Table IV-2, for a total incremental staffing of seven people. The incremental staffing is estimated to cost an additional $500,000 per year in 1983 dollars including salaries, fringe benefits, and office expenses. Figure IV-3 is the organization chart we have developed for the G&T alone five years after the formation of the G&T. As can be seen, we have assumed that the overall GaT organization would be identical to that currently proposed for Chugach (Figure IV-1). This appeared to be reasonable because in comparing the proposed Chugach organization chart with that of a typical G&T cooperative, most of the major functions currently being performed for Chugach would also have to be performed for the new G&T. However, it is likely that the actual titles and responsibilities of the positions for a G&T, as it might eventually be constituted, would differ from those presented in Figure IV-3. By comparing the organization charts we developed for Chugach and the G&T, we have estimated a permanent incremental staffing requirement five years after the formation of a G&T of 25 people. The identies of the estimated additional staff are provided Iv-15 Table IV-2 PROJECTED INCREMENTAL STAFFING Hl FOR CHUGACH AND G&T Staff Position Staff Position Day After G&T Formed No. Five Years After G&T Formed No. Executive Assistant of General Manager 1 G&T Operations 1 Executive Assistant to Staff Assistant 1 General Manager 1 Secretary 1 Executive Secretary 1 Manager of G&T Attorney i Accounting Director of Government Assistant Manager of Affairs 1 G&T Accounting Director of Engineering Accountant and Operations 1 , Account Clerk Director of Accounting i Total and Finance Director of Administrative Services Clerk Typist Reference Material Clerk Manager of Human Resources Purchasing Agent Manager of Information Services Secretary Auditor Controller Budget/Financial Analyst Rate Analyst Accountants Clerk Secretary Manager of Operations Secretary Total ~ athe ee 8 | UY oil Iv-16 oa LT-AI Ss —s — eal — _ FIGURE IV-3 ASSUMED ORGANIZATION STRUCTURE G&T ALONE! (Five Years After G&T Formation) GENERAL MANAGER EXECUTIVE SECRETARY TO GEN. MANAGER EXECUTIVE ASSISTANT LEGAL COUNSEL TO GEN. MANAGER DIRECTOR DIRECTOR DIRECTOR DIRECTOR POWER SUPPLY ENGINEERING AND ACCOUNTING AND GOVERNMENT AND ENVIRONMENTAL OPERATIONS FINANCE AFFAIRS lgased upon review of Preliminary Organization Structure of Chugach dated January 21, 1983. staffing requirement for G&T was estimated to be 25 persons. DIRECTOR ADMINISTRATIVE SERVICES Total incremental mae: co nec in Table IV-2. The incremental annual cost for this staffing is estimated to be $2.0 million per year in 1983 dollars. Facilities It is assumed the G&T would take over the ownership, operation and maintenance of the generation, transmission and power supply related general plant facilities currently owned and operated by Chugach. In addition to the power supply facilities currently owned by Chugach, we have assumed certain transmission assets leased to Chugach from Homer and Matanuska would also become property of the G&T cooperative. These facilities and Chugach's existing power supply-related facilities are summarized in Table IV-3. As was the case for the existing arrangement senario, we have assumed for study purposes that one-half of the new Chugach office building and dispatch center would be allocated to power supply function. Financing and Rates The TIER requirements for a G&T cooperative have been assumed to be a minimum of 1.0. This TIER requirement would apply to interest on all loans associated with generation, transmission, and general plant facilities included in the Gé&T cooperative's wholesale rate base. However, it would be prudent for a G&T to maintain operating margins (maintain an average TIER greater than 1.0) to provide financial flexibility and to cover operating expenses in the interim period between filings for wholesale rate increases and the time when the rate relief is actually granted. Thus, a TIER level of 1.2 was used in this study as representing a reasonable TIER target level for a G&T cooperative. Iv-19 Table IV-3 SUMMARY OF EXISTING POWER SUPPLY RELATED PLANT ASSETS ASSUMING FORMATION OF G&T COOPERATIVE ($1,000 on December 31, 1982) Capitalized Accumulated Description Cost of Provision for of Facility Facility Depreciation Generation Plant (Existing Chugach):/ Beluga Station 109,895 Bernice Lake Power Plant 16,924 International Station 4,761 Subtotal (CT) 131,580 17,015 Cooper Lake Hydro Plant 7,818 3,373 Knik Arm Power Plant 7,944 6,011 Subtotal 147,342 26,399 Transmission Plant:?! Bulk Substations 11,006 Step-up Substations 5,051 Transmission Lines 92,999 Subtotal 109,056 12,896 General Plant: 2,738 1,041 Transmission Plant (Currently owned by Homer):? Substations 1,078 Transmission Lines 4,981 Subtotal 6,060 1,329 Transmission Plant (Currently owned by Matanuska):* Substations 358 39 Transmission Lines 1,474 296 Subtotal 1,832 335 Total Power Supply Related Plant 267,028 42,000 1 Data for Generation Plant, Transmission Plant, and General Plant taken from Table IV-1. 2 From “Analysis of Debt Service Equivalent for CEA Leased Plant,”’ see information correspondence from Homer Electric Association, Inc., October 18, 1982. s Estimated from ‘‘Analysis of Debt Service Equivalent for CEA Leased Piant,”’ see information correspondence from Matanuska Electric Association, Inc., December 16, 1982. Iv-20 Net Plant Investment 114,565 4,445 1,933 120,943 96,160 1,697 4,731 319 1,178 1,497 225,028 Outstanding Principal Balance 93,393 14,145 2,787 110,325 4,668 1,950 i 116,943 8,290 ‘ 3,069 83,386 94,745 4 Additionally, existing interest and depreciation expenses related to transmission properties formerly owned by Homer and Matanuska and leased by Chugach would be included in expenses passed on to the wholesale customers. It was assumed that operation and maintenance expenses on these transmission properties would be borne by the new G&T cooperative. The only accrued patronage capital or equity assumed to be included on the new G&T cooperative's books is that which is currently being recovered through the patronage capital contributions of the three Cooperatives (15 percent of interest expense) under current rates. This patronage capital has only been recovered since July 1982 when the amended power sales contracts with Homer and Matanuska were implemented. We have assumed that additional patronage capital based on a 1.15 TIER will continue to be collected through wholesale rates through December 31, 1983. We understand the intent of the power sales contracts in effect prior to April 1982 was to only recover power costs (i.e., no patronage capital) from Homer and Matanuska. We have assumed that all patronage capital collected from Chugach's retail consumers would be retained by the Chugach distribution cooperative. Patronage capital paid in by retail customers would be returned to these customers based on a future capital credits retirement policy. As can be seen in Table IV-3, the net book value of investment in G&T plant is approximately $225.0 million. The amount of net book value is approximately $7.6 million greater than the outstanding loan balance of $217.4 million on G&T-related property. Therefore, in order for the G&T cooperative to be “made IV-21 whole" this imbalance should be resolved among the Cooperatives before forming a Gat. Because there are many possible ways in which this imbalance might be resolved and because it appeared to have relatively little impact on the fundamental comparison we were attempting to make, the imbalance was ignored in this study. It as assumed the G&T cooperative could borrow additional funds as _ required under the REA guaranteed loan program. Additional patronage capital would be collected from the G&T cooperatives’ members based on a target TIER requirement of 1.2. The members under a G&T cooperative arrangement would include Homer, Matanuska, and Chugach as distribution cooperatives. Operation of Facilities The G&T cooperative would operate and maintain the existing generation facilities which provide the majority of the Cooperatives’ current power supply. It was assumed the G&T cooperative would operate and maintain the transmission facilities which Chugach currently owns and also those which are currently leased by Chugach from Homer and Matanuska. Contractual Agreements It was assumed that Chugach's existing contractual agreements with fuel suppliers, wholesale power purchasers and the Alaska Power Administration would be assigned to the G&T cooperative. Additionally, the G&f cooperative would have to negotiate a new power sales contract with the resulting Chugach distribution cooperative. Under formation of a G&T cooperative, we have assumed that review and negotiation of any existing contractural agreements would take IV-22 Nrsereenronnes vevinas) om were pence ~~ acy place in the 1984 to 1986 time frame. We have included the estimated legal fees for development, review and negotiation of new wholesale power sales contracts with Homer, Matanuska, and the Chugach distribution cooperative as described under G&T "Organization Costs" above. Additionally, new contracts may be necessary for wholesale power sales to other wholesale customers. eee He IV-23 — —— ‘ — ' PART V — DEVELOPMENT OF POWER _ SUPPLY EXPANSION PLANS = pata ae my Lm PART V DEVELOPMENT OF POWER SUPPLY EXPANSION PLANS This part discusses the projected power requirements, the power supply alternatives available to meet these future power requirements, the development of specific power supply expansion plans and the future transmission requirements of the Cooperatives. PROJECTED POWER REQUIREMENTS In order to develop and evaluate power supply plans for the Cooperatives, a load forecast (projection of demand and energy requirements) was first prepared. The load forecast was then compared to existing generation resources in order to develop power supply expansion plans with adequate new generation. The load forecast developed in this Part extends over the 1983-2002 time frame. The projected demand and energy requirements for the Cooperatives used in this study are based on projections developed by the "Railbelt Electric Power Alternatives Study: Evaluation of Railbelt Electric Energy, Plans," a March 1982 study performed by Battelle Pacific Northwest Laboratories for the Alaska Power Authority. The Battelle study developed high-, medium-, and low-range load forecasts for the railbelt area of Alaska. The peak demand forecast used in this Organizational Study is based on Battelle's medium-range forecast over the 1980-2000 time frame. The medium-range forecast assumes an average annual compound demand growth rate of 3.4 percent for the railbelt area from 1980 through 2000. v-1 The energy forecast used in this study is based on the demand forecast described above and a load factor projection for the Cooperatives. The annual load factor for the Cooperative is assumed to be 50.0 percent in 1983 and to increase linearly to 52.0 percent by 2002. This load factor projection represents an estimate for study purposes by the Cooperatives’ staffs. The energy forecast for the Cooperatives, based on the given demand forecasts and load factors, increases at an average annual growth rate of 3.6 percent per year over the time period 1983-2002. The 1982-1983 winter peak demand, 380 MW, and the 1982 annual energy requirement, 1,664 GWh, of the Cooperatives have been estimated by the Chugach staff. The projected demand and energy requirements are shown in Table V-1. The Cooperatives’ historical demand and energy for the eleven-year period 1971 through 1981 are also shown in Table V-1. Prior to 1982 (1971-1981), the annual peak demand and energy requirements increased at an average compound rate of about 13 and 12 percent, respectively. In addition to the Cooperatives’ generation resources necessary to meet peak demand requirements, additional capacity resources must be developed to provide reliable electric service. Provisions for reserve margins were added to the Cooperatives’ peak demand requirements in determining the level of capacity resources required to provide reliable service. Reserves were estimated as 15 percent of the Cooperatives' peak demand or the single largest generation contingency outage, whichever was larger. V-2 eon vere wcrc Table V-1 LOAD PROJECTION FOR THE COOPERATIVES! Peak Demand Annual Energy Loed Calendar Percent Millions Percent Factor Year mw? Increase of KWh Increase (Percent) 1971 108.2 _ 519 _ _- 1972 135.9 25.6 600 15.6 50.4 1973 184.6 35.8 672 12.0 41.6 1974 182.5 (d-4) 708 5.4 44.3 1975 220.0 20.5 889 25.6 46.1 1976 217.6 (1.1) 1,091 22.7 57.2 1977 273.9 25.9 1,236 13.3 51.5 1978 283.8 3.6 1,351 9.3 54.3 1979 304.6 7.3 1,449 7.3 54.3 1980 337.4 10.8 1,492 3.0 50.5 Historical 1981 352.2 4.4 1,545 3.6 50.1 1982 380.0 7.9 1,6643 7.7 50.0 Projected 1983 393.0 3.4 1,725 3.6 50.1 1984 406.5 3.4 1,790 3.6 50.2 1985 420.5 3.4 1,851 3.6 50.3 1986 434.9 3.4 1,921 3.6 50.4 1987 449.8 3.4 1,991 3.6 50.5 1988 465.2 3.4 2,061 3.6 50.6 1989 481.2 3.4 2,136 3.6 50.7 1990 497.7 3.4 2,216 3.6 50.8 1991 514.8 3.4 2,296 3.6 50.9 1992 532.4 3.4 2,377 3.6 51.0 1993 550.7 3.4 2,466 3.6 51.1 1994 569.6 3.4 2,557 3.6 51.2 1995 589.1 3.4 2,647 3.6 51.3 1996 609.3 3.4 2,742 3.6 51.4 1997 630.2 3.4 2,842 3.6 51.5 1998 651.8 3.4 2,947 3.6 51.6 1999 674.2 3.4 3,052 3.6 51.7 2000 697.3 3.4 3,163 3.6 51.8 2001 721.2 3.4 3,278 3.6 51.9 2002 746.0 3.4 3,398 3.6 52.0 Average Annual Compound Growth Rate (1983-2002): 3.43%? 3.63% i Historical data obtained from ‘‘Electrical World Directories’’ and the Cooperatives’ Form 7s. 2 Growth rate (3.43 percent) taken from Medium Economic Growth, Peak Demand, ‘‘Railbelt Electric Power Alternative Study: Evaluation of Railbeit Electric Energy Plans, "’ Battelle Pacific Northwest Laboratories, February 1982. s Estimated by Chugach staff. 4 Peaks assumed to occur during winter months in the latter part of each calendar year. Currently, Chugach's single largest generation outage contingency is Beluga 6 or Beluga 7 and one-half of Beluga 8. This combination of Beluga 6 and 8 or Beluga 7 and 8 results from using waste heat from Beluga 6 and 7 to drive Beluga 8. If either Beluga 6 or 7 is out of service, one-half of the waste heat supply to drive Beluga 8 is also not available. The determination of Beluga 6 or Beluga 7 and one-half of Beluga 8 as the single largest outage is based on the assumption that Beluga Units 1, 2 and 4 would be in operation at the occurrence of the Cooperatives’ peak demand. If Beluga 1, 2 and 4 were not in operation at the time of the Cooperative's peak demand, these units would be available to replace Beluga 6 or Beluga 7 and one-half of Beluga 8 during an outage of these units. This assumption hinges on Chugach having a natural gas supply for operating Beluga 1, 2 and 4 other than that available under the current long-term contract for gas from the Beluga River Field. The total capacity requirements for the Cooperatives equal the sum of the reserve requirement and the peak demand. These requirements are summarized on Table V-2. PROJECTED CAPACITY DEFICITS The existing generation and purchased power resources described in Part II, and the total capacity requirements described above were used to estimate the Cooperatives’ incremental future capacity requirements. Table V-2 shows the balance of the Cooperatives’ projected loads and resources. Figure V-1 graphically shows the Cooperatives' existing generation and Alaska Power Administration purchase. The projected load, including the Cooperatives’ reserve requirement, is also shown. ot he 2 Pa eS ass: me oy owe Calendar Peak Year Demand 1983 393.0 1984 406.5 1985 420.5 1986 434.9 1987 449.8 1988 465.2 1989 481.2 1990 497.7 1991 514.8 1992 532.4 1993 550.7 1994 569.6 1995 589.1 1996 609.3 1997 630.2 1998 651.8 1999 674.2 2000 697.3 2001 721.2 2002 746.0 BALANCE OF PROJECTED LOADS AND RESOURCES Table V-2 FOR THE COOPERATIVES (MW) (3) (4) Peak Demand Less Firm Reserve Purchases Requirement 379.0 97.0 392.5 97.0 406.5 97.0 420.9 97.0 435.8 97.0 451.2 97.0 467.2 97.0 483.7 97.0 500.8 97.0 518.4 97.0 536.7 97.0 555.6 97.0 575.1 97.0 595.3 97.0 616.2 97.0 637.8 97.0 660.2 99.0 683.3 102.5 707.2 106.1 732.0 109.8 (5) Capacity Responsibility 532.8 548.2 564.2 580.7 597.8 615.4 633.7 652.6 672.1 692.3 713.2 735.5 761.2 787.8 815.3 843.8 (6) Generation Resources 518.2 518.2 518.2 518.2 518.2 518.2 518.2 518.2 518.2 518.2 518.2 518.2 518.2 518.2 518.2 518.2 518.2 518.2 518.2 518.2 @ Percent growth (3.43 percent) taken from Medium Economic Growth, Peak Demand, ‘‘Railbelt Electric Power Alternative Study: Evaluation of Railbeit Electric Energy Plans, ''Battelle Pacific Northwest Laboratories, February 1982. (2) Represents Chugach’s 9 MW and Matanuska’s 5 MW of firm capacity from the Alaska Power Administration. © Column 1 — Column 2. @ Represents the larger of the Cooperative's single largest generation outage or 15 percent of Column 3 (peak demand less firm purchases) ©) Column 3 + Column 4. 6) Based on current capacity resources and scheduled unit retirements. Column 6 — Column 5. (7) oS Surplus (Deficit) 42.2 28.7 14.7 0.3 (14.6) (30.0) (46.0) (61.8) (79.6) (97.2) (115.5) (134.4) (153.9) (174.1) (195.0) (217.3) (243.0) (269.6) (297.1) (325.6) POWER SUPPLY ALTERNATIVES The power supply resources which may be utilized to meet the Cooperatives’ future load growth include installation of gas turbines, participation in the planned Anchorage-to-Fairbanks transmission intertie, purchases from proposed State of Alaska projects, participation in gas-fired combined-cycle units, and participation in coal-fired generating units. Following descriptions of the supply alternatives available, we describe the three exploratory power supply expansion plans developed. Proposed Gas Turbine Installation Chugach tentatively plans to install a 64-MW gas turbine at the existing Beluga site in 1984 (Beluga 9) and a 37-MW gas turbine at the existing Bernice Lake plant site in 1985 (Bernice Lake 5) to meet the short-term load requirements of its customers. The estimated capital and operating costs, along with other information, for this unit are summarized in Table V-3. The capital costs include the costs of construction, engineering, owner's overhead, initial inventories and financing requirements. Anchorage-Fairbanks Transmission Intertie The Anchorage-to-Fairbanks transmission intertie will provide electrical interconnection between the Anchorage and Fairbanks area upon its scheduled completion in late 1984. The intertie is currently being designed and built as a 345-kV transmission line which will initially be energized at 138 kV and is planned to provide a 70-MW transfer capability between the two areas. The State of Alaska has appropriated approximately $80 million for the construction of this project. Additional funds of approximately $55 million are projected to be v-6 L-A (MW) FIGURE V-I BALANCE OF PROJECTED LOADS AND RESOURCES FOR THE COOPERATIVES 988.8 1858.8 1288.8 758.8 = s & 2 os wn aa e a a EXISTING GENERATION 2 a = 2 os TT T T ~ ee T T oe mal 1983 (98S 1967 i969 i991 i993 i995 1997 1999 2881 2883 YEAR Table V-3 PROFILES OF GENERATION ALTERNATIVES Operation & Maintenance Average Fuel information (19839) Net Net Annual Price Capital Cost? In Service Capacity Heat Rate = Availability (1963 Fixed Variable (1983) Unit Date (MW) (Btu/kWh) (%) Type ¢/MMBtu) (9/kW) (milis/kWh) ($/kW) Beluga 9 1984 64 12,000 83.1 Inlet/North Slope 150/639 8.43 0.56 370 Natural Gas Bernice Lake 5 1985 37 12,000 83.1 Enstar/North Slope 159/639 5.37 0.36 370 Natural Gas 200 MW Coal-Fired Unit 1990 200 10,000 80.3 Coal 164 38.30 2.73 2,536 200 MW Gas-Fired Combined Cycle Unit 1990 200 8,600 86.0 North Slope 639 15.50 1.10 1,255 Natural Gas 1 Represents scheduled in-service data for Bernice Lake 5 and Beluga 9 and anticipated earliest in- service date for 200 MW coal and 200 MW gas combined-cycle units. 2 Information concerning the capital cost of the 200 MW gas-fired combined cycle unit is based upon information provided in the ‘‘Natural Gas-Fired Combined Cycle Power Plant Alternatives for the Railbelt Region of Alaska,'’ dated June, 1982 by Battelle. The balance of the information on the table is generic information developed by Burns & McDonnell. These estimates represent Burns & McDonnell's professional judgement based on our knowledge of the project, experience, and familiarity with the power industry. Since we have no control over the cost of material and labor, the competitive bidding process, market conditions, weather, changes in applicable government regulations and laws, labor supply, labor interruptions, or other unavoidable delays or actions, we cannot guarantee that project construction costs and schedules for actual projects of this type will not vary from the cost estimates and schedules we have developed. required to complete the intertie. These funds may be issued through either an additional State grant or public financing. For this study, it was assumed that there would be no recovery of capital charges incurred in construction of the intertie. However, for study purposes, it was assumed that the participating utilities would be responsible for operation and maintenance costs of the intertie. This cost has been estimated at $14 per kW-year in 1984 dollars. The intertie will have the potential of providing economic benefits to electric customers in the Anchorage and Fairbanks areas. These benefits include reduced power costs through economy interchanges and reserve sharing. In this study it was assumed that the Cooperatives would be allocated approximately 51 MW of reserve capacity from the intertie, with the remaining 19 MW allocated to ML&P. These capacity allocations are based on historical load relationships between the Cooperatives and ML&P. The impact of economy interchanges was not addressed in this study since any benefits could be expected to be independent of power supply organization type. State of Alaska Generation Projects Major hydroelectric generating alternatives currently being considered by the State of Alaska include the Bradley Lake, Susitna and Chakachamna hydroelectric projects. These proposed projects are located in or near the Cooperatives' service areas and the Cooperatives are expected to be allocated capacity and energy from these projects if constructed. The State of Alaska has also appropriated funds for construction of a transmission intertie between Fairbanks and Anchorage as discussed above. V-10 ere meee heneeniat aie NS hie e. 4 The proposed Bradley Lake Project is a hydroelectric project with a scheduled in-service date of 1988. Plans call for the project to be constructed as either a 60-, 90- or 135-MW plant. Based on analyses and studies performed for the Alaska Power Authority, we have assumed that the Bradley Lake project would have an installed capacity of 155 MW and operate at an average annual capacity factor of 30 _ percent. This project would be constructed in Homer Electric Association's service area by the Alaska Power Authority but no funds have been allocated for construction by the Alaska legislature. In order to plan capacity available to the Cooperatives from the Bradley Lake project, we have assumed that the output of the plant would be shared by utilities serving the Anchorage-Kenai, Fairbanks and Valdez areas proportionate to these areas’ historical loads. We have also assumed reserves of 15 percent would be required on capacity received from the project, leaving a net capacity of 68 MW to the Cooperatives. The proposed Susitna Hydro Project, if constructed, would eventually consist of two dams, one at Watana which would be used to develop hydro facilities with 680 MW of capability scheduled to go on line in 1993 and an additional 340 MW in 1994. Based on Acres American's "Susitna Hydroelectric Project--Summary Report," of March 1982, we have assumed that the Watana portion of the Susitna Project would operate at an average annual capacity factor of 40 percent. Another dam at Devil Canyon would have approximately a 600-MW capability and is scheduled to go on line in 2002. Capacity allocations from the Watana portion of the Susitna Project have been allocated to utilities in Alaska based on the utilities’ respective loads. V-11 Cost estimates prepared by consultants for the Alaska Power Authority project the Watana portion of the Susitna Project to cost approximately $3.65 billon excluding interest during construction in 1982 dollars. Cost estimates for the Watana portion of the Susitna Project used in this study are based on Acres American's "Susitna Hydroelectric Project--Summary Report” dated March 1982 for the Alaska Power Authority. A scenario involving partial funding for the project by the State of Alaska has been assumed. This scenario assumes’ the state would fund approximately 45 percent of the project ($1.64 billion of the estimated $3.65 billion) and that the remaining 55 percent would be funded through issuance of tax-exempt bonds. In estimating the total cost of power from the project, we have included an estimate of interest during construction on funds assumed to be provided by the tax-exempt bonds. The sum of the funds issued through the State's grant program ($1.64 billion), the principal amount of the tax-exempt bonds ($2.01 billion), and interest expense during construction on the tax-exempt bonds ($0.93 billion) represents the estimated capitalized cost of the Watana portion of the Susitna Project in 1982 dollars. The total capitalized cost of the project is assumed to be amortized over a 50-year period. Interest on the tax-exempt bonds has been assumed at a rate of 10 percent. The Chakachamna Project, if constructed, would have approximately a 330-MW capability. The main problems anticipated with construction of the Chakachamna facility may be environmental problems and opposition by fisheries in the area where construction would take place. If the Susitna Project is constructed, the Chakachamna Project would probably not be constructed during the study period V-12 aoe ee ~~ due to the enormous funding required for each project and a lack of need for the capability of both projects. Other projects currently considered by the Alaska Power Authority include coal gasification and construction of combined-cycle plants in the North Slope area. These projects are still highly uncertain at this time and have not been considered in the power supply plans for this Organizational Study. Natural Gas-Fired Combined-Cycle Plants Gas-fired combined-cycle plants are expected to be commercially available in Alaska during the 1988-1990 time frame based on Battelle's June 1982 comment draft working paper No. 3.6, "Natural Gas-Fired Combined-Cycle Power Plant Alternative for the Railbelt Region of Alaska." These plants consist of combustion turbines that drive electric generators. Heat recovery boilers use exhaust heat from the turbines to drive a steam turbine generator. Estimated costs for a 200-MW combined-cycle unit are summarized in Table V-3. Coal-Fired Generating Units Although Chugach does not currently have any coal-fired generation, studies have been performed on the quality of coal near the Beluga Generating Station. These studies indicate that the Beluga Field could be economically opened with the establishment of an export market or development of approximately 800 MW of coal-fired generation. The cost of coal for the Organizational Study was based on these premises as presented in Battelle's draft, "Railbelt Electric Power Alternatives Study: Fossil-Fuel Availability and Price Forecasts," March 1982. V=-13 Estimated costs for a 200-MW net coal-fired steam-electric generating unit are summarized in Table V-3. DEVELOPMENT OF POWER SUPPLY EXPANSION PLANS In this study, three exploratory power supply expansion plans were developed in which long-term (1990-2002) power supply expansion would consist primarily of either hydroelectric, natural gas-fired or coal-fired generation. Each plan was developed assuming short-term (1983-1989) incremental power supply requirements would be met by the installation of a 64-MW gas turbine in 1984 (Beluga 9), a 37-MW gas turbine in 1985 (Bernice Lake 5), 51-MW of the proposed Anchorage- Fairbanks intertie and the purchase of approximately 68 MW of firm power from the Bradley Lake project beginning in 1988. Gas turbines were selected for short-term expansion because of the short lead time required for their installation and the current availability of natural gas in the Cook Inlet area. Costs for these gas turbines are summarized in Table V-3. The Bradley Lake project was selected because design and construction of this project is being pursued by the State of Alaska. Capacity from this project was assumed to be allocated to the utilities serving the Anchorage-Kenai, Fairbanks and Valdez areas as shown in Table V-4. These allocations were based on the historical relationship between these utilities’ loads. The projected purchased power costs for the Bradley Lake project are shown in Table V-5. The three long-range expansion plans developed in this study are summarized in Table V-6 and described below. V-14 ' ' ene ome ‘Project _ Bradley Lake * Susitna Project Phase 1 Watana Susitna Project Phase 2 Watana 4 From 1981-1982 Edition of the ‘‘Electrical World Directory.’’ Net (MW) 1173 680 Table V-4 ASSUMED ALLOCATION OF CAPACITY FROM STATE OF ALASKA PROJECTS Scheduled In-Service Date 1988 1993 1994 Utility The Cooperatives* Anchorage Municipal Light & Power Copper Valley Electric Association Golden Valley Electric Association Fairbanks Municipal Utilities System The Cooperatives‘ Anchorage Municipal Light & Power Copper Valley Electric Association Golden Valley Electric Association Fairbanks Municipal Utilities System The Cooperatives* Anchorage Municipal Light & Power Copper Valley Electric Association Golden Valley Electric Association Fairbanks Municipal Utilities System ‘ 2 Project's net capacity * Utility's Peak Demand/Sum of utilities’ peak demands. ; s Net capacity from project after allowance of 15 percent reserve capacity. ’ Chugach Electric Association, Homer Electric Association & Matanuska Electric Association. v-15 Peak Demand? (MW) 304.6 111.4 7.5 70.0 29.3 304.6 111.4 7.5 70.0 29.3 304.6 111.4 7.5 70.0 29.3 Allocated (MW) Year 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 Capacity! $/kW-Year 365 365 366 366 366 367 367 367 368 368 369 369 370 370 371 PROJECTED PURCHASED POWER COSTS Bradley Lake Energy Mills/kWh 5.4 5.8 6.3 6.8 7.4 7.9 8.6 9.3 10.0 10.8 11.7 12.6 13.6 14.7 15.9 Table V-5 Total Mills/kWh? 144.3 144.7 145.6 146.1 146.7 147.6 148.3 149.0 150.0 150.8 152.1 153.0 154.4 155.5 157.1 Capacity! $/kW-Year 781 781 782 782 783 783 784 784 785 785 1 Based on fixed operation and maintenance expense and 50 year amortization of capitalized plant costs. Capital costs based on estimates made by Battelle Pacific Northwest Laboratories with 45 percent financing by Alaska Power Authority and 55 percent financing using 10 percent tax-exempt bonds. 2 Sum of capacity and energy costs assuming operations at a 30 percent capacity factor. 3 sum at -capacity and energy costs assuming operation at a 40 percent capacity factor. V-16 Susitna Energy Mills/kWh 6.8 7.3 7.9 8.5 9.2 9.9 10.7 11.6 12.5 13.5 Total Mills/kWh? 229.7 230.2 231.1 231.7 232.7 233.4 234.4 235.3 236.5 237.5 - - 4 —— - - i — ~ ws mo 94 vr -— Ps ae | al wy = a Table V-6 SUMMARY OF POWER SUPPLY EXPANSION SCENARIOS CAPACITY ADDITIONS (mw) Expansion 12 2013 2014-2016 Scenario 1984 1986 1986-1987 1988 1989-1992 1983 1994 1996-2000 2001 2002 2003-2007 2008 2009-201 Gas ect! = 37cT? o 68H? o ° ° o 100 cc* o ° 200 cc* o 200 cc* o Coal eact! 37cT? o 68H? o 0 e o 100 cs* 0 o 200 cs* o 200 cs* ° Hydro eact! s7 Cr” 0 esn? 0 330 H¢ 165 n¢ 0 0 26207 0 0 0 0 0 z ey N 1 Beluga 9. CT — Combustion Turbine 2 Bernice Lake 5. H — Ryareebetiic 3 Assumed Chugach allocation of Bradley Lake Hydroelectric project. CC — Combined Cycle 4 Assumed Chugach allocation of Watana portion of Susitna Hydroelectric project. CS — Coal Steam Turbine 5 Assumed allocation of a 200 MW combined-cycle unit. 6 Assumed allocation of a 200 MW coal-fired unit. 7 Assumed Chugach allocation of Devil Canyon portion of Susitna Hydroelectric project. NOTE: All plans assume 51-MW are available to the cooperatives from the proposed Anchorage-Fairbanks intertie. Hydroelectric Expansion Scenario In this plan, long-term power supply expansion would be met primarily by power received from the Watana Dam portion of the Susitna Project. We have assumed that the Watana portion of the Susitna Project would be operated by the Alaska Power Authority or a similar entity organized to operate and dispatch power from the project. Therefore, we have shown the Watana portion of the Susitna Project as a purchased power source. This plan assumes that the 1,020-MW Watana portion of the Susitna Project would be developed by the State of Alaska and that capacity from this project would be allocated to the Cooperatives as shown in Table V-4. Projected purchase power costs (estimated for study purposes) for the Watana portion of the Susitna Project are shown in Table V-5. These projections are based on the assumption that approximately 45 percent of the project would be funded through State grants and that the remaining 55 percent would be funded through the issuance of tax-exempt bonds. Gas-Fired Expansion Scenario In this plan, all long-term power supply expansion would be met by participation in 200-MW natural gas-fired combined-cycle units. The estimated costs of gas-fired generation are shown in Table V-3. This plan is affected by uncertainties concerning the price and availability of natural gas during the study period. In particular, there are uncertainties concerning the future availability of Cook Inlet gas for power generation. Natural gas V-18 os from the North Slope fields could be available to the Cooperatives if a pipeline is constructed to deliver this gas. If the Alaska Natural Gas Transportation System is completed on schedule, natural gas could possible begin flowing in 1986 or 1987. The price of this gas is expected to be substantially higher than Beluga gas. For the purpose of this study it was assumed that Cook Inlet gas would no longer be available after 1997 and North Slope gas would be used after 1997 for the remainder of the study period. Coal-Fired Expansion Scenario In this scenario, long-term generation requirements were assumed to be met by participation in 200-MW net coal-fired steam-electric units. Estimated costs for these units are summarized in Table V-3. Fuel costs for the coal-fired plants are based on mining of coal in quantities which are significantly greater than that required to fuel a 200-MW plant. The fuel costs used assume quantities of coal would be mined annually to supply power for approximately 1,400 MW of coal-fired plant capacity. Coal mined over and above that required to power the 200-MW plant is assumed to be exported to other market areas. Fuel costs for this plan would be substantially higher than those shown in Table V-3 if an export market for Beluga coal is not developed. TRANSMISSION REQUIREMENTS In the "System Planning Report" for Chugach by Southern Engineering, dated May 1982, recommendations were made for transmission and distribution system improvements. The transmission system recommendations were incorporated into this study based on the Cooperative's projected transmission improvements as outlined in Chugach's October 1982 financial forecast. Specific transmission V-19 system improvements incorporated in this study include subtransmission and bulk transmission additions as outlined on Schedule G of the October Financial Forecast. * ee He * v-20 PART VI — ECONOMIC ANALYSIS a ey en" eee PART VI ECONOMIC ANALYSIS To make a relative comparison of the revenue requirements from members under the two organizational alternatives for the exploratory power supply plans developed in Part V, an economic analysis of each of the plans was performed. This Part describes the methods and key input parameters used in performing the economic analyses and provides a comparison of the results. METHOD OF ANALYSIS The economic analyses involved projecting the total annual accrual expenses for each power supply plan for each year of the study period, 1983 through 2015. We first developed parameters and performed economic analyses to project incremental accrual expenses. These are those expenses which are expected to vary from plan to plan, including all expenses associated with new power supply resources. These incremental expenses were then combined with the fixed expenses on existing power supply related facilities and operations plus TIER requirements to yield total projected power supply related revenue requirements. The economic analysis assumed for the existing organizational arrangement a TIER level of 2.0. For the G&T cooperative alternative, a TIER level of 1.2 was used. The rationale for using TIER levels higher than the minimum levels is discussed in Part IV. Also included in the cost projections for the G&T were additional expenses associated with the formation and staffing of a G&T cooperative as described in Part IV. vI-1 The incremental annual accrual expenses were projected using Burns & McDonnell's power supply plan analysis computer program. This program models the generation and transmission resources available within each plan and computes the total demand related and energy related expenses for each year of the study period. Generation resources are scheduled on an economic basis to meet the system demand and energy requirements for each year of the study period. Fuel expenses, operation and maintenance expenses, and fixed expenses (insurance, taxes, administrative and general expenses, interest and depreciation) are all included in the power supply computer program to compute the annual accrual expense. Cost escalation is also considered in the analysis. Total revenue requirements were projected using Burns & McDonnell's financial forecast computer program. This program utilizes the results of the power supply plan analysis model and adds the additional fixed costs associated with the organizational type being analyzed. The input data to this model includes a full year of operating statistics used as a starting point (operation and maintenance costs, administrative and general costs, fuel costs, debt service, member revenues, etc.). Other inputs to this model include amounts, issue dates, interest rates, terms and principal deferment periods of existing and future loans; other operating income and deductions; nonoperating income and deductions; and desired margins. The model develops output tables showing projected operating results for the study period. Appendix A provides a description of the financial forecast computer output and Appendix B provides a sample financial forecast computer output. The financial forecast computer output in Appendix B is that for the G&T organizational alternative under a gas-fired expansion plan. VI-2 r oT ~—— KEY ECONOMIC ANALYSIS INPUT PARAMETERS Table VI-1 provides a summary of the key input parameters used in the economic analysis. The top half of the table shows the straight line depreciation rate, insurance rate, and interim replacement rate for each generation type considered. Other information shown in the table is discussed in the following paragraphs. It was assumed that all future financing requirements would be met through Federal Financing Bank (FFB) guaranteed REA loans at an annual interest rate of 11 percent. The period of these loans was assumed to be 35 years. A seven-year deferral of principal payments was also assumed, resulting in a loan amortization period of 28 years. An escalation rate of 8 percent per year was used to project capital costs and annual operation and maintenance costs in this study. Annual administrative and general expenses for new generation facilities were assumed to be equal to 40 percent of the projected annual fixed operation and maintenance expenses for these facilities. Administrative and general expenses on existing plant (including insurance) were based on projections in Chugach's October 1982 Financial Forecast. A discount rate of 11 percent per year was used for computing the present value of the annual incremental costs over the study period for the various power VI-3 Table VI -1 KEY ECONOMIC ANALYSIS INPUT PARAMETERS Straight Line Depreciation Rate Utility Plant Type (Percent) Combustion Turbine 3.00 Hydroelectric 2.00 Steam Production 3.10 Combined Cycle 3.00 Transmission 2.75 General 3.00 External Financing (FFB): Interest Rate Amortization Period Deferment Period Interest Earned on General Funds Operation & Maintenance Escalation Rate Facility Capital Cost Escalation Rate Fuel Data Cook Inlet Natural Gas (old) North Slope Natural Gas Beluga Coal Enstar Natural Gas Cook Inlet Natural Gas (new) Administrative & General: Discount Rate: Times Interest Earned Ratio: Existing Organizational Structure Generation & Transmission Cooperative Fixed Charges (Percent of Total Financing Requirement) / Insurance 0.25 0.10 0.25 0.25 0.10 0.10 11.0 Percent 28.0 Years 7.0 Years 8.0 Percent 8.0 Percent 8.0 Percent Escalation Rates? 2.1 Percent 8.0 Percent 10.1 Percent 9.9 Percent 9.5 Percent Interim Replacements 0.35 0.65 0.35 0.35 0.20 0.20 1963 Fuel Cost (¢/MBTU) 21 639 164 159 150 40.0 Percent of Fixed Operation and Maintenance Costs for New Generation and Transmission Plant 11.0 Percent 2.0 1.2 i Total Financing Requirement = construction cost + overhead including interest during construction. 3 Average annual escalation rate over the study period. vI-4 us Sey supply plans. This discount rate is by convention equal to the assumed 11 percent interest rate for FFB loans. It was assumed that interest at a rate of 8.0 percent would be earned on the average balance of general cash funds. These interest earnings would be available to reduce revenues required from members in meeting operating expenses. When analyzing plans under the existing organizational arrangement, a TIER of 2.0 was used. When analyzing the plans assuming the formation of a generation and transmission cooperative, a TIER of 1.2 was assumed. TIER levels higher than the minimum levels were used because cooperatives must target for average TIER levels higher than the minimum levels to ensure that the minimum levels are always maintained. Capital credits generated with margins resulting from TIER levels in excess of 1.0 were assumed to be rotated (returned to the membership) every 20 years. Sensitivity analyses were performed assuming a 10-year capital credits rotation period. Capital credits assumed to be returned to members in a given year were credited against member revenue requirements in that year. ECONOMIC ANALYSIS OF POWER SUPPLY PLANS Tables IV-2, IV-3 and IV-4 present the results of the economic analysis for the gas-fired, coal-fired, and hydroelectric long-range expansion plans, respectively, assuming a 20-year capital credits retirement period. These tables show projected annual revenue requirements in terms of millions of vI-5 dollars and mills per kilowatt hour for the two organizational alternatives studied. The last three columns of each table show the amount by which the G&T projected member revenue requirements are above or below the projected member revenue requirements for the existing arrangement. It should be noted that the revenue requirements presented in these tables for any year have been reduced by the projected capital credits retirement. That is, capital credits assumed to be returned to members in a given year have been subtracted from projected revenues from member rates in that year tq achieved the revenue requirements shown on these tables. Since capital credits retirements would be greater under the existing alternative (due to a more rapid equity buildup because of the higher TIER), member rates would actually be relatively higher than suggested by the results in these tables for the existing arrangement as compared to the G&T cooperative for the years after 2002 (capital credits retirements are assumed to commence in 2003 under a 20-year rotation). As can be seen in Table VI-2, for the gas-fired expansion scenario, revenue requirements from members under the G&T cooperative are projected to be 24.7 percent lower in 1984 and to decline steadily to only 3.1 percent lower in 1990 compared to those projected under the existing arrangement. By 1991, the advantage is projected to shift to the existing arrangement and it is not until 2008 under this scenario that the revenue requirements of the G&T are again projected to be lower for the gas-fired expansion plan. Also, capital credits retirements are assumed to commence in 2003 under the 20-year rotation schedule, shifting the advantage in terms of revenue requirements to the existing vI-6 7 barrens mens ' ‘ od focmeaoad wa Existing Arrangement yr Assuming 2.0 TIER & Calendar Year ($ Million) (Mills/kWh) r 1983 48.0 28.6 i 1984 73.3 42.1 1985 90.0 50.0 . 1986 94.1 50.4 ; 1987 90.5 46.8 i 1988 123.7 61.7 1989 128.4 64.0 os 1990 129.8 61.4 i 1991 176.9 79.2 ‘ 1992 184.0 79.6 1993 205.6 85.7 Fs 1994 226.7 91.2 i 1995 330.9 128.6 : 1996 455.1 170.6 1997 664.9 240.6 i 1998 754.2 263.2 j 1999 831.3 280.1 2000 938.6 305.1 ze 2001 1,064.3 333.8 | 2002 1,173.3 355.0 “ 2003 1,284.2 374.9 2004 1,413.5 398.3 Y 2005 1,580.3 429.9 : 2006 1,794.4 470.7 : 2007 1,979.0 501.2 2008 2,300.1 562.2 ' 2009 2,547.6 600:4 3 2010 2,824.6 642.7 2011 3,067.2 674.0 2012 3,433.8 727.7 2013 3,924.6 802.6 i 2014 4,369.0 862.2 2015 4,804.3 915.3 z Key Assumptions: Table VI-2 COMPARISON OF PROJECTED MEMBER REVENUE REQUIREMENTS FOR GAS-FIRED EXPANSION PLAN! (LESS RETIRED CAPITAL CREDITS BEGINNING 20037) G&T Cooperative Assuming 1.2 TIER ($ Million) (Milis/kWh) 48.1 28.7 55.1 31.7 76.3 42.4 78.2 41.9 80.9 41.8 115.9 57.8 122.7 61.2 125.9 59.5 179.2 80.3 194.5 $4.1 217.6 90.8 240.3 96.6 349.0 135.6 471.1 176.7 677.5 245.1 765.1 266.9 $44.1 284.4 954.0 310.2 1,062.7 333.3 1,177.0 356.1 1,290.7 376.7 1,443.1 406.6 1,616.8 439.8 1,834.0 481.1 2,019.8 511.5 2,284.5 558.4 2,512.5 592.2 2,801.8 637.5 3,053.5 671.0 3,428.2 726.5 3,956.9 809.2 4,334.2 855.4 4,790.9 912.7 Interest Rate on REA Guaranteed Funds: 11.0 percent 2 Interest Earned on Cash Balance: 8.0 percent Assumes 20-Year Capital Credits Rotation. G&T Above (Below) __Existing Arrangement ($ Million) (Mills/kWh) (%) 0.1 0.1 0.3 (18.2) (10.4) (24.7) (13.7) (7.6) (15.2) (15.9) (8.5) (16.9) (9.6) (5.0) (10.7) (7.8) (3.9) (6.3) (5.7) (2.8) (4.4) (3.9) (1.9) (3.1) 2.3 a} 1.4 10.5 4.5 5.7 12.0 5.1 6.0 13.6 5.4 5.9 18.1 7.0 5.4 16.0 6.1 3.6 12.6 4.5 1.9 10.9 3.7 lu 12.8 4.3 1.5 15.4 5.1 1:7, (1.6) (0.5) (0.1) 3.7 1h 0.3 6.5 1.8 0.5 29.6 8.3 2.1 36.5 9.9 2.3 39.6 10.4 2.2 40.8 10.3 2.1 (15.6) (3.8) (0.7) (35.1) (8.2) (1.4) (22.8) (5.2) (0.8) (13.7) (3.0) (0.4) (5.6) (1.2) (0.2) 32.3 6.6 0.8 (34.8) (6.8) (0.8) (13.4) (2.6) (0.3) arrangement. Up through 2002, Tables VI-2 through VI-4 provide a comparison of projected revenue requirements through rates. Since the coal-fired expansion plan and gas-fired expansion plan used in this study are identical through the year 2000, Table VI-2 and Table VI-3 are identical for the years 1983-2000. In 2001, the relative revenue requirements of the G&T are again projected to be lower for the coal-fired expansion plan since a new coal plant is assumed to be placed in service that year. Table VI-3 shows that after 2001, revenue requirements under the G&T are projected to be lower than those under the existing arrangement for all but four years during the period 2001-2015. This serves to illustrate that a major capital investment, as would be required for the development of a coal-fired plant, would substantially shift the advantage in terms of lower revenue requirements to the G&T for a number of years. It should also be noted that a load growth rate greater than the 3.4 percent annual peak demand growth rate assumed in this study would require new capacity to be brought on line earlier than assumed in the expansion plans used in this analysis. The resulting larger capital expenditures program would result in a greater revenue requirement advantage for the G&T than indicated in Tables VI-2 and VI-3. The results shown for the hydroelectric expansion plan in Table VI-4 are the same as those for both the gas-fired and coal-fired expansion plans through the year 1992 since the expansion plans are identical up until that time. After 1992, revenue requirements from members under the G&T are shown to range from VI-8 - Calendar Year 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1997 2010 2011 2012 2013 2014 2015 Existing Arrangement Assuming 2.0 TIER ($ Million) 455. 1 664.9 754.2 831.3 938.6 1,112.8 1,219.0 1,320.5 1,442.0 1,599.0 1,805.5 1,979.2 2,395.2 2,658.0 2,903.8 3,113.1 3,448.7 4,045.2 4,520.0 (Mills/kWh) 28.6 42.1 50.0 50.4 46.8 61.7 64.0 61.4 79.2 79.6 85.7 91.2 128.6 170.6 240.6 263.2 280.1 305.1 349.1 368.8 385.4 406.3 434.9 473.6 501.2 585.5 626.4 660.7 684.0 730.8 827.2 892.1 Table VI-3 COMPARISON OF PROJECTED MEMBER REVENUE REQUIREMENTS FOR COAL-FIRED EXPANSION PLAN! (LESS RETIRED CAPITAL CREDITS BEGINNING 20037) G&T Cooperative G&T Above (Below) Assuming 1.2 TIER Existing Arrangement ($ Million) (Mills/kWh) ($ Million) (Mills/kWh) (%) 48.1 28.7 0.1 0.1 0.3 55.1 31.7 (18.2) (10.4) (24.7) 76.3 42.4 (13.7) (7.6) (15.2) 78.2 41.9 (15.9) (8.5) (16.9) 80.9 41.8 (9.6) (5.0) (10.7) 115.9 57.8 (7.8) (3.9) (6.3) 122.7 61.2 (5.7) (2.8) (4.4) 125.9 59.5 (3.9) (1.9) (3.1) 179.2 80.3 2.3 11 1.4 194.5 84.1 10.5 4.5 5.7 217.6 90.8 12.0 5.1 6.0 240.3 96.6 13.6 5.4 5.9 349.0 135.6 18.1 7.0 5.4 471.1 176.7 16.0 6.1 3.6 677.5 245.1 12.6 4.5 1.9 765.1 266.9 10.9 3.7 1.4 844.1 284.4 12.8 4.3 1.5 954.0 310.2 15.4 5.1 1.7 1,077.7 338.0 (35.1) (11.1) (3.2) 1,189.7 360.0 (29.3) (8.8) (2.4) 1,297.0 378.6 (23.5) (6.8) (1.8) 1,444.7 407.1 (2.7) 0.8 0.2 1,611.4 438.4 12.4 3.5 0.8 1,824.2 478.6 18.7 5.0 eu 2,002.2 507.0 23.0 5.8 1.2 2,315.9 566.1 (79.3) (19.4) (3.3) 2,542.3 599.2 (115.7) (27.2) (4.3) 2,810.9 639.6 (92.9) (21.1) (3.2) 3,039.8 668.0 (73.3) (16.0) (2.3) 3,394.1 719.2 (54.6) (11.6) (1.6) 4,021.7 822.4 (23.5) (4.8) (0.6) 4,390.8 866.6 (129.2) (25.5) (2.9) 4,796.9 913.9 (89.1) (17.0) (1.8) 4,886.0 1 Key Assumptions: Interest Rate on REA Guaranteed Funds: 11.0 percent 2 930.9 Interest Earned on Cash Balance: 8.0 percent Assumes 20-Year Capital Credits Rotation. Table VI-4 COMPARISON OF PROJECTED MEMBER REVENUE REQUIREMENTS FOR HYDROELECTRIC EXPANSION PLAN! (LESS RETIRED CAPITAL CREDITS BEGINNING 20037) G&T Cooperative Assuming 1.2 TIER ($ Million) (Mills/kWh) ($ Million) G&T Above (Below) Existing Arrangement (Mills/kWh) Existing Arrangement Assuming 2.0 TIER Calendar _ Year ($ Million) (Mills/kWh) 1983 48.0 28.6 1984 73.3 42.1 1985 90.0 50.0 1986 94.1 50.4 1987 90.5 46.8 1988 123.7 61.7 1989 128.4 64.0 1990 129.8 61.4 1991 176.9 79.2 1992 184.0 79.6 1993 405.3 169.0 1994 524.2 210.8 1995 553.8 © 215.2 1996 596.8 223.8 1997 683.1 247.1 1998 730.7 254.9 1999 760.7 256.3 2000 814.7 264.9 2001 878.1 275.4 2002 868.7 262.9 2003 908.7 265.2 2004 905.2 255.1 2005 1,013.6 275.8 2006 1,155.2 303.1 2007 1,249.0 316.3 2008 1,261.4 308.3 2009 1,436.4 338.5 2010 1,550.5 352.8 2011 1,707.8 375.3 2012 2,012.3 426.4 2013 2,109.2 431.3 2014 2,445.5 482.6 2015 2,877.5 548.2 1 Key Assumptions: 48.1 55.1 76.3 78.2 80.9 115.9 122.7 125.9 179.2 194.5 417.3 537.9 571.9 612.9 695.6 741.5 773.6 830.1 900.5 895.8 927.0 954.7 1,060.9 1,210.5 1,306.8 1,305.6 1,495.1 1,600.7 1,767.2 2,057.7 2,158.7 2,491.5 2,941.3 Interest Rate on REA Guaranteed Funds: 11.0 percent 2 Interest Earned on Cash Balance: 8.0 percent Assumes 20-Year Capital Credits Rotation. VI-10 28.7 31.7 42.4 41.9 41.8 57.8 61.2 59.5 80.3 $4.1 174.0 216.3 222.2 229.8 251.7 258.7 260.7 269.9 282.5 271.1 270.6 269.0 288.6 317.6 330.9 319.2 352.4 364.2 388.3 436.1 441.5 491.7 560.4 0.1 (18.2) (13.7) (15.9) (9.6) (7.8) (5.7) (3.9) 2.3 10.5 12.0 13.7 18.1 16.1 12.5 10.8 12.9 15.4 22.4 27.1 18.3 49.5 47.3 55.3 57.8 44.2 58.7 50.2 59.4 45.4 49.5 46.0 63.8 0.1 (10.4) (7.6) (8.5) (5.0) (3.9) (2.8) (1.9) 1.1 4.5 5.0 5.5 7.0 6.0 4.6 3.8 4.4 5.0 71 8.2 5.4 13.9 12.8 14.5 14.6 10.9 13.9 11.4 13.0 9.7 10.2 9.1 12.2 (24.7) (15.2) (16.9) (10.7) (6.3) (4.4) (3.1) 1.4 5.7 3.0 2.6 3.3 2.7 1.9 1.5 1.7 1.9 2.6 3.1 2.0 5.4 4.6 4.8 4.6 3.5 4.1 3.2 3.5 2.3 2.4 1.9 2.2 ee 5.4 percent higher in 2004 to 1.5 percent higher in 1998 than projected revenue requirements under the existing arrangement. Tables VI-5, VI-6 and VI-7 present the results for the gas-fired, coal-fired, and hydroelectric long-range expansion plans assuming a 10-year capital credits retirement period. These tables show the sensitivity of the results to changes in the capital credits retirement period. The results in these three tables show that, as under the 20-year capital credits retirement period assumption, the revenue requirements advantage alternates back and forth between the G&T and the existing arrangement for the gas-fired and coal-fired expansion plans. For the hydroelectric expansion plan, the advantage in any given year remains with the existing arrangement for the years 1993 through 2015. For all three plans, however, the revenue requirements advantage of the existing arrangement in the years 1993-2002 are greater when a 10-year capital credits retirement period is assumed, as would be expected. Table VI-8 presents a compafison of present value of member revenue requirements for the long-range expansion scenarios. The results presented in this table are for both a 20-year capital credits eveatcean and a 10-year capital credits rotation. Present values have been shown for the time period 1983-2000 as well as for the time period 1983-2015. On a present-value basis, over the 1983-2015 study period assuming a 20-year capital credits rotation, the gas-fired expansion plan shows a 0.3 percent advantage for the G&T cooperative. The hydroelectric expansion plan shows a 0.9 percent advantage for the existing arrangement while the coal-fired expansion plan shows a 1.5 percent advantage for the G&T cooperative. Decreasing the capital credits rotation to 10 years VI-11 Calendar Year 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Existing Arrangement Assuming 2.0 TIER ($ Million) 303.0 429.6 643.9 733.4 813.5 923.3 1,054.7 1,170.6 1,286.7 1,438.9 1,611.4 1,822.4 2,001.9 2,322.3 2,566.2 2,843.5 3,037.4 3,408.3 3,904.0 4,352.3 4,791.6 I Key Assumptions: Interest Rate on REA Guaranteed Funds: 11.0 percent Interest Earned on Cash Balance: 8.0 percent ({Mills/kWh) 81. ‘4 117.7 161.1 233.0 255.9 274.1 300.2 330.9 354.2 375.6 405.4 438.4 478.1 507.0 567.7 604.8 647.0 667.4 722.3 798.4 859.0 912.9 2 Assumes 10-Year Capital Credits Rotation. Table VI-5 COMPARISON OF PROJECTED MEMBER REVENUE REQUIREMENTS FOR GAS-FIRED EXPANSION PLAN! (LESS RETIRED CAPITAL CREDITS BEGINNING 19937) G&T Cooperative Assuming 1.2 TIER ($ Million) (Mills/kWh) 48.1 28.7 55.1 31.7 76.3 42.4 78.2 41.9 80.9 41.8 115.9 57.8 122.7 61.2 125.9 59.5 179.2 80.3 194.5 84.1 214.4 89.4 235.7 94.8 342.4 133.0 465.1 174.4 672.0 243.1 759.3 264.9 839.1 282.7 949.7 308.7 1,059.0 332.2 1,174.0 355.2 1,291.7 377.0 1,446.3 407.5 1,622.1 441.3 1,839.0 482.4 2,025.0 512.8 2,290.8 560.0 2,518.3 593.5 2,807.8 638.9 3,047.9 669.7 3,423.6 725.5 3,953.5 808.5 4,331.8 854.9 4,790.1 912.6 VI-12 G&T Above (Below) Existing Arrangement ($ Million) (Mills/kWh) (%) 0.1 0.1 0.3 (18.2) (10.4) (24.7) (13.7) (7.6) (15.2) (15.9) (8.5) (16.9) (9.6) (5.0) (10.7) (7.8) (3.9) (6.3) (5.7) (2.8) (4.4) (3.9) (1.9) (3.1) 2.3 re 1.4 10.5 4.5 5.7 12.0 5.0 5.9 33.2 13.4 16.5 39.4 15.3 13.0 35.5 13.3 8.3 28.1 10.1 4.3 25.9 9.0 3.5 25.6 8.6 3.1 26.4 8.5 2.8 4.3 1.3 0.4 3.4 1.0 0.3 5.0 1.4 0.4 7.4 eel 0.5 10.7 2.9 0.7 16.6 4.3 0.9 23.1 5.8 1.1 (31.5) (7.7) (1.4) (47.9) (11.3) (1.9) (35.7) (8.1) (1.3) 10.5 2.3 0.3 15.3 3.2 0.4 49.5 10.1 1.3 (20.5) (4.1) (0.5) (1.5) (0.3) (0.0) ma wom t — Year 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 2010 2011 2012 2013 2014 2015 Existing Arrangement Assuming 2.0 TIER L$ Million) (Mills/kWh) 48.0 28.6 73.3 42.1 90.0 50.0 94.1 50.4 90.5 46.8 123.7 61.7 128.4 64.0 129.8 61.4 176.9 79.2 184.0 79.6 202.4 84.4 202.5 81.4 303.0 117.7 429.6 161.1 643.9 233.0 733.4 255.9 813.5 274.1 923.3 300.2 1,103.2 346.1 1,216.4 368.0 1,323.0 386.2 1,467.4 413.5 1,629.9 443.4 1,833.5 481.0 2,002.1 507.0 2,417.4 590.9 2,676.6 630.8 2,922.7 665.0 3,034.2 666.7 3,378.1 715.9 3,983.3 814.6 4,466.0 881.4 4,839.9 922.1 1 Key Assumptions: Interest Rate on REA Guaranteed Funds: 11.0 percent Interest Earned on Cash Balance: 8.0 percent 2 Assumes 10-Year Capital Credits Rotation. Table VI-6 COMPARISON OF PROJECTED MEMBER REVENUE REQUIREMENTS FOR COAL-FIRED EXPANSION PLAN! (LESS RETIRED CAPITAL CREDITS BEGINNING 19937) G&T Cooperative G&T Above (Below) Assuming 1.2 TIER Existing Arrangement ($ Million) (Milis/kWh) ($ Million) (Mills/kWh) (9%) 48.1 28.7 0.1 0.1 0.3 55.1 31.7 (18.2) (10.4) (24.7) 76.3 42.4 (13.7) (7.6) (15.2) 78.2 41.9 (15.9) (8.5) (16.9) 80.9 41.8 (9.6) (5.0) (10.7) 115.9 57.8 (7.8) (3.9) (6.3) 122.7 61.2 (5.7) (2.8) (4.4) 125.9 59.5 (3.9) (1.9) (3.1) 179.2 80.3 2.3 er L4 194.5 84.1 10.5 4.5 5.7 214.4 89.4 12.0 5.0 5.9 235.7 94.8 33.2 13.4 16.5 342.4 133.0 39.4 15.3 13.0 465.1 174.4 35.5 13.3 8.3 672.0 243.1 28.1 10.1 4.3 759.3 264.9 25.9 9.0 3.5 839.1 282.7 25.6 8.6 3.1 949.7 308.7 26.4 8.5 2.8 1,074.0 336.9 (29.2) (9.2) (2.7) 1,186.8 359.1 (29.6) (8.9) (2.4) 1,298.0 378.9 (25.0) (7.3) (1.9) 1,447.8 408.0 (19.6) (5.5) (1.3) 1,616.7 439.8 (13.2) (3.6) (0.8) 1,829.2 479.9 (4.3) (1.1) (0.2) 2,007.4 508.3 5.3 1.3 0.3 2,322.2 567.6 (95.2) (23.3) (3.9) 2,548.1 600.5 (128.5) (30.3) (4.8) 2,816.8 640.9 (105.9) (24.1) (3.6) 3,023.7 664.4 (10.5) (2.3) (0.3) 3,379.8 716.2 ry 0.3 0.0 4,009.4 819.9 26.1 5.3 0.7 4,380.5 864.5 (85.5) (16.9) (1.9) 4,788.9 912.4 (51.0) (9.7) G2) VI=13 Calendar Year 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2001 2002 2003 2010 2011 2012 2013 2014 2015 Existing Arrangement Assuming 2.0 TIER ($ Million) (Mills/kWh) Table VI-7 COMPARISON OF PROJECTED MEMBER REVENUE REQUIREMENTS FOR HYDROELECTRIC EXPANSION PLAN! (LESS RETIRED CAPITAL CREDITS BEGINNING 19937) ($ Million) G&T Above (Below) Existing Arrangement (Mills/kWh) 48.0 73.3 90.0 94.1 90.5 123.7 128.4 129.8 176.9 184.0 402.1 500.0 525.8 571.4 662.1 709.9 742.9 799.4 868.5 866.1 911.2 930.6 1,044.8 1,183.3 1,271.9 1,283.6 1,455.0 1,569.4 1,723.8 2,024.3 2,117.8 2,455.4 2,883.7 1 Key Assumptions: Interest Rate on REA Guaranteed Funds: 11.0 percent Interest Earned on Cash Balance: 8.0 percent 28.6 42.1 50.0 50.4 46.8 61.7 64.0 61.4 79.2 79.6 167.7 201.1 204.3 214.2 239.6 247.7 250.3 259.9 272.4 262.1 266.0 262.2 284.2 310.4 322.1 313.8 342.9 357.1 378.8 429.0 433.1 484.6 549.4 2 Assumes 10-Year Capital Credits Rotation. G&T Cooperative Assuming 1.2 TIER ($ Million) (Mills/kWh) 48.1 28.7 55.1 31.7 76.3 42.4 78.2 41.9 80.9 41.8 115.9 57.8 122.7 61.2 125.9 59.5 179.2 80.3 194.5 84.1 414.1 172.7 533.2 214.4 565.3 219.6 606.9 227.6 690.2 249.7 735.8 256.7 768.6 259.0 825.8 268.5 896.8 281.3 892.9 270.2 928.0 270.9 957.9 269.9 1,066.2 290.1 1,215.5 318.9 1,312.0 332.2 1,311.9 320.7 1,500.9 353.7 1,606.7 365.6 1,772.5 389.5 2,062.5 437.1 2,163.8 442.5 2,496.0 492.6 2,945.5 561.2 VI-14 (18.2) (13.7) (15.9) (9.6) (7.8) (5.7) (3.9) 2.3 10.5 12.0 33.2 39.5 35.5 28.1 25.9 25.7 26.4 28.3 26.8 16.8 27.3 21.4 32.2 40.1 28.3 45.9 37.3 48.7 38.2 46.0 40.6 61.8 (10.4) (7.6) (8.5) (5.0) (3.9) (2.8) (1.9) 11 4.5 5.0 13.3 15.3 13.4 10.1 9.0 8.7 8.6 8.9 8.1 4.9 Cae 5.9 8.5 10.1 6.9 10.8 8.5 10.7 8.1 9.4 8.0 11.8 (24.7) (15.2) (16.9) (10.7) (6.3) (4.4) (3.1) 1.4 5.7 3.0 6.6 7.5 6.3 4.2 3.6 3.5 3.3 3.3 3.1 1.8 2.9 2.1 2.7 3.1 2.2 3.1 2.4 2.8 1.9 2.2 1.7 21 CST-IA Table Vi-8 SUMMARY OF PRESENT VALUE OF MEMBER REVENUE REQUIREMENTS FOR LONG RANGE EXPANSION SCENARIOS! (1983$) 20 YEAR CAPITAL CREDITS ROTATION : Assumes 11.0 percent discount rate. 2 Assumes development of Susitna project funded in part (45 percent) with State of Alaska grants. Present Value 1983-2000 Present Value 1983-2015 Ne G&T Above (Below) G&T Above (Below) ) Existing Existing Arrangement Existing Existing Arrangement Expansion Arrangement G&T Arrangement G&T Plan ($ Million) ($ Million) ($ Million) (%) ($ Million) ($ Million) ($ Million) (%) Gas 1,652.5 1,630.9 (21.6) (1.3) 4,129.8 4,116.8 (13.0) (0.3) Coal 1,652.5 1,630.9 (21.6) (1.3) 4,190.4 4,126.7 (63.7) (1.5) Hydro? 1,882.5 1,860.8 (21.7) (1.2) 3,419.6 3,449.2 29.6 0.9 10 YEAR CAPITAL CREDITS ROTATION Present Value 1983-2000 Present Value 1983-2015 G&T Above (Below) G&T Above (Below) Existing Existing Arrangement Existing Existing Arrangement Expansion Arrangement G&T Arrangement G&T Plan _4$ Million) A$ Million) ($ Million) (%) ($ Million) ($ Million) ($ Million) 1%) Gas 1,614.0 1,620.7 6.7 0.4 4,099.3 4,107.9 8.6 0.2 Coal 1,614.0 1,620.7 6.7 0.4 4,150.6 4,115.8 (34.8) (0.8) Hydro? 1,844.0 1,850.6 6.6 0.4 3,396.4 3,442.2 45.8 1.3 decreases the present-value advantage of the G&T cooperative. The relatively small percentage differences shown in Table VI-8 are to be expected since a cooperative is consumer owned and all equity eventually accrues to the membership, regardless of TIER assumption all other factors being equal. As might be expected, the more capital intensive the expansion scenario, the greater the advantage for the G&T cooperative. As shown in Table VI-8 for the study period 1983-2015, the present-value advantage of the G&T for the capital intensive coal-fired expansion scenario is projected to be either $63.7 million (1.5 percent) for the 20-year capital credit rotation assumption or $34.8 million (0.8 percent) for the 10 year capital credit rotation assumption. In comparison, the existing arrangement has a $29.6 million (0.9 percent) advantage under the hydroelectric expansion scenario assuming a 20-year capital credits rotation and a $45.8 million (1.3 percent) advantage assuming a 10-year capital credits rotation. As has been pointed out, the hydroelectric expansion scenario assumes capital will be invested by the State of Alaska instead of by the Cooperatives. This confirms that the greater the load growth and the greater the amount of power supply facilities investment by the Cooperatives, the greater the short-term and long-term advantage of the G&T. In summary, the economic analysis results indicate that the formation of a G&T cooperative will result in significantly lower member rates in the short run, and the greater the required power supply facilities investment in the short run, the longer the period and the greater the magnitude of this short-run advantage. In the long run, the two organizational alternatives would be approximately equivalent in terms of the present value of member revenue VI-16 i i = ae requirements if only modest investment in additional power supply facilities is required of the Cooperatives. More capital intensive expansion plans will more strongly favor the G&T cooperative on a present-value basis. In fact, the greater the required power supply facilities investment and the longer the period of capital credits retirement, the greater the economic advantage of the G&T. Under the existing arrangement, members would pay significantly higher rates up front, building up equity which would eventually be returned to them in the form of capital credits. The Cooperatives would, in effect, be borrowing much more money from their members through higher rates under the existing arrangement than under the G&T. Figures VI-1, VI-2, and VI-3 present a comparison of the projected member revenue requirements for the gas-fired, coal-fired, and hydroelectric scenarios, respectively, assuming a 20-year capital credits rotation period. CONCLUSIONS AND RECOMMENDATIONS Although a number of alternative organization types might be implemented to supply the power requirements of the Cooperatives in the future, the results of our study suggest that the formation of a G&T cooperative is the most viable alternative to continuation with the existing power supply. The principal advantages of a G&T cooperative are that this form of organization: 1. Represents a logical extension of the current form of organization (rural electric cooperative) supplying the needs of the members of the Cooperatives. VI-17 2. Would not require enabling or any other form of legislation. 3. Could be formed by the Cooperatives themselves without loss of control or sharing of control over their power supply with other entities. 4. Would be consistent with the desires of REA, CFC, and the APUC. 5. Would permit the Cooperatives to maintain a minimum 1.0 TIER on generation and transmission facilities, thereby significantly reducing member rates, especially in the short run. 6. Could be structured to alleviate concern about the relative control of facilities and fuel supply contracts. 7. Could be expanded to add new member cooperatives. 8. Could become a taxable entity without significant tax penalties since G&Ts are required to maintain only a 1.0 TIER. An important point to consider in contemplating the results of the economic analysis is that the expansion plans evaluated assumed a constant annual load growth rate of 3.43 percent per year over the period 1983-2015. Preliminary results of the Power Requirements Study we are currently performing for Chugach indicate that this load growth rate may well be conservative in that loads are likely to grow at a significantly higher rate over the next decade. Asa VI-18 —— fT vm 61-1A REVENUE FROM RATEPAYERS (MILLS/KWH) SB. BB 188. BB 158. 88 288. 8B 258. BB 388.88 358. BB 488.88 1983 1985 FIGURE VI-I COMPARISON OF REVENUE REQUIREMENTS FOR GAS-FIRED EXPANSION PLAN (2B-YEAR CAPITAL CREDITS ROTATION) EXISTING ARRANGEMENT G&T COOPERATIVE 1907 1989 1991 1993 1995 1997 1999 YEAR 288) 2883 T@-1A pcan a - - - nee ey tr mee C4 ‘oie ca = FIGURE VI-2 COMPARISON OF REVENUE REQUIREMENTS FOR COAL-FIRED EXPANSION PLAN (2B-YEAR CAPITAL CREDITS ROTATION) 488.88 158.88 288. 88 258. 8B 388.88 358.88 REVENUE FROM RATEPAYERS (MILLS/KWH) EXISTING ARRANGEMENT —=—— G&T COOPERATIVE — T T — T T T 5 1983 1505 YEAR T T 1967 1989 i991 i993 ig9s 1997 i999 2881 1 2883 €7-IA REVENUE FROM RATEPAYERS (MILLS/KWH) 188. BB (SB. BB 288. 8B 258. BB 388. BB 358. 8B 488. BB FIGURE VI-3 COMPARISON OF REVENUE REQUIREMENTS FOR HYDROELECTRIC EXPANSION PLAN (2B-YEAR CAPITAL CREDITS ROTATION) EXISTING ARRANGEMENT G&T COOPERATIVE 1983 T im T T T 1985 1987 1989 i991 1993 i995 1997 1999 YEAR T 1 288) 2883 result, it is likely that the capacity expansion plans used in the economic evaluations of this study are conservatively low in their assumptions concerning the amount of investment in power supply facilities which may be required of the Cooperatives during the next 10 years. Thus, it is likely that the short-run impact of a G&T on member revenue requirements will be greater than indicated by the results of our analyses. In summary, the economic analyses results indicate that the formation of a Gé&T cooperative will result in significantly lower member rates in the short run, and the greater the required power supply facilities investment in the short run, the longer the period and the greater the magnitude of this short-run advantage. In the long run, the two organizational alternatives would be approximately equivalent in terms of present value of member revenue requirements with the capital intensive expansion plans favoring the G&T cooperative. The greater the required power supply facilities investment and the longer the period of capital credits retirement, the more the present-value advantage would shift to the G&T. In other words, under the existing arrangement members would pay significantly higher rates up front, building up equity which would eventually be returned to them in the form of capital credits. The Cooperatives would, in effect, be borrowing much more money from their members through higher rates under the existing arrangement than under the G&T. Assuming the Cooperatives would prefer to maintain substantially lower member rates in the short term, the results of our study indicate it would be economically preferable to form a G&T cooperative rather than continue with the vI-25 present power supply situation. There are, of course, many factors which come into play and many uncertainties involved in a decision of this nature. After weighing and considering the results of our economic analyses and the other information available to us concerning the power supply situation of the Cooperatives, it is our opinion that a G&T is the preferred power supply organization type. Formation of a G&T cooperative would lower member rates and revenue requirements in the short run; be consistent with the express desires of CFC, REA, and the APUC; would not require enabling legislation; would be a logical extension of the current form of organization (rural electric cooperative); could be expanded to add new member systems; and would provide a more flexible organization to deal with the complex and dynamic power supply environment of South Central Alaska. There is also considerable precedent for the formation of a G&T cooperative since this is the form of organization being utilized by virtually all other rural electric cooperatives in the United States that have pursued major power supply programs. Also supporting this conclusion are the preliminary results of the Power Supply Planning Study which we are performing for Chugach. The results of this study indicate a much greater capital investment requirement for power supply facilities over the next decade than projected for purposes of developing the results of this study. This difference is primarily due to the higher load growth rate being used in the Power Supply Planning Study. For these reasons, we recommend the formation of a G&T cooperative. The formation of a G&T cooperative, however, will not be easy if this is the course selected by the Cooperatives. A number of important decisions and major commitments must be made by all concerned if such an organization is to be VI-26 ew fee 5 “9 h GaGa eee cm me cam ~ Geeiiiian formed. Perhaps, the most important initial decision would involve a decision by Chugach to either form a G&T alone or a joint G&T with Homer and Matanuska and/or possibly GVEA. The formation of a G&T by Chugach alone could no doubt be accomplished more quickly because only one party (Chugach) would be involved. Forming a joint G&T would be complicated by the need to gain additional approvals and to negotiate and come to a mutual agreement among the parties on various aspects of the G&T's structure. From the perspective of Chugach, there are also a number of significant concerns which would need to be addressed if a joint G&T is to be formed. For Chugach, a disadvantage associated with the formation of a joint G&T is that Chugach would lose exclusive control and ownership of its power supply facilities. Related concerns are that the members of Chugach might lose the benefit of existing favorable fuel contracts and have their vested equity in power supply facilities diluted. The results of our investigation and experience suggest these concerns can be resolved to the mutual satisfaction of all parties. For example, concerns about relative control of decision making might be accommodated through some form of weighted voting on key issues. The issue of existing equity in power supply facilities could be resolved by appropriate compensation from the G&T. In fact, the figures we have developed indicate that the combined amount of equity in power supply facilities of the Cooperatives is relatively small (roughly $7.5 million) compared to the outstanding loan principle balance (about $217 million) on G&T facilities. Regarding the fuel contracts, the Cooperatives already share the benefits of these contracts under the existing power sales agreements. A valid concern of Chugach would be that these benefits not be diluted in the future. It would VI-27 seem that appropriate arrangements to mitigate this concern, such as weighted voting, could be negotiated during the G&T formation process. Thus, we believe that the major apparent obstacles to the formation of a joint G&T can be overcome. At the same time, we believe there are significant advantages to be gained by the Cooperatives from the formation of a joint G&T cooperative. For Homer and Matanuska, an important benefit of a joint G&T is that it would provide them (and their consumers) with a voice in power supply matters. For all three Cooperatives, the most important benefit may be creation of a stronger power supply organization, one with the clout and resources to operate successfully in the highly dynamic environment of South Central Alaska. The importance of a strong G&T power supply organization dedicated to reliably supplying the power needs of its member cooperatives at the lowest possible cost cannot be overemphasized. Also, a joint G&T is the form of organization preferred by REA. For these reasons, we consider a joint G&T to be the preferred form of power supply organization for the Cooperatives. Because of the economic and other benefits to be derived from the formation of a G&T and the expiration at the end of 1983 of Chugach's agreement with REA and CFC permitting a 1.15 TIER on G&T properties, we recommend that the necessary steps leading to the formation of a G&T cooperative be initiated as soon as possible. The formation of an operating G&T, especially a joint G&T, is a complex process as discussed in Part VII of our report. The complexity of forming a G&T can be expected to be compounded by the many other demands on the time of the boards and staffs of the Cooperatives, the need to obtain member VI-28 approval, and the need to negotiate mutually acceptable arrangements if a joint G&T is established. It should also be realized that a G&T cooperative would have to depend heavily on the existing Chugach organization and would probably have to contract with Chugach for staff and logistic support during the initial years following its formation. At the same time it is important to recognize that a new G&T would be much more than a paper organization in that it would own and control substantial power supply resources, have a sizeable staff, and have major contractual obligations. It should also be noted that the formation of a G&T is likely to result in significant additional expense resulting from some duplication of staff and facilities. We have estimated for purposes of our analyses an eventual incremental cost of $2.0 million per year to operate a separate G&T compared to continuation with the present organization. While this is a significant additional cost, we believe that savings from increased efficiencies which should result from the operation of an organization dedicated exclusively to power supply will substantially offset this additional expense. However, because such savings are difficult to reliably quantify, we have included no allowance for savings from any increased organizational efficiency possible through the formation of a G&T in our study. We would also like to mention that our study assumed that financing for power supply facilities would continue to be available to the Cooperatives under the REA guaranteed loan program. Obviously, there is no assurance that funds under VI-29 this program will continue to be available to the Cooperatives in the future, and the Cooperatives may be forced at some future point in time to seek other sources of financing. On the other hand, we believe the maintenance of the status quo regarding the Cooperative's source of financing to be a reasonable assumption because any other assumption would be much more speculative in view of the unpredictability of future actions concerning such matters by the federal government. At the same time, we are of the opinion that a strong G&T cooperative would facilitate the direct entry of the Cooperatives into the private capital markets if this should ever become necessary. This view appears to be supported by the following conclusion of the LBKL Study: "G&T systems have the potential for expanding their access to private capital, but within the context of a strong continuing REA guarantee program. The Committee on Objectives and Planning projects a total of $49.3 billion of capital commitments for construction programs through 1990. In our judgment, even the fullest possible exploitation of available private financing alternatives would fall short of meeting these requirements. It is particularly important to stress that even the perception of substantially diminishing REA support would limit the full utilization of available private market alternatives--that is to say, that access to the private market will be maximized if a strong ongoing REA financial and administrative commitment is assured. Given this assurance, we believe that G&T systems have several alternatives for expanding their access to private capital." eee HH VI-30 t ' oe ws a Reemonnee —} P eT PSa OP e ) P ae e PART Vil — G&T IMPLEMENTATION os Pra: 3 PART VII G&T IMPLEMENTATION GENERAL This part presents a discussion of the various activities and processes which must be accomplished in connection with the formation of a G&T cooperative. Principally, most of these activities must be carried out regardless of whether Chugach forms a G&T by itself or in conjunction with Homer and Matanuska (or others). For purposes of consistency, the discussion here assumes the formation of a joint G&T. Major changes in the organizational structure of any organization require the cooperation and willingness of those affected in order to proceed in an orderly, successful manner. This is particularly true for a major organizational change. A change from the current power supply arrangement to a joint G&T cooperative would require the acceptance and cooperation of the boards of directors, members and employees of the Cooperatives. The formation of a G&T cooperative, although fairly simple and straightforward in concept, will require a substantial effort as well as a positive outlook and attitude of compromise on the part of all concerned if it is to be successfully accomplished within a reasonable time frame. In order to bring a new G&T cooperative to the point of actually providing service for its members, a series of tasks must be completed. While many of the necessary steps could be performed concurrently, there may be limits on staff resources and certain critical path items which must be accomplished VII-1 consecutively. The first and most important of these is to obtain the approval of the majority of each Cooperative's members and board of directors. In particular, Chugach would face the most radical change in its organization. Board and member approval of such a major change would certainly be required for Chugach. Formation of a G&T would require the transfer of some 80 percent of Chugach's assets which are G&T property. This requirement is explicitly stated in Article IX of Chugach's By-Laws. Article IX, Section 1(b) states that Chugach "may not sell, lease, or otherwise dispose of all or a substantial portion of the Association's property unless such sale, lease or disposition is authorized by the affirmative vote of not less than the majority of all the members of the cooperative... Alternatively, the members may authorize Chugach's board of directors to dispose of such property at a meeting of a majority of the members. The actual timing of formation of a G&T will depend heavily on the timing of member and board approvals. Member approval could be obtained at annual membership meetings or at special meetings of the cooperatives’ members. Each of the Cooperatives’ annual membership meetings is typically scheduled for late April or early May. For purposes of the analyses of this study, we have assumed that board and member approvals for the formation of a G&T cooperative could be obtained during 1983 and that the G&T would begin operating by January 1984. However, for a variety of reasons this schedule may not be attainable. Following board approval, a number of issues must be settled among the Cooperatives. These issues may include, for example, assignment of deferred credits incurred in a natural gas exploration program, the current discrepancy VII-2 aoe —— — “- wom aa between G&T assets and long-term indebtedness assignable to such facilities, the rate base allocation of the new headquarters and dispatch center, and relative representation and voting rights on the G&T board. G&T COOPERATIVE IMPLEMENTATION Additional in-house personnel and outside consultants, as discussed in Part IV, would be necessary to execute the activities required to form a G&T. A listing of typical activities which may be necessary to implement a G&T is outlined below. However, it should be noted that this listing is not necessarily complete. Also, the actual timing or sequencing of activities may differ from that suggested by the ordering in the list. The list is primarily intended to indicate the nature and scope of activities which must be undertaken in conjunction with the formation of a G&T. For ease in understanding the activities which must be accomplished, these activities are shown as pre-G&T formation and post-G&T formation activities. The activities described as pre-G&T formation activities include those which must be performed prior to formal organization of the G&T operating entity separate from the Chugach distribution cooperative. The post-G&T formation activities are those which can be accomplished after the G&T has been formed as an operating entity. VII-3 The steps which must be accomplished prior to and after the establishment G&T cooperative include the following: Pre-G&T Formation Activities of a 1. Affirmative resolution and commitment by each of the Cooperatives’ boards to study G&T formation. 2. Appointment of G&T Coordinating Committee with representatives from each cooperative. 3. Selection by Coordinating Committee of a chairman and other persons to review legal and engineering aspects and affects on employees, members of the public, rates and regulations, operating policies and practices, power supply, capital structure and financial outlook. 4. Coordination meetings between the Coordinating Committee and Cooperative boards. 5. Dissemination of progress reports to employees, members and the public. 6. Preparation of G&T formation agreement. 7. Approval of G&T formation agreement by boards of directors. VII-4 Bee ——— — _- 10. 11. 12. 13. 14. 15. 16. 17. Approval of G&T formation agreement by general membership. Approval of G&T formation agreement by REA and CFC. Appointment of general manager to direct: new G&T (see REA Bulletin 109-4). Formation of new G&T board of directors. Appointment of transition staff to develop new G&T. Development of new G&T organizational structure and organizational outline. Drafting of G&T cooperative bylaws (see REA Bulletin 101-5). Drafting of articles of incorporation and “filing of same with state of Alaska. Filing of application for tax exemption with+district director of the Internal Revenue Service. Selection of corporate attorney (see REA Bulletin 100-1). VII-5 18, 19. 20. 21. Review of existing contractual agreements between Chugach and others including: a. Fuel contracts. b. Purchase contracts. c. Interconnection agreements Development of new power sales contracts with City of Seward, Homer, Matanuska and newly formed Chugach distribution cooperative (approval by new G&T cooperative board of directors, REA, APUC). Development of separate accounting system and staff for G&T operations. Initiation of separate billing procedures to wholesale customers including Chugach distribution cooperative. Post G&T Formation Activities Obtain outside accountant for independent audit (CPA). Establish a new employee benefits program for G&T employees including: a. Life insurance. b. Hospital and surgical coverage. c. Employee income protection. d. Retirement plan. VII-6 fa we cc a ea Fs Bae own , Smt eS ae 10. Develop safety program (see REA Bulletin ae db. Ce d. ee. f. Rules and regulations. Policy. Job training program. Enforcement program. Safety accreditation program. Accident reporting program. Develop self-training program. Develop member services program. Prepare operating budgets. Establish G&T cooperative newsletter. Hold initial annual meeting. Prepare first annual report to members (see REA Bulletin 101-4). Review insurance policies to accommodate separation into new corporation. yII-7 168-7) including: of G&T properties 1. 12. 13. 14. Develop public and employee relations program. Complete transfer of production and transmission personnel to umbrella of new G&T cooperative. Separate responsibilities of administrative personnel of Chugach and G&T into separate G&T and distribution functions. Perform cost-of-service study and rate design work. eee HE VII-8 APPENDIX A — FINANCIAL FORECAST COMPUTER OUTPUT DESCRIPTION APPENDIX A FINANCIAL FORECAST COMPUTER OUTPUT DESCRIPTION This appendix shows the development of a financial forecast for the Cooperatives covering the period 1983 through 2015. A complete financial forecast computer output for the natural gas expansion scenario, G&T organization alternative, is included in Appendix B, Financial Forecast Computer Output. Appendix C contains a table of projected operating results for each of the power supply expansion scenarios presented in Part VI. The complete computer output in Appendix B was generated by a financial forecast computer program and includes the following output tables: Table 1 - Input Data Table 2 - Summary of Power Sources Table 3 - Power Requirements and Sources Table 4 - Energy Allocations and Fuel Requirements Table 6 - Investments and Cash Requirements Table 7 - Incremental Cash Expenditures Table 8 - Incremental Accrual Expenses Table 9 - Summary Table 10 - Long-Term Debt - Existing Table 11 - Long-Term Debt - New Table 12 - Long-Term Debt - Summary Table 13 - Electric Plant In Service Table 14 - Projected Operating Results Table 15 - Cash Operating Margins TABLE 1 - INPUT DATA This table gives the basic data upon which the calculations for each plan are made. The first part of this table lists fuel prices, fuel heating values, and purchased power costs. The second part of this table lists input parameters by type of investment, including depreciation periods, insurance rates, and interim replacement rates. The amortization period, interest rate, and capital recovery factor for FFB loans are included along with a listing of escalation rates, the discount rate used for present value calculations, property tax rate, and the reserve requirement. TABLE 2 - SUMMARY OF POWER SOURCES This table describes the existing and future power resources available for this financial forecast. The information provided about each purchased power source includes its availability and the 1983 cost of energy in mills/kWh. The information provided about each generation source includes its net capacity, availability, average annual net heat rate, year of initial operation, type of generator, type of fuel, 1983 cost of energy and the 1983 fixed and variable operation and maintenance costs. The cost of energy shown in Table 2 for each generation source is the product of the unit heat rate and the appropriate fuel cost for 1983 plus the variable 0&M expense. A-2 hoe aa — TABLE 3 - POWER REQUIREMENTS AND SOURCES Power Requirements This table starts with a listing of the expected peak demand for the Cooperatives for the years 1983-2015. The expected peak system demands are combined with reserve requirements to provide the total required capacity. Power Sources The section subtitled "Generation" accumulates the net capacity available from existing generation units plus new generating units as they are placed in service. The capacity values shown are net (gross less station service) capacities in megawatts. The section subtitled "Purchased Capacity" summarizes the sources of purchased power. The capacity required from additional purchases was calculated by the program in years in which the sum of new and existing generating and purchased power sources was not sufficient to meet the total required capacity. Total Power Sources This line gives the sum of total generation and total purchased capacity for each year. Capacity Surplus Any capacity from existing and new generation and from purchases in excess of the required capacity is shown in this line. A-3 Firm Capacity Sold No surplus capcity was assumed to be sold in this study. TABLE 4 - ENERGY ALLOCATIONS AND FUEL REQUIREMENTS To facilitate an analysis of each alternative, the net capacity, energy allocation, capacity factor, energy price, fuel price, fuel cost, and fuel consumption are listed, as applicable, for each power source in this table by year. Also included are yearly totals for the figures tabulated. The annual energy allocation shown in Table 4 for each resource is a summary from the allocation model which operates on an annual basis. This energy allocation model is based on the Booth-Baleriaux probabilistic simulation method of energy allocation. A load duration curve is used to represent the system load. Capacity resources are loaded economically, such that units with the lowest energy prices will be allocated the most energy. The load presented to a given unit in the loading order includes the effects of outages of all previously loaded units. Thus, the first unit to be loaded is affected only by its own outages, but subsequently loaded units are affected by outages of all previously loaded units. Energy assigned to supplemental purchases represents energy which will be required when units are on scheduled or forced outages. After determining the energy assigned to a generating unit, the heat rate from Table 2 and fuel price from Table 1 were used to determine the cost of fuel for that particular generator. The sum of the fuel costs for the generators utilized during a particular year provides the total fuel expense listed. The fuel quantities required by each generating unit were also calculated using the A-4 —- eee Renee leousne ‘ ‘ oe ov — heating values of fuels shown in Table 1. The energy costs listed on this table were calculated by dividing the fuel cost by the energy allocated to the unit. TABLE 6 - INVESTMENTS AND CASH REQUIREMENTS New Generators For reference, the new generation capacity (MW) installed is tabulated for each year. Totals are shown for each year and for the 33-year study. Investments The estimated total cost including interest during construction and overheads is shown for each new generation investment in terms of dollars per kW (net) and for both new generation and transmission investments in terms of total dollar cost. TABLE 7 - INCREMENTAL CASH EXPENDITURES Demand-Related Purchased Power Expenses Demand-related purchased power expenses for each purchased power source are summarized for power purchased in any given year from outside bulk power suppliers. The demand charges are calculated at the rate listed in Table 1. Fixed 0&M The fixed O&M expenses includes the salaries, fringe benefits, and materials (exclusive of fuel) for the normal supervision, operation and maintenance necessary for the proper functioning of the generating unit. These expenses are calculated for each unit using the rate shown in Table 2, with a 8 percent per year escalation and then summed to show the total. A-5 Substation/Transmission Line 0&M This is the expense for the normal operation and maintenance required for new substations and transmission lines. Administrative and General The administrative and general expenses are calculated by multiplying the administrative and general expense rate (40 percent) times the fixed O&M expense for new generating units during each year of the study. Internal Financing No internal financing of new units was assumed. Long-Term Leases For both organizational types analyzed, the long-term lease payments made by Chugach are shown for each year of the study. These lease payments are generally for land leased for generation and transmission facilities. Homer Xmsn Lease Pmt For the existing organizational type, the estimated lease payments on the transmission facilities leased from Homer are shown for each year of the study. These costs are not included in the analyses of formation of a G&T cooperative. Additional G&T Staff For the G&T organizational type, the estimated expenses incurred for personnel to guide and coordinate the transition from the existing organization type are shown for the early years of the study. After the transition period (after A-6 oy 1988) additional staff members are assumed for the continued operation of the G&T cooperative. Interim Replacements The interim replacement cost provides for the expenses that occur when equipment must be replaced before the end of the expected lifetime. The interim replacement rates used are shown in Table 1. Insurance The insurance expense was calculated at the rate shown in Table 1. The insurance is for fire and extended coverage on plants, buildings, and equipment associated with new generation and transmission plant. Principal The principal payment shown is that for a level service repayment schedule. The debt service schedule for each new bond issue or loan has been calculated according to the term of the issue, amortization, and interest rate shown in Table i. Interest The interest expense is the interest which accrues on outstanding bond issues associated with new generation plant. The interest expense for a particular plant will decrease as the years go by since the debt service has been calculated to be level. The term of the bond issue or loan and the amortization period and interest rate is shown in Table 1. Property Taxes The tax expense was calculated at the property tax rate shown in Table 1. No property taxes have been assumed for Alaska. Total-Demand Related Cash Expenses This line totals all of the demand-related cash expenses listed above. Less Capacity Sales No surplus capacity was assumed to be sold in this study. Net Demand-Related Cash Expenses Total demand-related cash expenses less capacity sales. Energy-Related Purchased Power Expenses The energy-related purchased power expense represents the energy charges for power purchased in any given year from outside bulk power suppliers. The energy charges are calculated at the rate listed in Table 1. Fuel Expense The fuel expense shown represents the sum of all existing and future generating unit fuel expense. These expenses are calculated for each year of the study by multiplying the fuel price in Table 1 times energy generated during each year of the study for the respective unit. A-8 Nerenemcls ~— - om Variable O&M The power production variable O&M expense is the sum of the existing and new unit variable O&M expenses for each unit. Unit variable O&M expenses are calculated by multiplying the variable O&M rate in Table 2 times the energy generated from the unit and adjusting this number by the escalation for variable O&M expenses which is printed in Table 1. Total Generation Expenses Sum of fuel expense and variable O&M expense. Total Energy-Related Cash Expenses This line totals all of the energy-related cash expenses listed above. Net Energy-Related Cash Expenses Total energy- related cash expenses less any sales of surplus. energy. No surplus energy sales were assumed in this study. Total Cash Expenditure The total cash expenditures constitute the sum of net demand-related cash expenses and net energy-related cash expenses. Demand-Related Expenses, $/kW-Year The demand-related expenses ($/kW-Year) represents the net demand-related cash expenses divided by the peak demand. A-9 Energy-Related Expenses, Mills/kWh The energy-related expenses (mills/kWh) represents the net energy-related cash expenses divided by the system energy requirement. Total Expenses, Mills/kWh The total expenses (mills/kWh) represents the Total Cash Expenditures divided by the system energy requirements. TABLE 8 - INCREMENTAL ACCRUAL EXPENSES The expenses listed in this table, such as production operation and maintenance, purchased power, fuel expense, etc., are the same as developed for Table 7, “Incremental Cash Expenditures." The only new entry here is depreciation. The depreciation expense is calculated on a straight-line basis, using the depreciation period shown in Table 1, for each investment type. Cash expenditures for principal payments and interim replacements are not included as accrual expenses. Annual and 33-year totals are provided. The net accrual expenses and the system energy requirement are used to calculate the average power cost shown in mills/kWh. TABLE 9 - SUMMARY OF POWER COSTS The summary table shows the totals and present values of the cash expenditures and accrual expenses over the period 1983-2015. The present values are given in 1983 dollars and have been calculated using a discount rate of 11 percent. The total investment, accumulated depreciation, and net investment are shown as well as the total fuel requirements for the study. The average ‘incremental accrual energy cost (mills/kWh) is also shown. A-10 a) bees Psa sO —— TABLE 10 - LONG-TERM DEBT - EXISTING This table lists individual REA, FFB and other loans which are currently outstanding. This table gives the original principal amount, interest rate, and annual principal and interest payments. TABLE 11 - LONG-TERM DEBT - NEW This table lists individual FFB loans which will be used to finance new generation and transmission plant. This table gives the original principal amount, interest rate, annual principal and interest payments, and interest charged to construction for each loan. TABLE 12 - LONG-TERM DEBT - SUMMARY This table gives an annual summary of the loan payments, interest expense, and balance of long-term debt for the period 1983-2015. TABLE 13 - ELECTRIC PLANT IN SERVICE This table gives an annual summary of the gross plant in service, plant additions and retirements, accumulated depreciation, and depreciation expense. TABLE 14 - PROJECTED OPERATING RESULTS This table provides an annual summary of the projected operating expenses, estimated revenues, required revenue increases, margins, operating ratios, and financial ratios for the Cooperatives. Net patronage capital or margins, and therefore required revenue increases, have been calculated so as to give a times interest earned ratio (TIER) of 1.2 when a generation and transmission cooperative is formed. For the assumption that the existing arrangement is A-11 maintained, a TIER of 2.0 was used. The TIER is calculated as net patronage capital or margins plus net interest on long-term debt divided by net interest on long-term debt. Net interest on long-term debt is interest on long-term debt less interest during construction. The debt service coverage is calculated as net patronage capital or margins plus interest on long-term debt plus depreciation divided by interest on long-term debt. The expense item labeled Other Deductions includes expenses for dispatching, amortization of specific known items, and depreciation of general plant. Nonoperating income has been calculated as the interest income generated from surplus cash. Table 15 shows how surplus cash is generated each year. An interest rate of 8.0 percent has been assumed to calculate interest income. TABLE 15 - CASH OPERATING MARGINS This table provides an annual summary of cash margins. Cash margins are equal to total cash income less total cash expenditures. Total cash income includes revenues from ratepayers, other operating income, and nonoperating income. Total cash expenditures includes principal payments and operating expenses (Net Power Cost-Accrual) less depreciation. Margins have been used to retire patronage capital, retire existing loans, and reduce loan requirements for future plant investments. ee HHH A-12 i ceo 4 F i q o FE ’ os 7 f a rs ’ \ 4 Ce Bee eed f ere poe b eee es —- ¢ ‘ APPENDIX B — FINANCIAL FORECAST COMPUTER OUTPUT CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 YEAR ENDING DEC 31 FUEL PRICES, CENTS/MBTU BELUGA GAS BELGA COAL NORTH GAS ENSTAR GAS BELUGA GAS PURCHASED POWER COSTS CAPACITY ($/KW-YEAR) AK P ADMIN BRADLEY LA WATANA DEVIL CANY INTERTIE ADDTNL PUR ENERGY (MILLS/KWH) AK P ADMIN BRADLEY LA WATANA DEVIL _CANY INTERTIE ADDTNL PUR YEAR ENDING DEC 31 FUEL PRICES, CENTS/MBTU BELUGA GAS BELGA COAL NORTH GAS ENSTAR GAS BELUGA GAS PURCHASED POWER COSTS CAPACITY (%/KW-YEAR) AK P ADMIN BRADLEY LA WATANA DEVIL _CANY INTERTIE ADDTNL PUR 1020. 2027. 2189. 2553. 1031. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN TABLE 1 INPUT DATA 1988 1987 1990 1991 27. 27. a. 28. 265. 292. 354. 939. 1014. 1095: 1183. 247. 272. 329. 340. 367. 37. 428. 0. 0. 0. 0. 365. 365. 366. 366. 779. 780. 780. 780. 0. 0. 0. 0. 19. 21. 23. 24. 0. 0. 0. 0. 14.6 16.0 16.0 16.0 5.4 5.8 63 68 4.6 5.0 5.4 5.8 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 37.0 57.0 80.0 106.0 2003 2004 2005 2006 34. 35. 35. 36 1124. 1237. 1362. 1500. - 2978. 3217. 3474. 3752. 1031. 1134. 1248. 1372. 1079. 11465. 1258. 1359. 0. 0. 0. 0. 371. 372. 373. 374. 786. 787. 788. 789. 1032. 1033. 1034. 1034. 61. 66. 72. 77. 0. 0. 0. 0. . 1738. 0 168.0 206.0 248.0 25. 0 2008 2009 2010 2011 1818. 4376. 1661. 2203. 2426. 5104. 5513. - 2210. 1651. 4052. 1510. 2001. 4726. . 1712. 1035. 1036. 1037. 1038. Tea se A TaN eee PAGE: 1 DATE: 21-May-63 TIME: 09:24 FILES: CHMGT.D1 GASGT. D2 VERSION: PS6-9/82 1992 1993 1994 1995 1996 1997 HEAT VALUE BTU/UNIT 31. 1006. 631. 7900. 1877. 1004. 382. 1003. 680. 1006. 0. 368. 783. 0. 39. 0. 19.4 10.8 9.2 0.0 0.0 348.0 2012 HEAT VALUE BTU/UNIT 39. 2671. 3954. 2431. - 2157. 0. 381. 796. - 1041. 123. 0. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 2 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOPER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (82,20 VERSION: PS6-9/82 TABLE 1 INPUT DATA (CONTINUED) YEAR ENDING DEC 31 1998 19979 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 ENERGY (MILLS/KWH) AK P ADMIN 21.4 21.4 21.4 23.5 23.5 23.5 25.8 25.8 25.8 28.4 28.4 28.4 31.3 31.3 31.3 BRADLEY LA 11.7 12.6 13.6 14.7 15.9 17.2 18.5 20.0 21.6 23.3 25.2 27.2 29.4 31.8 34.3 WATANA 9.9 10.7 11.6 12.5 13.5 14.6 15.8 17.0 18.4 19.9 21.5 23.2 25.0 27.0 29.2 DEVIL _CANY 0.0 0.0 0.0 0.0 7.5 8.1 8.7 9.4 10.1 11.0 11.8 12.8 13.8 oes 16.1 INTERTIE 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 ADDTNL PUR 407.0 439.0 474.0 512.0 553.0 597.0 645.0 697.0 752.0 813.0 878.0 948.01024.01105.01194.0 YEAR ENDING DEC 31 2013 2014 2015 FUEL PRICES, CENTS/MBTU BELUGA GAS 37. 4. 4%. BELGA COAL 2741. 3238. 3565. NORTH GAS 6430. 6944. 7500. ENSTAR GAS 2674. 2942. 3236. BELUGA GAS 2329. 2516. 2717. PURCHASED POWER COSTS CAPACITY (%/KW-YEAR) AK P ADMIN 0. 0. 0. BRADLEY LA 382. 384. 385. WATANA 798. 799. 801. DEVIL _CANY 1042. 1044. 1045. INTERTIE 133. 143. 155. ADDTNL PUR 0. 0. 0. ENERGY (MILLS/KWH) AK P ADMIN 34.4 34.4 34.4 BRADLEY LA 37.1 40.0 43.2 WATANA 31.5 34.1 36.8 DEVIL CANY - 4 18.8 20.3 INTERTIE 0.0 0.0 0.0 ADDTNL PUR 1289. 01373. 01504.0 DEPRECIATION INSURANCE INTERIN PERIOD RATE RATE REPLACEMENTS (YEARS) (PCT) (PCT) (PCT) COMBUSTION TURBINE 33.3 3.00 0.25 0.35 HYDRO 30.0 2.00 0.10 0.465 STEAM PRODUCTION 32.3 3.10 0.25 0.35 COMBINED CYCLE 33.3 3.00 0.25 0.35 GENERAL PLANT 33.3 3.00 0.10 0.20 SUBSTATION/XMISSION 36.4 2.75 0.10 0.20 BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 TYPE OF LOAN AMORTIZATION INTEREST PERIOD RATE (YEARS) (PCT) FFB 28 11.00 ESCALATION RATES 1983 - 1984 oan 8.00 PERCENT CAPITAL COST 8.00 PERCENT BELUGA GAS 1.99 PERCENT WASTE HEAT 0.00 PERCENT HYDRO 0.00 PERCENT BELGA COAL 10.10 PERCENT NORTH GAS 8.00 PERCENT ENSTAR GAS §.18 PERCENT BELUGA GAS 66.67 PERCENT NONE 0.00 PERCENT DISCOUNT RATE 11.00 PERCENT PROPERTY TAX - PROP. TAX 0.00 PERCENT RESERVE REQUIREMENT 15.00 PERCENT TABLE 1 INPUT DATA (CONTINUED) CAPITAL RECOVERY FACTOR (PERIODS (PCT) PER YEAR) 2.688 AVERAGE COMPOUND RATE 8.00 PERCENT 8.00 PERCENT 2.09 PERCENT 0.00 PERCENT 0.00 PERCENT 10.10 PERCENT 8.00 PERCENT 9.87 PERCENT 9.47 PERCENT 0.00 PERCENT EAE: a 2ray 0 TIME: 09:24 FILES: CHHGT. Di GASGT. D2 VERSION: PS6-9/82 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATIGN AND TRANSMISSION COOP. PLAN: UNIT GAS (8%, 20 POWER NUMBER SOURCE BRBRRSVSNeGSONKSwoNpuswNe AK P ADMIN BRADLEY LA WATANA DEVIL CANY INTERTIE ADDTNL PUR BELUGA 122 BELUGA 3 BELUGA 4 BELUGA 5 BELUGA 688 BELUGA 788 BERNICE 1 BERNICE 2 BERNIC 384 COOPER 182 INTN 1,283 KNIK ARM BELUGA 9 BERNICE 5 200M CC 200MM CC 200MW CC HDGRS SUPPL PURCH NET CAPACITY (ri) 36.0 36.2 10.0 61.3 97.4 98.0 8.3 19.6 56.0 17.2 48.2 10.0 64.0 37.0 100.0 200.0 200.0 0.0 AVAIL (%) 100.0 100.0 100.0 100.0 0.0 100.0 83.0 83.0 83.0 83.0 83.0 83.0 83.0 83.0 83.0 95.1 83.0 83.0 83.0 83.0 86.0 86.0 84.0 0.0 FOR (%) 0.0 0.0 0.0 0.0 0.0 0.0 8.5 8.5 8.5 8.5 8.5 8.5 8.5 8.5 8.5 1.9 8.5 8.5 8.5 8.5 8.0 8.0 8.0 0.0 BURNS & MCDONNELL ENGINEERING COrPANY POWER SUPPLY PROGRAN TABLE 2 SUMMARY OF POWER SOURCES AVG ANN NET YEAR OF HEAT RATE (BTU/KWH) 9878. 12000. 12000. eres: 0. INITIAL OPERATION 1968 1972 1976 1972 1976 1976 1963 1971 1978 1961 1965 1952 1984 1985 2001 2008 2013 1984 TYPE OF TYPE OF GENERATOR FUEL. COMB COMB TURB B/N GAS COMB TURB IN/N GAS COMB TURB B/N GAS COMB CYCLE B/N GAS Come CYCLE B/N GAS COMB TURB E/N GAS COMB TURB E/N GAS COMB TURB E/N GAS HYDRO HYDRO COMB TURB E/N _GAS STEAM PROD ENSTAR GAS TURB IN/N GAS TURB E/N _GAS COMB CYCLE NORTH GAS COMB CYCLE NORTH GAS CYCLE NORTH GAS GENERAL NONE 33 3 C1] — ENERGY COST FOR SUPPLEMENTAL PURCHASES IS ASSUMED TO BE 1.0 TIMES THE PRICE OF ENERGY FROM ADDTNL PUR. ecm eee — PAGE: _ 4 DATE: 21-May-83 TIME: 09:24 FILES: CHNGT.D1 GASGT.D2 VERSION: PS6-9/82 COST OF OPERATION AND MAINTENANCE ENERGY FIXED VARIABLE (MILLS/KWH) ($/KW-YEAR) (MILLS/KWH) (1983$) (1983$) (1983$) 13.26 _ 3.68 aaa 3.13 anenenear 0.00 eee 9.00 ra 24.00 ene 21.26 8.43 3.41 8.43 21.26 8.43 3.41 8.43 2.60 8.43 2.60 8.43 32.16 5.37 32.16 5.37 32.16 5.37 0.63 10.50 34.85 5.07 41.83 48.72 18.56 8.43 19.44 3.37 546.05 15.50 56.05 15.50 56.05 15.50 0.00 0.00 C1] meme BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 YEAR ENDING DEC 31 POWER REQUIREMENTS, MW EXPECTED PEAK DEMAND RESERVE REQUIREMENT TOTAL REQUIRED CAPACITY POWER SOURCES, rl AVAILABLE GENERATION EXISTING GENERATION NEW GENERATION COMBUSTION TURBINE COMBINED CYCLE TOTAL AVAILABLE GENERATION PURCHASED CAPACITY AK P ADMIN (FIRM) BRADLEY LA (FIRM) WATANA DEVIL _CANY INTERTIE ADDTNL_PUR TOTAL PURCHASED CAPACITY TOTAL CAPACITY AVAILABLE CAPACITY SURPLUS NONFIRM CAPACITY SOLD TABLE 3 POWER REQUIREMENTS AND SOURCES 1983 393.0 36.8 449.8 318.2 0.0 0.0 318.2 14.0 0.0 0.0 0.0 0.0 0.0 14.0 332.2 62.3 0.0 1984 47.0 59.0 446.0 518.2 64.0 0.0 382.2 14.0 0.0 9.0 0.0 0.0 0.0 14.0 396.2 130.2 0.0 1985 420.0 60.9 480.9 318.2 101.0 0.0 619.2 14.0 0.0 0.0 0.0 51.0 0.0 65.0 684.2 203.3 0.0 1984 435. 63. 498. WS 318.2 101.0 0.0 619.2 14.0 0.0 0.0 0.0 31.0 0.0 65.0 684.2 186.0 0.0 a ll 1987 450.0 65.4 315.4 318.2 101.0 619.2 14.0 0.0 0.0 0.0 51.0 0.0 65.0 684.2 168.8 0.0 1988 465.0 37.5 522.4 318.2 101.0 0.0 619.2 14.0 68.0 0.0 0.0 31.0 0.0 133.0 7352.2 229.8 0.0 1989 481.0 59.9 340.8 518.2 101.0 619.2 14.0 68.0 0.0 0.0 31.0 0.0 133.0 752.2 211.3 0.0 DATE: 21-May-83 TIME: 09:24 FILES: CHMGT.D1 GASGT.D2 VERSION: PS6-9/82 1990 4978.0 62.4 3460.4 518.2 101.0 0.0 619.2 14.0 68.0 0.0 0.0 31.0 0.0 133.0 752.2 191.8 0.0 1991 315.0 64.9 579.9 318.2 101.0 0.0 619.2 14.0 68.0 0.0 0.0 51.0 0.0 133.0 7352.2 172.3 0.0 BURNS & HCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSHISSION COOP. PLAN: GAS (8%, 20 YEAR ENDING DEC 31 POWER REQUIREMENTS, IW EXPECTED PEAK DEMAND RESERVE REQUIREMENT TOTAL REQUIRED CAPACITY POWER SOURCES, MW AVAILABLE GENERATION EXISTING GENERATION NEW GENERATION COMBUSTION TURBINE COMBINED CYCLE TOTAL AVAILABLE GENERATION PURCHASED CAPACITY AK P ADMIN (FIRM) BRADLEY LA = (FIRM) WATANA DEVIL CANY INTERTIE ADDTNL PUR TOTAL PURCHASED CAPACITY TOTAL CAPACITY AVAILABLE CAPACITY SURPLUS NONFIRM CAPACITY SOLD POWER REQUIREMENTS AND SOURCES 1992 532.0 67.5 599.5 518.2 101.0 0.0 619.2 14.0 68.0 — si: 0 0.0 133.0 7352.2 152.7 0.0 TABLE 3 (CONTINUED) 1993 1994 331.0 370.0 70.4 73.2 621.3 643.2 518.2 318.2 101.0 101.0 0.0 0.0 619.2 619.2 14.0 14.0 68.0 68.0 0.0 0.0 9.0 0.0 51.0 31.0 0.0 0.0 133.0 133.0 7352.2 752.2 130.8 109.0 0.0 0.0 1995 389.0 76.1 665.1 318.2 101.0 0.0 619.2 14.0 68.0 9.0 31.0 0.0 133.0 7352.2 87.1 0.0 1996 609.0 7901 688.1 318.2 101.0 0.0 619.2 14.0 68.0 0.0 0.0 51.0 133.0 752.2 64.1 0.0 1997 630.0 82.2 712.2 518.2 101.0 0.0 619.2 14.0 68.0 0.0 9.0 51.0 0.0 133.0 732.2 #.0 0.0 1998 652.0 85.5 737.5 318.2 101.0 619.2 PAGE: 6 DATE: 21-May-83 TINE: 09:24 FILES: CHNGT.D1 GASGT. b2 VERSION: PS6-9/82 1999 674.0 88.8 762.8 518.2 101.0 0.0 619.2 14.0 68.0 0.0 0.0 31.0 10.6 143.6 762.8 0.0 0.0 697.0 92.3 789.3 518.2 101.0 0.0 619.2 14.0 68.0 0.0 9.0 31.0 37.1 170.1 789.3 0.0 0.0 BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 YEAR ENDING DEC 31 POWER REQUIREMENTS, MW EXPECTED PEAK DEMAND RESERVE REQUIREMENT TOTAL REQUIRED CAPACITY POWER SOURCES, MW AVAILABLE GENERATION EXISTING GENERATION NEW GENERATION COMBUSTION TURBINE COMBINED CYCLE TOTAL AVAILABLE GENERATION PURCHASED CAPACITY AK P ADMIN (FIRM) BRADLEY LA = (FIRM) WATANA DEVIL CANY INTERTIE ADDTNL_PUR TOTAL PURCHASED CAPACITY TOTAL CAPACITY AVAILABLE CAPACITY SURPLUS NONFIRM CAPACITY SOLD POWER REQUIREMENTS AND SOURCES 14.0 31.0 133.0 852.2 35.3 0.0 TABLE 3 (CONTINUED) 2002 2003 746.0 772.0 99.8 103.5 845.6 875.5 318.2 518.2 101.0 101.0 100.0 100.0 719.2 719.2 14.0 14.0 68.0 68.0 0.0 0.0 0.0 0.0 31.0 51.0 0.0 23.3 133.0 156.3 852.2 875.5 6.6 0.0 0.0 0.0 2004 798.0 107.4 905.4 318.2 101.0 100.0 719.2 14.0 68.0 0.0 0.0 51.0 33.2 186.2 905.4 0.0 0.0 14.0 51.0 217.3 936.4 0.0 0.0 854.0 115.8 969.8 318.2 101.0 100.0 719.2 14.0 68.0 0.0 0.0 51.0 117.6 250.6 969.8 0.0 0.0 883.0 120.2 1003.2 318.2 101.0 100.0 719.2 14.0 68.0 0.0 0.0 51.0 151.0 284.0 1003.2 0.0 0.0 PAGE: 7 DATE: 21-Ma TIME: 09:24 FILES: CHMGT GASGT VERSION: PS6 2008 913.0 124.7 1037.6 318.2 101.0 300.0 919.2 14.0 68.0 0.0 0.0 51.0 0.0 133.0 1052.2 14.6 0.0 y-83 Di 02 9/82 2009 945.0 129.5 1074.4 318.2 101.0 300.0 919.2 14.0 68.0 0.0 0.0 51.0 22.3 155.3 1074.4 0.0 0.0 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 8 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 TALE S VERSION: PS6-9/82 POWER REQUIREMENTS AND SOURCES (CONTINUED) YEAR ENDING DEC 31 2010 2011 2012 2013 2014 2015 POWER REQUIREMENTS, MW EXPECTED PEAK DEMAND 977.0 1010.0 1045.0 1081.0 1118.0 1156.0 RESERVE REQUIREMENT 134.3 139.2 144.5 149.9 155.4 161.1 TOTAL REQUIRED CAPACITY 1111.3 1149.2 1189.4 1230.9 1273.4 1317.1 POWER SOURCES, MW AVAILABLE GENERATION EXISTING GENERATION 518.2 518.2 518.2 518.2 318.2 518.2 NEW GENERATION COMBUSTION TURBINE 101.0 101.0 101.0 101.0 101.0 101.0 COMBINED CYCLE 300.0 300.0 300.0 300.0 300.0 500.0 TOTAL AVAILABLE GENERATION 919.2 919.2 919.2 1119.2 1119.2 1119.2 PURCHASED CAPACITY AK P ADMIN = (FIRM) 14.0 14.0 14.0 14.0 14.0 14.0 BRADLEY LA = (FIRM) 68.0 68.0 68.0 68.0 68.0 68.0 WATANA. 0.0 0.0 0.0 0.0 0.0 0.0 DEVIL _CANY 0.0 0.0 0.0 0.0 0.0 0.0 INTERTIE 31.0 51.0 31.0 31.0 31.0 51.0 ADDTNL_PUR 59.1 97.0 137.3 0.0 21.2 64.9 TOTAL PURCHASED CAPACITY 192.1 230.0 270.3 133.0 154.2 197.9 TOTAL CAPACITY AVAILABLE 1111.3 1149.2 1189.4 1252.2 1273.4 1317.1 CAPACITY SURPLUS 0.0 0.0 0.0 21.3 0.0 0.0 NONFIRM CAPACITY SOLD 0.0 0.0 0.0 0.0 0.0 0.0 BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSHISSION COOP. PLAN: GAS (8%, 20 DATE: | 21°Hay-83 TIME: 09:24 FILES: CHMGT.D1 GASGT.D2 VERSION: PS6-9/82 Sagas saas & TABLE 4 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL. UNIT POWER CAP ENERGY FACTOR VAR OM ONLY COST NUMBER SOURCE (rd) (rH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) YEAR ENDING DEC 31, 1983 11 BELUGA 688 97.4 706435. 82.8 2.60 2.04 1439. 6936547. 12 BELUGA 788 98.0 332937. 62.1 2.60 2.04 1086. 5232958. 8 BELUGA 3 36.2 169768. 34.5 3. 41 2.85 483. 2320831. 10 BELUGA 5 61.3 91971. 17.1 3. 41 2.85 262. 1261636. 7 BELUGA 182 346.0 29079. 9.2 21.26 20.70 . 602. 398896. 9 BELUGA 4 10.0 6448. 7.4 21.26 20.70 133. 88456. 13 BERNICE 1 8.3 4589. 6.3 32.16 31.80 146. 91512. 14 BERNICE 2 19.6 8443. 4.9 32.16 31.80 268. 168356. 15 BERNIC 324 56.0 13161. 2.7 32.16 31.80 419. 262436. 18 KNIK ARM 10.0 1546. 1.8 41.83 38. 48 59. 37298. 17 INTN 1,283 48.2 4215. 1.0 34.85 34.22 229. 143310. 14 COOPER 182 17.2 38009. 38.5 0.43 1 AK P ADMIN 14.0 91980. 75.0 13.26 tenn enem enn 25 SUPPL PURCH ——- 29783. nian 24.00 SSS TOTAL ALLOCATION 332.2 1721566. 36.9 3126. TOTAL REQUIRED CAPACITY 449.8 SYSTEM REQUIREMENTS 393.0 1725000. SYSTEM LOAD FACTOR, x 30.1 3269. 15759972. 1121. 702910. 735. 487351. BURNS & MCDONNELL ENGINEERING COMPANY CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 UNIT NUMBER YEAR ENDING 11 12 8 10 19 13 14 15 7 7 18 17 16 1 25 POWER SOURCE DEC 31, 1984 BELUGA 628 BELUGA 788 BELUGA 3 BELUGA 5 BELUGA 9 BERNICE 1 BERNICE 2 BERNIC 384 BELUGA 182 BELUGA 4 KNIK ARM INTN 1,283 COOPER 182 AK P ADMIN SUPPL PURCH TOTAL ALLOCATION TOTAL REQUIRED CAPACITY SYSTEM REQUIREMENTS SYSTEM LOAD FACTOR, % Cap (ry 97.4 98.0 36.2 61.3 64.0 8.3 19.6 36.0 36.0 10.0 10.0 48.2 17.2 14.0 596.2 466.0 407.0 30.2 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY (TWH) 707129. 550356. 193259. 103403. 49500. 4189. 8109. 13094, 4231. 828. 702. 1880. 38009. 91980. 1234. 1787902. 1790000. POWER SUPPLY PROGRAM CAPACITY FUEL PLUS FACTOR VAR OFM (PCT: 82.9 64.1 39.3 19.3 8.8 3.8 4.7 2.7 1.3 0.9 9.8 0.4 38.5 73.0 34.2 ) aah eet ee TABLE 4 ENERGY PRICE FUEL ONLY (MILLS/KWH) = (MILLS/KWH) 2.68 2.08 2.468 2.08 3.51 2.90 3.51 2.90 30.60 30.00 34.79 34. 40 34.79 34.40 34.79 34.40 35.10 34.50 35.10 34.50 45.24 41.62 59.33 58.65 0.68 13.26 26.00 FUEL cost ($1000) 1469. 1143. 361. 300. 1485. 144. 279. 450. 146. 29. 29. 110. 3473. 1013. 1640. 16416845. 587154. 6597864. PAGE: 10 DATE: 21-May-83 TIME: 09:24 FILES: CHNGT.01 GASGT.02 VERSION: PS6-9/82 saaanaaaaaaa g z g BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOrER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 TABLE 4 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL UNIT POWER Cap ENERGY FACTOR VAR O+M ONLY NUMBER SOURCE (rd) (WH) (PCT) <(MILLS/KWH) = (MILLS/KWH) YEAR ENDING DEC 31, 1984 FUEL cOsT ($1000) PAGE: 11 DATE: 21-May-83 TIME: 09:24 FILES: CHMNGT.D1 GASGT. D2 VERSION: PS6-9/82 oe BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 12 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82~113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSHISSION COOP. PLAN: GAS (8%, 20 mika VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER CAP ENERGY FACTOR VAR Of ONLY COST NUMBER SOURCE (mW) (WH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 1985 3 INTERTIE 31.0 0. 9.0 0.00 S88 SS il BELUGA 688 97.4 707403. 82.9 2.73 2.08 1470. 6946047. MCF BELUGA GAS 12Z BELUGA 788 98.0 361203. 65.4 2.73 2.08 11466. 5510501. NCF BELUGA GAS 8 BELUGA 3 36.2 210448. 42.7 3.56 2.90 611. 2886867. MCF BELUGA GAS 10 BELUGA 5 61.3 111750. 20.8 3.56 2.90 324. 1532748. MCF BELUGA GAS 20 BERNICE 5 37.0 39329. 12.1 22.62 22.20 873. 470539. MCF ENSTAR GAS 19 BELUGA 9 64.0 35883. 6.4 33.05 32.40 1163. 428025. NCF BELUGA GAS 13 BERNICE 1 8.3 3185. 4.4 37.42 37.00 118. 63503. MCF ENSTAR GAS 14 BERNICE 2 19.6 5952. 3.5 37.42 37.00 220. 118681. MCF ENSTAR GAS 15 BERNIC 384 54.0 9145. 1.9 37.42 37.00 338. 182352. MCF ENSTAR GAS 7 BELUGA 182 34.0 2783. 0.9 37.91 37.26 111. 409719. MCF BELUGA GAS g BELUGA 4 10.0 591. 0.7 37.91 37.26 22. 8106. MCF BELUGA GAS 18 KNIK ARM 10.0 479. 0.5 48.68 44.77 2i. 11545. MCF ENSTAR GAS 17 INTN 1,283 48.2 1271. 0.3 63.82 63.09 80. 43202. MCF ENSTAR GAS 16 COOPER 122 «17.2 58009. 38.5 0.73 HYDRO 1 AK P ADMIN § 14.0 91980. 73.9 13.26 SSS 3 SUPPL PURCH ——- 840. -_— 28.00 a rrr nnn TOTAL ALLOCATION 684.2 1840450. 30.7 6517. TOTAL REQUIRED CAPACITY 480.9 SYSTEM REQUIREMENTS 420.0 1851000. SYSTEM LOAD FACTOR, % 50.3 FUEL TOTALS 3570. 16876362. MCF BELUGA GAS fives tes LL i necrone rene Meera eee heme ren te es BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 13 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 cada VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL, UNIT POWER Cap ENERGY FACTOR VAR O+M ONLY COST NUMBER SOURCE (rd) (WH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 1985 1651. 887841. MCF ENSTAR GAS 1296. 477050. CF BELUGA GAS BURNS & MCDONNELL ENGINEERING COMPANY CHUGACH, HOMER & HATANUSKA ELEC. ASSOCIATIONS PROJECT 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 UNIT POWER NUMBER SOURCE YEAR ENDING DEC 31, 1986 5 INTERTIE 11 BELUGA 688 12 BELUGA 788 8 BELUGA 3 10 BELUGA 5 20 BERNICE 5 19 BELUGA 9 7 BELUGA 182 9 BELUGA 4 13 BERNICE 1 14 BERNICE 2 15 BERNIC 384 18 KHIK ARM 17 INTN 1,283 16 COOPER 182 1 AK P ADMIN 3 SUPPL PURCH TOTAL ALLOCATION TOTAL REQUIRED CAPACITY SYSTEM REQUIREMENTS SYSTEM LOAD FACTOR, % CAP (rw) 31.0 97.4 98.0 56.2 61.3 37.0 64.0 36.0 10.0 8.3 19.6 36.0 10.0 48.2 17.2 14.0 684.2 478.2 435.0 50.4 ENERGY (TWH) 0. 708060. 383218. 237952. 122128. 46438. 42384. 12984. 2629. 1891. 3576. 5281. 399. 1587. 38009. 91980. 1051. 1919766. 1921000. POWER SUPPLY PROGRAN CAPACITY FUEL PLUS FACTOR VAR O+M (PCT) (MILLS/KWH) 0.0 83.0 67.9 48.3 22.7 14.3 7.6 4.1 3.0 2.6 2.1 1.1 0.7 0.4 38.5 73.0 32.0 TABLE 4 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE 0.00 2.82 2.82 3.67 3.67 24.93 35.75 41.00 41.00 41.25 41.25 41.25 33.59 70.36 0.79 14.59 30.00 FUEL ONLY (MILLS/KWH) 2.12 2.12 2.96 2.96 24. 48 35.04 40.30 40.30 40.80 40.80 40.80 499.37 69.56 FUEL. COST ($1000) 1500. 1236. 704. 362. 1137. 1495. 523. 106. 77. 146. 215. 30. 110. 7631. 3802. 1675313. 555588. 505577. 176111. 36061. 37699. 71306. 105304. 14443. 53947. 17618637. PAGE: 14 DATE: 21-May-83 TINE: 09:24 FILES: CHMGT.O1 GASGT.D02 VERSION: PS6-9/82 FUEL TOTALS NCF BELUGA GAS BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 TABLE 4 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER CAP ENERGY FACTOR VAR O+f ONLY COosT NUMBER SOURCE oy) (HH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) YEAR ENDING DEC 31, 1986 1715. 2114. =a ena wee PAGE: 15 DATE: 21-May-83 TIME: 09:24 FILES: CHNGT.D1 GASGT.D2 VERSION: PS6-9/82 AMOUNT OF FUEL 838288. MCF ENSTAR GAS 719749. WF BELUGA GAS Bevnn BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 UNIT POWER NUMBER SOURCE YEAR ENDING DEC 31, 1987 5 INTERTIE il BELUGA 688 12 BELUGA 728 8 BELUGA 3 10 BELUGA 5 20 BERNICE 5 19 BELUGA 9 7 BELUGA 182 9 BELUGA 4 13 BERNICE 1 14 BERNICE 2 15 BERNIC 324 18 KNIK ARM 17 INTN 1,283 16 COOPER 182 1 AK P ADMIN 25 SUPPL PURCH TOTAL ALLOCATION TOTAL REQUIRED CAPACITY SYSTEM REQUIREMENTS SYSTEM LOAD FACTOR, X Cap (ri) 31.0 97.4 98.0 36.2 61.3 37.0 64.0 36.0 10.0 8.3 19.6 34.0 10.0 48.2 17.2 14.0 684.2 315.4 450.0 50.5 ENERGY (WH) 0. 708441. 603831. 256021. 143572. 54496. 50472. 15842. 3351. 2446. 4586. 6971. 816. 2232. 38009. 91980. 1595. 2004660. 1991000. (PCT) 0.0 83.0 70.3 52.0 26.7 16.8 9.0 5.0 3.8 3.4 2.7 1.4 0.9 0.5 38.5 73.0 33.4 TABLE 4 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE CAPACITY FUEL PLUS FACTOR VAR O+f (MILLS/KWH) 0.00 2.88 2.88 3.72 3.72 27.37 38.56 44.23 44.23 45.29 3.29 5.29 58.77 77.24 0.86 14.59 33.00 FUEL ONLY (MILLS/KWH) 2.12 2.12 2.96 2.96 26.88 37.80 43.47 43.47 44.80 44.80 44.80 34.21 76.38 FUEL COST ($1000) 1501. 1279. 738. 425. 1445. 1908. 689. 146. 110. 205. 312. 44. 170. 3963. PAGE: 16 DATE: 21-May-83 TIME: 09:24 FILES: CHNGT.D1 GASGT.D2 VERSION: PS6-9/82 AMOUNT OF FUEL 6956247. NCE BELUGA GAS 5929070. MCF BELUGA GAS 3512019. MCF BELUGA GAS 1969479. NCE BELUGA GAS 651993. NCF ENSTAR GAS 602053. MCF BELUGA GAS 217310. MCF BELUGA GAS 95967. MCF BELUGA GAS 48767. MCF ENSTAR GAS 91446. CF ENSTAR GAS 139002. NCF ENSTAR GAS 19678. MCF ENSTAR GAS 75869. CF ENSTAR GAS HYDRO FUEL TOTALS 18366815. NCF BELUGA GAS BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 17 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 tr 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL, UNIT POWER CAP ENERGY FACTOR VAR O+f ONLY COST NUMBER SOURCE cr) (WH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 1987 2307. 1026754. MCF ENSTAR GAS 2742. 865329. MCF BELUGA GAS BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (82,20 UNIT POWER NUMBER SOURCE YEAR ENDING DEC 31, 1988 7 INTERTIE i1 BELUGA 688 12 BELUGA 728 8 BELUGA 3 10 BELUGA 5 20 BERNICE 5 19 BELUGA 9 7 BELUGA 182 9 BELUGA 4 13 BERNICE 1 14 BERNICE 2 15 BERNIC 384 18 KNIK ARM 17 INTN 1,283 16 COOPER 182 1 AK P ADMIN 2 BRADLEY LA a SUPPL PURCH TOTAL ALLOCATION TOTAL REQUIRED CAPACITY SYSTEM REQUIREMENTS SYSTEM LOAD FACTOR, % Cap (rd) 31.0 97.4 98.0 56.2 61.3 37.0 64.0 36.0 10.0 8.3 19.6 36.0 10.0 48.2 17.2 14.0 68.0 732.2 322.4 465.0 50.6 ENERGY (WH) 0. 708504. 590929. 221186. 112485. 38022. 33526. 9601. 1882. 1350. 2478. 3364. 357. 906. 58009. 91980. 178704. 317. 2053799. 2061000. CAPACITY FUEL PLUS FACTOR VAR Ot (PCT) = (MILLS/KWH) 0.0 83.0 68.8 44.9 20.9 11.7 6.0 3.0 2.1 1.9 1.4 0.7 0.4 0.2 38.5 735.0 30.0 31.2 TABLE 4 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE 0.00 3.49 3.49 4.55 4.535 30.17 41.62 47.74 97.74 49.93 49.93 49.93 64.70 85.15 0.93 14.59 5.41 37.00 FUEL ONLY (MILLS/KWH) 2.67 2.67 3.73 3.73 29.64 40.80 4.92 46.92 49.% 49.40 49.40 39.77 84.23 FUEL cost ($1000) 1890. 1576. 824. 419. 1127. 1368. 50. 88. 67. 122. 166. 21. 76. 8195. 4709. 6956862. 5802382. 3034161. 1543037. 454899. 399912. 131707. 25814. 26923. 49406. 67072. 8613. 30798. PAGE: 18 DATE: 21-May-83 TIME: 09:24 FILES: CHNGT.D1 GASGT.D2 VERSION: PS6-9/82 AMOUNT OF FUEL aa aRaaaaaas BELUGA GAS BELUGA GAS BELUGA GAS BELUGA GAS ENSTAR GAS BELUGA GAS BELUGA GAS BELUGA GAS ENSTAR GAS ENSTAR GAS ENSTAR GAS 17336442. FUEL TOTALS NiCr BELUGA GAS BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 TABLE 4 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER CAP ENERGY FACTOR VAR Ot ONLY cost NUMBER SOURCE «rw (WH) (PCT) (MILLS/KWH) = (MILLS/KWH) ($1000) YEAR ENDING DEC 31, 1988 1580. 1907. DATE: 21 ftay-83 TIME: 09:24 FILES: CHNGT.D1 GASGT- D2 VERSION: PS6-9/82 AMOUNT OF FUEL 637711. MCF ENSTAR GAS 357433. MCF BELUGA GAS BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATLONS PROJECT 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 CAP (rid) 31.0 97.4 98.0 36.2 61.3 37.0 64.0 36.0 10.0 8.3 19.6 546.0 10.0 48.2 17.2 14.0 68.0 UNIT POWER NUMBER SOURCE YEAR ENDING DEC 31, 1989 3 INTERTIE 11 BELUGA 688 12 BELUGA 788 8 BELUGA 3 10 BELUGA 5 20 BERNICE 5 19 BELUGA 9 7 BELUGA 182 9 BELUGA 4 13 BERNICE 1 14 BERNICE 2 15 BERNIC 384 18 KNIK ARM 17 INTN 1,283 16 COOPER 182 1 AK P ADMIN 2 BRADLEY LA a SUPPL PURCH ---- TOTAL ALLOCATION TOTAL REQUIRED CAPACITY 340.8 SYSTEM REQUIREMENTS SYSTEM LOAD FACTOR, % 752.2 481.0 50.7 ENERGY (TWH) 0. 708603. 614147. 251988. 126141. 46842. 40669. 12010. 2431. 1718. 3153. 4450. 492. 1253. 38009. 91980. 178704. 770. 2143357. 2136000. CAPACITY FUEL PLUS FACTOR VAR O+M (PCT) = (MILLS/KWH) 0.0 83.0 71.5 51.2 23.5 14.5 7.3 3.8 2.8 2.4 1.8 0.9 0.6 0.3 38.5 75.0 30.0 32.5 TABLE 4 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE 0.00 3.56 3.56 4.61 4.61 33.21 44.93 51.53 51.53 34.97 34.97 34.97 71.14 93.75 1.00 16.05 5.84 57.00 FUEL ONLY (MILLS/KWH) 2.67 2.67 3.73 3.73 32.64 44.04 50.65 50.65 34.40 34.40 34.40 65.82 92.75 FUEL COST ($1000) 1890. 1638. 939. 470. 1529. 1791. 608. 123. 93. 172. 242. 32. 116. 4937. PAGE: 20 DATE: 21-May-83 TIME: 09:24 FILES: CHNGT.Di GASGT. D2 VERSION: PS6-9/82 AMOUNT OF FUEL 6957829. MCF BELUGA GAS 6030360. MCF BELUGA GAS 3456696. MCF BELUGA GAS 1730359. MCF BELUGA GAS 340423. MCF ENSTAR GAS 485112. NCF BELUGA GAS 164748. MCF BELUGA GAS 33345. MCF BELUGA GAS 34253. MCF ENSTAR GAS 62863. MCF ENSTAR GAS 68728. MCF ENSTAR GAS 11875. MCF ENSTAR GAS 42583. MCF ENSTAR GAS HYDRO FUEL TOTALS 18175244. MCF BELUGA GAS BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP.. PLAN: GAS (8%, 20 TABLE 4 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER CAP ENERGY FACTOR VAR O+f ONLY cost NUMBER SOURCE (rad) (TWH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) YEAR ENDING DEC 31, 19897 2185. 22. PAGE: 21 DATE: 21-May-83 TIME: 09:24 FILES: CHNGT.D1 GASGT..02 VERSION: PS6-9/82 AMOUNT OF FUEL 800726. NCF ENSTAR GAS 683204. NCF BELUGA GAS BURNS & NCDONMELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT §2-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 UNIT POWER NUMBER SOURCE YEAR ENDING DEC 31, 1990 3 INTERTIE il BELUGA 688 12 BELUGA 728 8 BELUGA 3 10 BELUGA 5 20 BERNICE 5 19 BELUGA 9 7 BELUGA 182 9 BELUGA 4 13 BERNICE 1 14 BERNICE 2 15 BERNIC 384 18 KNIK ARM 17 INTN 1,283 16 COOPER 122 1 AK P ADMIN 2 BRADLEY LA 23 SUPPL PURCH TOTAL ALLOCATION TOTAL REQUIRED CAPACITY SYSTEM REQUIREMENTS SYSTEM LOAD FACTOR, % Cap OD) 31.0 97.4 98.0 56.2 61.3 37.0 64.0 36.0 10.0 8.3 19.6 36.0 10.0 48.2 17.2 14.0 68.0 7352.2 360.4 498.0 50.8 CAPACITY FUEL PLUS FACTOR VAR O41 (MILLS/KWH) ENERGY (WH) 0. 708603. 626380. 261123. 147229. 53663. 47898. 14419. 2785. 2132. 3974. 5830. 648. 1687. 38009. 91980. 178704. 1068. 2206329. 2216000. (PCT) 0.0 83.0 73.0 53.0 27.4 16.6 8.5 4.6 3.4 2.9 2.3 1.2 0.7 0.4 38.5 73.9 30.0 33.5 na TABLE 4 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE 0.00 3.73 3.73 4.82 4.82 36.50 4B. 60 55.75 55.75 60. 42 60. 42 60. 42 78.10 103.04 1.08 16.05 6.31 80.00 FUEL. ONLY (MILLS/KWH) 2.77 2.77 3.86 3.86 35.83 47.64 54.79 34.79 39.80 59.80 59.80 72.36 101.96 FUEL COST ($1000) 1960. 1732. 1009. 369. 1925. 2282. 790. 164. 127. 238. 349. a. 172. 11364. 5270. PAGE: 22 DATE: 21-Hay-B3 TIME: 09:24 FILES: CHHGT.D1 GASGT: D2 VERSION: PS6-9/82 AMOUNT OF FUEL 6957829. 6150475. 3582002. 2019639. 642025. 571349. 197795. 9943. 42511. 79237. 116245. 15634. 57366. BELUGA GAS BELUGA GAS BELUGA GAS BELUGA GAS ENSTAR GAS BELUGA GAS BELUGA GAS BELUGA GAS ENSTAR GAS ENSTAR GAS ENSTAR GAS ENSTAR GAS ENSTAR GAS SRG aaSa Rass 18709945. FUEL TOTALS NCF BELUGA GAS BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 23 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 pay VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER Cap ENERGY FACTOR VAR O+N ONLY Cost NUMBER SOURCE (rd) (WH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 1990 2858. 753018. MCF ENSTAR GAS 3235. 8100846. MCF BELUGA GAS BURNS & MCOONNELL ENGINEERING COMPANY PAGE: 24 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT..D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%,20 mE 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER Cap ENERGY FACTOR VAR O+" ONLY COST NUMBER SOURCE (ri) (PH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 1991 5 INTERTIE 51.0 0. 0.0 0.00 Se 11 BELUGA 688 97.4 708603. 83.1 3.80 2.77 1568. 5566263. NCF BELUGA GAS 117.87 116.83 16557. 1391566. NCE NORTH GAS 12 BELUGA 7288 98.0 647347. 73.4 3.80 2.77 1432. 5085088. MCF BELUGA GAS 117.87 116.83 15126. 1271272. 3 NCF NORTH GAS 8 BELUGA 3 36.2 272726. 33.4 4.90 3.86 843. 2992938. NCF BELUGA GAS 164.26 163.22 8903. 748234. MCF NORTH GAS 10 BELUGA 5 61.3 180533. 33.6 4.90 3.86 558. 1981192. MCF BELUGA GAS 164.26 163.22 3893. 495298. MCF NORTH GAS 20 BERNICE 5 37.0 63550. 19.6 4.15 39.48 2007. 608252. MCF ENSTAR GAS 142.60 141.93 1804. 151610. MCF NORTH GAS 17 BELUGA 9 64.0 58577. 10.4 52.40 31.36 2407. 358984. MCF BELUGA GAS 142.97 141.93 1663. 139746. NCE NORTH GAS 7 BELUGA 182 34.0 18160. 5.8 60.10 59.06 858. 199296. MCF BELUGA GAS 164.26 163.22 593. 47824. MCF NORTH GAS BELUGA 4 10.0 3782. 4.3 60.10 39.06 179. 41507. MCF BELUGA GAS 164.26 163.22 123. 10377. MCF NORTH GAS 13 BERNICE 1 8.3 2756. 3.8 66.47 65.80 145. 43958. NCF ENSTAR GAS 237.22 236.55 130. 10957. MCF NORTH GAS 14 BERNICE 2 19.6 5202. 3.0 66.47 65.80 274, 82976. MCF ENSTAR GAS 237.22 236.55 24%. 20682. MCF NORTH GAS 15 BERNIC 384 54.0 7757. 1.6 66.47 65.80 408. 123736. MCF ENSTAR GAS 237.22 236.55 367. 30842. MCF NORTH GAS 18 KNIK ARM 10.0 891. 1.0 85.82 79.62 57. 17207. MCF ENSTAR GAS 292.42 286.22 51. 4289. MCF NORTH GAS 17 INTN 1,283 48.2 2412. 0.6 113.36 112.19 217. 65609. MCF ENSTAR GAS 404. 48 403.32 195. NCF 16 COOPER 182 17.2 38009. 38.5 1.17 1 AK P ADMIN § 14.0 91980. 75.0 16.05 —— 2 BRADLEY LA 48.0 178704. 30.0 6.82 == a3 SUPPL PURCH --——- 1654. _— 106.00 a TOTAL ALLOCATION 7352.2 2302644. 34.9 62604. TOTAL REQUIRED CAPACITY 579.9 SYSTEM REQUIREMENTS 315.0 2296000. SYSTEM LOAD FACTOR, % 50.9 FUEL TOTALS 4401. 15625481. MCF BELUGA GAS beg fe Le sit ewes 8 a wes ee BURNS & MCCONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 TABLE 4 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL UNIT POWER Cap ENERGY FACTOR VAR O+f ONLY NUMBER SOURCE (ru) (WH) (PCT) (MILLS/KWH) = (MILLS/KWH) YEAR ENDING DEC 31, 1991 PAGE: 25 DATE: 21-May-83 TIME: 09:24 FILES: CHNGT.Di GASGT..D2 VERSION: PS6-9/82 FUEL COST ($1000) AMOUNT OF FUEL 31652. 4341049. MCF NORTH GAS 3108. 941738. NCF ENSTAR GAS 3444. 799786. CF BELUGA GAS BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 26 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHMGT.01 BRADLEY LAKE, GAS-FIRED GENERATION GASGT..02 GENERATION AND TRANSHISSION COOP. PLAN: GAS (8%, 20 TABLE 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER CAP ENERGY FACTOR VAR ON ONLY COST NUMBER SOURCE (rw) (IH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 1992 5 INTERTIE 31.0 0. 0.0 0.00 te —— sate elereersaemennnerneraiane mona 11 BELUGA 688 97.4 708603. 83.1 3.98 2.86 1624. 5566263. NCF BELUGA GAS 127.30 126.18 17882. 1391566. MCF NORTH GAS 12 BELUGA 788 98.0 656744. 76.5 3.98 2.86 1505. 5158902. NCF BELUGA GAS 127.30 126.18 16573. 1289726. MCF NORTH GAS 8 BELUGA 3 36.2 278814. 36.6 5.12 4.00 893. 3059744. MCF BELUGA GAS 177.40 176.28 9830. 764936. MCF NORTH GAS 10 BELUGA 5 61.3 200469. 37.3 5.12 4.00 642. 2199977. MCF BELUGA GAS 177.40 176.28 7068. 349994. = MCF NORTH GAS 20 BERNICE 5 37.0 70837. 21.9 44.04 43.32 1841. 308504. NCF ENSTAR GAS 154.00 153.28 4343. 337992. MCF NORTH GAS 19 BELUGA 9 64.0 68739. 12.3 56.68 35.56 2291. 491972. CF BELUGA GAS 154. 40 153.28 4215. 327982. MCF NORTH GAS BELUGA 182 34.0 21710. 6.9 65.01 63.89 832. 178683. MCF BELUGA GAS 177.40 176.28 1531. 119122. NCE NORTH GAS BELUGA 4 10.0 4708. 3.4 65.01 63.89 180. 38750. HCF BELUGA GAS 177.40 176.28 332. 25833. MCF NORTH GAS 13 BERNICE 1 8.3 3380. 4.6 72.92 72.20 146. 40440. =NCF ENSTAR GAS 256.19 255.47 345. 26880. MCF NORTH GAS 14 BERNICE 2 19.6 6411. 3.7 72.92 72.20 278. 76704. MCF ENSTAR GAS 256.19 255.47 655. 50984. MCF NORTH GAS 15 BERNIC 384 54.0 9948. 2.0 72.92 72.20 431. 119020. NCF ENSTAR GAS 256.19 255.47 1017. 79110. NCE NORTH GAS 18 KNIK ARM 10.0 1142. 1.3 94.06 87.36 60. 16538. MCF ENSTAR GAS 315.82 309.12 141. 10993. MCF NORTH GAS 17 INTN 1,283 48.2 3191. 0.8 124.36 123.10 236. 65084. NCF ENSTAR GAS 436.84 435.58 356. 43260. MCF NORTH GAS 16 COOPER 182 17.2 38009. 38.5 1.26 1 AK P ADMIN § 14.0 91980. 73.0 17.66 —— 2 BRADLEY LA 68.0 178704. 30.0 7.36 naan 25 SUPPL PURCH ---~ 2361. ahem 135.00 scones TOTAL ALLOCATION 7352.2 2365750. 35.9 75447. TOTAL REQUIRED CAPACITY 399.5 SYSTEM REQUIREMENTS 332.0 2377000. SYSTEM LOAD FACTOR, % 51.0 FUEL TOTALS 4663. 15984886. MCF BELUGA GAS BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 27 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHNGT.01 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.02 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 mas 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL, UNIT POWER CAP ENERGY FACTOR VAR O+M ONLY COST NUMBER SOURCE (rd) (WH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 1992 64488. 5018376. MCF NORTH GAS 2992. 826270. MCF ENSTAR GAS 3304. 70946. MCF BELUGA GAS BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 28 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHNGT.01 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 TALE 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER CAP ENERGY FACTOR VAR O+f" ONLY cost NUMBER SOURCE (ri) (TWH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 1993 5 INTERTIE 51.0 Oo. 0.0 0.00 SSS Renee 11 BELUGA 688 97.4 708603. 83.1 4.07 2.86 1624. 5566263. MCF BELUGA GAS 137.48 136.27 19313. 1391566. MCF NORTH GAS 12 BELUGA 788 98.0 675843. 78.7 4.07 2.86 1549. 5308931. NCF BELUGA GAS 137.48 136.27 18420. 1327233. MCF NORTH GAS 8 BELUGA 3 56.2 289789. 58.9 5.21 4.00 928. 3180187. MCF BELUGA GAS 191.59 190.38 11034. 795047. MCF NORTH GAS 10 BELUGA 5 61.3 236086. 44.0 5.21 4.00 756. 2590847. MCF BELUGA GAS 191.59 190.38 8989. 647712. NCF NORTH GAS 20 BERNICE 5 37.0 83113. 25.6 48.54 47.76 1588. 397751. MCF ENSTAR GAS 166.32 165.55 8255. 594847. MCF NORTH GAS 19 BELUGA 9 64.0 85647. 15.3 61.21 60.00 2056. 408655. MCF BELUGA GAS 166.76 165.55 8507. 612983. MCF NORTH GAS BELUGA 182 36.0 28976. 9.2 70.21 69.00 800. 158993. MCF BELUGA GAS 191.59 190.38 3310. 238489. MCF NORTH GAS BELUGA 4 10.0 6109. 7.0 70.21 69.00 169. 33521. CF BELUGA GAS 191.59 190.38 698. 50282. MCF NORTH GAS 13 BERNICE 1 8.3 4591. 6.3 80.38 79.60 146. 36614. NCF ENSTAR GAS 276.69 275.91 760. 54758. NiCr NORTH GAS 14 BERNICE 2 19.6 8997. 5.2 80.38 79.60 286. 71760. CF ENSTAR GAS 276.69 275.91 1489. 107319. NcF NORTH GAS 15 BERNIC 384 54.0 14533. 3.0 80.38 79.60 443. 115917. NCF ENSTAR GAS 276.69 275.91 2406. 173356. MCF NORTH GAS 18 KNIK ARN 10.0 1742. 2.0 103.55 96.32 67. 16817. CF ENSTAR GAS 341.08 333.85 349. 25150. MCF NORTH GAS 17 INTN 1,283 48.2 5080. 1.2 137.08 135.72 276. 69088. NCF ENSTAR GAS 471.79 470.43 1434. 103324. MCF NORTH GAS 16 COOPER 182 17.2 58009. 38.5 1.36 HYDRO 1 AK P ADMIN 14.0 91980. 75.0 17.66 —— KR RRNA 2 BRADLEY LA 468.0 178704. 30.0 7.95 Sn eee emrrenenemnnenememen ene 2 SUPPL PURCH ---— 4062. —_— 168.00 SO erence amen TOTAL ALLOCATION 752.2 2481865. 37.7 95670. TOTAL REQUIRED CAPACITY 621.3 SYSTEM REQUIREMENTS 551.0 2466000. SYSTEN LOAD FACTOR, % 51.1 FUEL TOTALS 4856. 16646228. CF BELUGA GAS i) ‘ ia kn ; bot eel BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: @2-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 TABLE 4 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL UNIT POWER Cap ENERGY FACTOR VAR O+" ONLY NUMBER SOURCE (rd) (PH) (PCT) (MILLS/KWH) = (MILLS/KWH) YEAR ENDING DEC 31, 1993 ~ - - ~ » - ™ RE Pes TIME: 09:24 FILES: CHHGT.D1 GASGT.02 VERSION: PS6-9/82 FUEL cost ($1000) AMOUNT OF FUEL 84964. 6122065. MCF NORTH GAS 2826. 707947. HEF ENSTAR GAS 3024. 601170. MCF BELUGA GAS pie CHUGACH, PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM HOMER & MATANUSKA ELEC. ASSOCIATIONS PAGE: 30 UNIT POWER Cap NUMBER SOURCE Cr) YEAR ENDING DEC 31, 1994 5 INTERTIE 31.0 11 BELUGA 688 97.4 12 BELUGA 788 98.0 8 BELUGA 3 56.2 10 BELUGA 5 61.3 20 BERNICE 5 37.0 19 BELUGA 9 64.0 BELUGA 182 34.0 BELUGA 4 10.0 13 BERNICE 1 8.3 14 BERNICE 2 19.6 15 BERNIC 384 54.0 18 KNIK ARM 10.0 17 INTN 1,283 48.2 16 COOPER 182 17.2 1 AK P ADMIN § 14.0 2 BRADLEY LA 48.0 23 SUPPL PURCH ---~ TOTAL ALLOCATION 752.2 TOTAL REQUIRED CAPACITY 643.2 SYSTEM REQUIREMENTS 570.0 SYSTEM LOAD FACTOR, % 51.2 TABLE 4 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE CAPACITY FUEL PLUS FUEL ENERGY FACTOR VAR O+M ONLY (WH) (PCT) (MILLS/KWH) (MILLS/KWH) 0. 0.0 0.00 708603. 83.1 4.27 2.96 148. 48 147.17 683783. 79.7 4.27 2.96 148. 48 147.17 295792. 460.1 5.45 4.14 206.91 205.61 255341. 47.6 5.45 4.14 206.91 205.61 88526. 27.3 53.28 52.44 179.63 178.79 93971. 16.8 66.11 64.80 180.10 178.79 32349. 10.3 75.83 74.52 206.91 205.61 6789. 7.8 75.83 74.52 206.91 205.61 5048. 6.9 88.24 87.40 298.82 297.98 10033. 5.8 88.24 87.40 278.82 297.98 16548. 3.4 88.24 87.40 298.82 297.98 1991. 2.3 113.56 105.75 348.37 360.56 5838. 1.4 150. 49 149.02 309.53 508.06 38009. 38.5 1.47 91980. 735.0 17.66 178704. 30.0 8.59 4867. —ome 206.00 2538392. 38.5 2557000. DATE: 21-May-83 TIME: 09:24 FILES: CHNGT.D1 GASGT.D2 VERSION: PS6-9/82 FUEL COST ($1000) AMOUNT OF FUEL 1680. 5566263. MCF BELUGA GAS 20858. 13915446. MCF NORTH GAS 1622. 5372871. MCF BELUGA GAS 20133. 1343218. MCF NORTH GAS 980. 3246072. NCF BELUGA GAS 12163. 811518. MCF NORTH GAS 846. 2802157. MCF BELUGA GAS 10500. 700539. MCF NORTH GAS 928. 211826. MCF ENSTAR GAS 12662. 844777. = NCF NORTH GAS 1218. 224186. MCF BELUGA GAS 13441. 896744. = NCF NORTH GAS 482. 88751. MCF BELUGA GAS 5321. 355003. MCF NORTH GAS 101. 18626. NCF BELUGA GAS 1117. 74505. MCF NORTH GAS 88. 20132. MCF ENSTAR GAS 1203. 80287. MCF NORTH GAS 175. 40012. MCF ENSTAR GAS 2392. 159569. MCF NORTH GAS 270. 66075. MCF ENSTAR GAS 3950. 263512. MCF NORTH GAS 42. 9608. MCF ENSTAR GAS 574. 38319. = MCF NORTH GAS 174. 39694. = NCF ENSTAR GAS 2373. 158304. MCF NORTH GAS 115312. FUEL TOTALS 5127. 16987363. MCF BELUGA GAS BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 TABLE 4 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL, UNIT POWER CAP ENERGY FACTOR VAR Ot ONLY COST NUMBER SOURCE (mW) (IH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) YEAR ENDING DEC 31, 1994 106687. 1698. 1801. DATE: 2i-tHay-2a TIME: 09:24 FILES: CHNGT.D1 GASGT.D02 VERSION: PS6-9/82 AMOUNT OF FUEL 7117862. MCF NORTH GAS 387348 CF ENSTAR GAS 331563. MCF BELUGA GAS BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 32 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHNMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 tame 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER CAP ENERGY FACTOR VAR O+M ONLY COST NUMBER SOURCE (mW) (AH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 1995 2 INTERTIE 51.0 0. 0.0 0.00 ae" een anne tener etienenT il BELUGA 688 97.4 708603. 83.1 4.37 2.96 1260. 4174697. MCF BELUGA GAS 160. 36 158.95 45052. 2783132. MCF NORTH GAS 12 BELUGA 788 98.0 695224. 81.0 4.37 2.96 1236. 4095879. MCF BELUGA GAS 160.36 158.95 44202. 2730586. MCF NORTH GAS 8 BELUGA 3 36.2 309297. 62.8 5.55 4.14 768. 2545703. MCF BELUGA GAS 223.47 222.06 27473. 1697135. NCF NORTH GAS 10 BELUGA 5 61.3 277138. 31.6 5.55 4.14 688. 2281020. MCF BELUGA GAS 223.47 222.06 24616. 1520680. MCF NORTH GAS 20 BERNICE 5 37.0 108725. 33.5 58.463 57.72 0. 0. NCE ENSTAR GAS 194.00 193.09 20994. 1296922. NCF NORTH GAS 19 BELUGA 9 64.0 110891. 19.8 71.37 $9.96 0. 0. MCF BELUGA GAS 194.50 193.09 21412. 81322752. MCF NORTH GAS 7 BELUGA 182 36.0 38938. 12.3 81.86 80. 45 0. 0. MCF BELUGA GAS 223.47 222.06 8646. 534138. MCF NORTH GAS BELUGA 4 10.0 8799. 10.0 81.86 80. 45 0. 0. MCF BELUGA GAS 223.47 222.06 1954. 120699. MCF NORTH GAS 13 BERNICE 1 8.3 6480. 8.9 97-11 96.20 0. oO. MCF ENSTAR GAS 322.73 321.82 2085. 128826. MCF NORTH GAS 14 BERNICE 2 19.6 12670. 7.4 97.11 96.20 0. 0. MCF ENSTAR GAS 322.73 321.82 478. 251895. NCF NORTH GAS 15 BERNIC 384 56.0 21888. 4.5 97.11 96.20 0. 0. NCE ENSTAR GAS 322.73 321.82 7044. 435148. NCF NORTH GAS 18 KNIK ARM 10.0 2728. 3.1 124.84 116.40 0. Oo. MCF ENSTAR GAS 397.84 389.40 1062. 65623. MCF NORTH GAS 17 INTN 1,283 48.2 8254. 2.0 145.61 164.02 0. 0. MCF ENSTAR GAS 550.29 348.71 4529. 279778. WCF NORTH GAS 16 COOPER 182 17.2 38009. 38.5 1.59 HYDRO 1 AK P ADMIN §=14.0 91980. 75.0 19.42 seanenee:| | | eunetenenreep-oermemetenenteenenestenentnneneerereinnntet 2 BRADLEY LA 68.0 178704. 30.0 9.27 ——————————— 23 SUPPL PURCH --— 7267. ae 248.00 SAE: ___ SEER RTE NNNIN NEN TOTAL ALLOCATION 752.2 2645595. 40.2 217101. TOTAL REQUIRED CAPACITY 665.1 SYSTEM REQUIREMENTS 5897.0 2647000. SYSTEM LOAD FACTOR, % 51.3 FUEL TOTALS 3953. 13097300. NCF BELUGA GAS . . - . r - rc oo ety aor eo oc oe oe oes am og BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 33 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 ums 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER Cap ENERGY FACTOR VAR O+f ONLY COST NUMBER SOURCE cr) (WH) (PCT) <(MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 1995 213148. 13167315. MCF NORTH GAS a 7% BURNS & NCDONNELL ENGINEERING COMPANY PAGE: 34 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TINE: 09:24 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT. D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (82,20 recta VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER CAP ENERGY FACTOR VAR O+M ONLY cost NUMBER SOURCE (rd) (WH) (PCT) = (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 1996 = INTERTIE 51.0 0. 0.0 0.00 eee eee emer 11 BELUGA 688 97.4 708603. 83.1 4.59 3.06 868. 2783132. MCF BELUGA GAS 173.19 171.66 72985. 4174697. MCF NORTH GAS 12 BELUGA 728 8698.0 700402. 81.6 4.59 3.06 858. 2750924. NCF BELUGA GAS 173.19 171.66 72140. 4126386. MCF NORTH GAS 8 BELUGA 3 36.2 327149. 66.5 5.80 4.28 5360. 1795090. NCF BELUGA GAS 241.34 239.82 47074. 2692635. MCF NORTH GAS 10 BELUGA 5 61.3 294690. 54.9 5.80 4.28 504. 1616985. MCF BELUGA GAS 241.34 239.82 42404. 2425478. MCF NORTH GAS 20 BERNICE 5 37.0 133065. 41.1 64.46 63. 48 0. 0. MCF ENSTAR GAS 209.52 208.54 27749. = 1587258. MCF NORTH GAS 19 BELUGA 9 64.0 131922. 23.5 77.12 75.60 0. 0. NF BELUGA GAS 210.06 208.54 27511. 1573628. NCF NORTH GAS BELUGA 182 36.0 46479. 14.7 88. 46 86.94 0. 0. NCF BELUGA GAS 241.34 239.82 11147. 637590. NCF NORTH GAS BELUGA 4 10.0 10624. 12.1 88. 46 86.94 0. 0. MCF BELUGA GAS 241.34 239.82 2548. 145736. CF NORTH GAS 13 BERNICE 1 8.3 8102. 11.1 106.78 105.80 0. 0. NCF ENSTAR GAS 348.55 347.57 2816. 161080. MCF NORTH GAS 14 BERNICE 2 19.6 16178. 9.4 106.78 105.80 0. 0. MCF ENSTAR GAS 348.55 347.57 3623. 321632. MCF NORTH GAS i5 BERNIC 384 56.0 28472. 5.8 106.78 105.80 0. 0. NCF ENSTAR GAS 348.55 347.57 9896. 566040. MCF NORTH GAS 18 KNIK ARM 10.0 3641. 4.2 137.13 128.02 0. 0. ACF ENSTAR GAS 429.67 420.56 1531. 87584. NCF NORTH GAS 17 INTN 1,283 48.2 11442. 2.7 182.10 180.39 0. 0. MCF ENSTAR GAS 594.32 592.60 6780. 387840. CF NORTH GAS 16 COOPER 182 17.2 58009. 38.5 1.71 HYDRO 1 AK P ADMIN 14.0 91980. 75.0 19.42 a 2 BRADLEY LA 68.0 178704. 30.0 10.02 ne 25 SUPPL PURCH ---~ 10985. — 295.00 eer TOTAL ALLOCATION 732.2 2760446. 41.9 332995. TOTAL REQUIRED CAPACITY 688.1 SYSTEM REQUIREMENTS 609.0 2742000. SYSTEM LOAD FACTOR, % 51.4 FUEL TOTALS 2790. 8946131. MCF BELUGA GAS b i . ae ret tt : : Se aeee BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 35 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 meme 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL, UNIT POWER Cap ENERGY FACTOR VAR O+M ONLY COST NUMBER SOURCE Crd) (WH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 1996 330205. 18887584. MCF NORTH GAS a BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 36 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (82,20 TABLE 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER CAP ENERGY FACTOR VAR O+fM ONLY cosT NUMBER SOURCE (IW) (WH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 1997 5 INTERTIE 31.0 0. 0.0 0.00 ee arene il BELUGA 688 97.4 708603. 83.1 4.71 3.06 0. 0. MCF BELUGA GAS 187.04 185. 40 131373. 6957829. MCF NORTH GAS 12 BELUGA 7288 98.0 702236. 81.8 4.71 3.06 0. 0. MCF BELUGA GAS 187.04 185.40 130192. 6895315. MCF NORTH GAS 20 BERNICE 5 37.0 233788. 72.1 70.90 69.84 0. 0. MCF ENSTAR GAS 226.28 225.22 52655. 2788729. MCF NORTH GAS 19 BELUGA 9 64.0 333437. 59.5 83.24 81.40 0. 0. NCE BELUGA GAS 226.87 225.22 75098. 3977379. CF NORTH GAS BELUGA 182 34.0 158259. 30.2 95.48 93.84 0. oO. MCF BELUGA GAS 260.65 259.01 40990. 2170944. = NCE NORTH GAS BELUGA 3 36.2 163856. 33.3 5.92 4.28 0. 0. MCF BELUGA GAS 260.45 2597.01 4244. 2247721. MCF NORTH GAS BELUGA 4 10.0 21044. 24.0 95.48 93.84 0. 0. MCF BELUGA GAS 260.45 259.01 5451. 288673. MCF NORTH GAS 10 BELUGA 5 61.3 90847. 16.9 5.92 4.28 0. 0. MCF BELUGA GAS 260.45 259.01 23530. 1246218. MCF NORTH GAS 13 BERNICE 1 8.3 9248. 12.7 117.46 116.40 0. 0. NCE ENSTAR GAS 376.43 375.37 3471. NCF 14 BERNICE 2 19.6 18653. 10.9 117.46 116.40 0. NCE 376.43 375.37 7002. NCE 15 BERNIC 324 54.0 33622. 6.9 117.46 116.40 0. NCF 376.43 375.37 12621. NCE 18 KNIK ARM 10.0 4314. 4.9 150.68 140.84 0. NCE 464.04 454. 20 1959. NCE 17 INTN 1,283 48.2 13851. 3.3 200.31 198.46 0. NCE 641.86 640.01 8865. CF 16 COOPER 182 17.2 58009. 38.5 1.85 1 AK P ADMIN § 14.0 91980. 73.9 19.42 renee 2 BRADLEY LA 48.0 178704. 30.0 10.82 = 23 SUPPL PURCH ---~ 14298. —_ 348.00 = TOTAL ALLOCATION 7352.2 2834747. 43.0 535647. TOTAL REQUIRED CAPACITY 712.2 SYSTEM REQUIREMENTS 630.0 2842000. SYSTEM LOAD FACTOR, % 51.5 FUEL TOTALS BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 37 POWER SUPPLY PROGRAM DATE: 2i-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (82, 20 come 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL, UNIT POWER CAP ENERGY FACTOR VAR OM ONLY cost NUMBER SOURCE «Mu (WH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 1997 335647. 28369193. MCF NORTH GAS BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 UNIT POWER Cap NUMBER SOURCE (rd) YEAR ENDING DEC 31, 1998 5 INTERTIE 51.0 il BELUGA 688 97.4 12 BELUGA 788 98.0 20 BERNICE 5 37.0 19 BELUGA 9 64.0 BELUGA 122 36.0 BELUGA 3 36.2 BELUGA 4 10.0 10 BELUGA 5 61.3 13 BERNICE 1 8.3 14 BERNICE 2 19.6 15 BERNIC 384 54.0 18 KNIK ARM 10.0 17 INTN 1,283 48.2 16 COOPER 182 17.2 1 AK P ADMIN 14.0 2 BRADLEY LA 68.0 25 SUPPL PURCH ---- TOTAL ALLOCATION 752.2 TOTAL REQUIRED CAPACITY 737.5 SYSTEM REQUIREMENTS 652.0 SYSTEM LOAD FACTOR, % 51.6 weet TABLE 4 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE ENERGY (WH) 708603. 705497. 247495. 345921. 169585. 195833. 24852. 109972. 11388. 23227. 43644. 5742. 19049, 58009. 178708. 21106. 2960596. 2947000. CAPACITY FUEL PLUS FACTOR VAR O+M (PCT) 030 82.2 76.4 61.7 53.8 39.8 28.4 20.5 15.7 13.5 8.9 6.6 4.5 38.5 75.0 39.0 44.9 (MILLS/KWH) 0.00 4.94 202.01 4.94 202.01 77.94 244. 38 89.86 245.02 103.07 281.50 6.19 281.50 103.07 281.50 6.19 281.50 129.14 406.55 129.14 406.55 129.14 406.55 165.51 501.16 220.24 693.21 2.00 21.37 11.48 407.00 FUEL FUEL ONLY cost (MILLS/KWH) ($1000) 3.16 0. 200.23 141883. 3.16 0. 200.23 141259. 76.80 0. 243.24 60201. 88.08 0. 243.24 84142. 101.29 0. 279.73 47438. 4.42 0. 279.73 34780. 101.29 0. 279.73 6952. 4.42 0. 279.73 30762. 128.00 0. 405.40 4617. 128.00 0. 405.40 9416. 128.00 0. 405.40 17694. 154.88 0. 490.54 2817. 218.24 0. 691.21 13167. 615126. PAGE: _38 DATE: 21-May-83 TIME: 09:24 FILES: CHMGT.D1 GASGT.D2 VERSION: PS6-9/82 AMOUNT OF FUEL 0. NCE BELUGA GAS 6957829. NCE NORTH GAS 0. MCF BELUGA GAS 6927241. MCF NORTH GAS 0. MCF ENSTAR GAS 2952225. NCF NORTH GAS 0. MCF BELUGA GAS 4126292. MCF NORTH GAS 0. MCF BELUGA GAS 2326313. MCF NORTH GAS 0. NCE BELUGA GAS 2686376. MCF NORTH GAS 0. NCE BELUGA GAS 340917. MCF NORTH GAS 0. MCF BELUGA GAS 1508557. MCF NORTH GAS 0. MCF ENSTAR GAS 226392. MCF NORTH GAS 0. NCF ENSTAR GAS 461772. MCF NORTH GAS 0. MCF ENSTAR GAS 867682. NCF NORTH GAS 0. MCF ENSTAR GAS 138128. MCF NORTH GAS 0. MCF ENSTAR GAS 645688. MCF NORTH GAS HYDRO FUEL TOTALS BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 39 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHMNGT.01 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 ee VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER Cap ENERGY FACTOR VAR O+f ONLY COST NUMBER SOURCE Crd) WH) (PCT) = (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 1998 615126. 30165412. MCF NORTH GAS BURNS & NCDONNELL ENGINEERING COMPANY PAGE: 40 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION : GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (82,20 ae VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER Cap ENERGY FACTOR VAR O+M ONLY cOosT NUMBER SOURCE (mW) (TWH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) YEAR ENDING DEC 31, 1999 s INTERTIE 31.0 0. 0.0 0.00 ——— il BELUGA 688 97.4 708603. 83.1 5.08 3.16 0. 218.17 216.25 153233. 12 BELUGA 788 98.0 706300. 82.3 5.08 3.16 0. 218.17 216.25 152735. 20 BERNICE 5 37.0 252315. 77.8 85.71 84. 48 0. 263.93 262.70 66283. 19 BELUGA 9 64.0 352992. 63.0 97.08 95.16 0. 264.62 262.70 92732. 7 BELUGA 182 34.0 174391. 53.3 111.35 109. 43 0. 304.02 302.11 32685. BELUGA 3 36.2 212836. 43.2 4.33 4. 42 0. 304.02 302.11 64299. 9 BELUGA 4 10.0 27091. 3.9 111.35 109. 43 0. 304.02 302.11 8184. 10 BELUGA 5 61.3 120634. 22.5 6.33 4. 42 0. 304.02 302.11 36444. 6 ADDTNL PUR 10.6 18861. 20.3 4397.00 et 13 BERNICE 1 8.3 11070. 15.2 142.03 140.80 0. 439.07 437.84 4847. 14 BERNICE 2 19.6 22685. 13.2 142.03 140.80 0. 439.07 437.84 9932. 15 BERNIC 324 54.0 42704. 8.7 142.03 140.80 0. 439.07 437.84 18497. 18 KNIK ARM 10.0 5594, 6.4 181.84 170.37 0. 341.26 329.78 2964, 17 INTN 1,283 48.2 18546. 4.4 242.22 240.06 0. 748.67 746.51 13845. 16 COOPER 182 17.2 58009. 38.5 2.16 1 AK P ADMIN § 14.0 91980. 75.0 21.37 a 2 BRADLEY LA 68.0 178704. 30.0 12.62 — 23 SUPPL PURCH ---- 20987. ee 439.00 ne TOTAL ALLOCATION 762.8 3024302. $5.3 676881. TOTAL REQUIRED CAPACITY 762.8 SYSTEM REQUIREMENTS 674.0 3052000. SYSTEM LOAD FACTOR, % 51.7 FUEL TOTALS BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP... PLAN: GAS (8%, 20 TABLE 4 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL UNIT POWER Cap ENERGY FACTOR VAR O+f" ONLY NUMBER SOURCE (ru) (WH) (PCT) = (MILLS/KWH) = (MILLS/KWH) YEAR ENDING DEC 31, 1999 BE ala Tite: 09:24" FILES: CHMGT.D1 GASGT. D2 VERSION: PS6-9/82 FUEL cost ($1000) AMOUNT OF FUEL 676881. 30795019. MCF NORTH GAS inl BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 42 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: €2-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%,20 TALE 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE CAPACITY FUEL PLUS FUEL. FUEL UNIT POWER CAP ENERGY FACTOR VAR ON ONLY COST NUMBER SOURCE (rd) (WH) (PCT) = (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 2000 5 INTERTIE 31.0 0. 0.0 0.00 SS 11 BELUGA 688 97.4 708603. 83.1 5.33 3.26 0. 0. MCF BELUGA GAS 235.62 233.55 165492. 6957829. MCF NORTH GAS 12 BELUGA 788 98.0 708520. 82.5 5.33 3.26 0. 0. MCF BELUGA GAS 235.62 233.55 165472. 6957015. MCF NORTH GAS 20 BERNICE 5 37.0 257719. 79.5 94.33 93.00 0. 0. MCF ENSTAR GAS 285.05 283.72 73119. 3074181. MCF NORTH GAS 19 BELUGA 9 64.0 372361. 66.4 104.79 102.72 0. 0. MCF BELUGA GAS 285.79 283.72 105645. 4441679. MCF NORTH GAS 7 BELUGA 182 9.36.0 183344, 58.1 120.20 118.13 0. Oo. MCF BELUGA GAS 328.35 326.27 597820. 2515052. MCF NORTH GAS BELUGA 3 56.2 237904. 48.3 6.63 4.55 0. 0. MCF BELUGA GAS 328.35 326.27 77622. 3263498. MCF NORTH GAS 9 BELUGA 4 10.0 34806. 39.7 120.20 118.13 0. 0. NEF BELUGA GAS 328.35 326.27 11356. 477458. NCE NORTH GAS 10 BELUGA 5 61.3 146799. 27.3 6.63 4.55 0. 0. ME BELUGA GAS 328.35 326.27 47897. 2013748. NCF NORTH GAS 6 ADDTNL PUR 37.1 71691. 22.1 474.00 SSS SS 13 BERNICE 1 8.3 10306. 14.2 156.33 155.00 0. 0. MCF ENSTAR GAS 474.19 472.86 4873. 204893. MCF NORTH GAS 14 BERNICE 2 19.6 21176. 12.3 156.33 155.00 0. 0. MCF ENSTAR GAS 474.19 472.84 10013. 420991. MCF NORTH GAS 15 BERNIC 384 54.0 39980. 8.1 156.33 155.00 0. 0. MCF ENSTAR GAS 474.19 472.86 18905. 794829. CF NORTH GAS 18 KNIK ARM 10.0 5321. 6.1 199.95 187.55 0. 0. MCF ENSTAR GAS 584.56 972.16 3044. 127991. NCE NORTH GAS 17 INTN 1,283 48.2 17786. 4.2 266.61 264.28 0. 0. MCF ENSTAR GAS 808. 56 806.23 14340. nCF 16 COOPER 182 17.2 58009. 38.5 2.33 1 AK P ADMIN § 14.0 91980. 75.0 21.37 eres 2 BRADLEY LA 68.0 178704. 30.0 13.63 25 SUPPL PURCH ---- 20987. pane 474.00 an TOTAL ALLOCATION 789.3 3165994. 45.8 757600. TOTAL REQUIRED CAPACITY 789.3 SYSTEM REQUIREMENTS 697.0 3163000. SYSTEM LOAD FACTOR, % 51.8 FUEL TOTALS BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 43 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 “er 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL, UNIT POWER CAP ENERGY FACTOR VAR O+N ONLY COST NUMBER SOURCE (rw) (TWH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 2000 737600. 31852048. MCF NORTH GAS BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 44 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOPER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHNMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (82,20 rae VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER CAP ENERGY FACTOR VAR OH" ONLY COST NUMBER SOURCE (rw) (TWH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 2001 5 INTERTIE 31.0 0. 0.0 0.00 emma _ SE ENEPEERETHEerERERReRREENENES EERSTE 21 200MW CC 100.0 753360. 86.0 223.99 219.60 165436. 6440255. NCF NORTH GAS 11 BELUGA 688 97.4 705393. 82.7 5.50 3.26 0. 0. MCF BELUGA GAS 254.47 252.23 177922. 6926316. MCF NORTH GAS 12 BELUGA 788 98.0 620152. 72.2 5.50 3.26 0. 0. MCF BELUGA GAS 254. 47 252.23 156421. 6089922. MCF NORTH GAS 20 BERNICE 5 37.0 194874. 60.1 103.68 102.24 0. 0. NCE ENSTAR GAS 307.85 306. 41 59712. 2324546. MCF NORTH GAS 19 BELUGA 9 64.0 280643. 50.1 113.24 111.00 0. 0. MCF BELUGA GAS 308. 65 306. 41 85993. 3347632. MCF NORTH GAS BELUGA 182 34.0 114810. 346.4 129.89 127.45 0. 0. MCF BELUGA GAS 354.61 352.38 40456. 1574924. MCF NORTH GAS BELUGA 3 56.2 118698. 24.1 4.79 4.55 0. 0. NCE BELUGA GAS 354.61 352.38 41826. 1628257. MCF NORTH GAS BELUGA 4 10.0 16484. 18.8 129.89 127,65 0. 0. NCE BELUGA GAS 354. 61 352.38 3809. 226150. MCF NORTH GAS 10 BELUGA 5 61.3 73190. 13.6 6.79 4.55 0. 0. NCE BELUGA GAS 354. 61 352.38 25790. 1003797. NCF NORTH GAS 13 BERNICE 1 8.3 7546. 10.4 171.84 170.40 0. 0. MCF ENSTAR GAS 512.13 310.49 3854. 150018. MCF NORTH GAS 14 BERNICE 2 19.6 15546. Fel 171.84 170.40 0. 0. MCF ENSTAR GAS 512.13 510.49 7939. 309071. NCF NORTH GAS 15 BERNIC 384 56.0 297110. 5.9 171.84 170.40 0. 0. MCF ENSTAR GAS 512.13 310.69 14866. 578720. MCF NORTH GAS 18 KNIK ARM 10.0 39715. 4.5 219.57 206.18 0. 0. MCF ENSTAR GAS 631.32 617.94 2419. 94174. CF NORTH GAS 17 INTN 1,283 48.2 13148. 3.1 273.05 290.53 0. 0. MCF ENSTAR GAS 873.25 870.73 11448. 445660. NCF NORTH GAS 16 COOPER 182 17.2 58009. 38.5 2.52 1 AK P ADMIN § 14.0 91980. 75.0 23.50 mearineenis 2 BRADLEY LA 48.0 178704. 30.0 14.72 i 2 SUPPL PURCH ---— 15385. _- 512.00 —— TOTAL ALLOCATION 852.2 3290947. 44.1 799893. TOTAL REQUIRED CAPACITY 816.8 SYSTEM REQUIREMENTS 721.0 3278000. SYSTEM LOAD FACTOR, % 51.9 FUEL TOTALS BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 45 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.02 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 etn VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER CAP ENERGY FACTOR VAR O+M" ONLY cost NUMBER SOURCE (rd) (MJH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 2001 7998973. 311397042. MCF NORTH GAS BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 46 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (82,20 me A VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER Cap ENERGY FACTOR VAR O+M ONLY cost NUMBER SOURCE (rid) (TWH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 2002 5 INTERTIE 31.0 0. 0.0 0.00 aaa aeee nat 21 200M CC 100.0 733360. 86.0 241.91 237.17 178671. 6440255. MCF NORTH GAS 11 BELUGA 688 97.4 706781. 82.8 5.78 3.36 0. 0. MCF BELUGA GAS 274.83 272.41 192533. 6939943. MCF NORTH GAS 12Z BELUGA 788 898.0 643058. 74.9 5.78 3.36 0. 0. MCF BELUGA GAS 274.83 272.41 175175. 6314241. NCF NORTH GAS 20 BERNICE 5 37.0 201035. 62.0 113.99 112.44 0. 0. MCF ENSTAR GAS 332. 48 330.93 66528. 2398031. MCF NORTH GAS 19 BELUGA 9 64.0 299959. 53.5 122.30 119.88 0. 0. MCF BELUGA GAS 333.34 330.93 99265. 3578045. MCF NORTH GAS BELUGA 182 34.0 135207. 42.9 140.28 137.86 0. 0. MCF BELUGA GAS 382.98 380.57 51455. 1854723. MCF NORTH GAS BELUGA 3 36.2 135585. 27.5 7.11 4.69 0. 0. MCF BELUGA GAS 382.98 380.57 51599. 1859918. MCF NORTH GAS BELUGA 4 10.0 19901. 22.7 140.28 137.86 0. 0. MCF BELUGA GAS 382.98 380.57 7374. 272992. MCF NORTH GAS 10 BELUGA 5 61.3 85187. 15.9 7.11 4.69 0. 0. MCF BELUGA GAS 382.98 380.57 32419. 1168568. MCF NORTH GAS 13 BERNICE 1 8.3 9035. 12.4 188.95 187.40 0. 0. MCF ENSTAR GAS 553.10 551.55 4983. 179617. CF NORTH GAS 14 BERNICE 2 19.6 18328. 10.7 188.95 187.40 0. 0. MCF ENSTAR GAS 553.10 551.55 10109. 364369. NCF NORTH GAS 15 BERNIC 384 56.0 35804. 7.3 188.95 187.40 0. 0. MCF ENSTAR GAS 353.10 551.55 19747. 711800. MCF NORTH GAS 18 KNIK ARM 10.0 4797. 5.5 241.21 226.75 0. 0. MCF ENSTAR GAS 681.83 667.37 3201. 115393. NCF NORTH GAS 17 INTN 1,283 48.2 16190. 3.8 322.24 319.52 0. 0. MCF ENSTAR GAS 943.11 940.39 15225. 548802. MCF NORTH GAS 16 COOPER 182 17.2 58009. 38.5 2.72 7 AK P ADMIN 14.0 91980. 75.0 23.50 — 2 BRADLEY LA 48.0 178704. 30.0 15.89 —- 2 SUPPL PURCH ---~ 20284. —w 553.00 ———— TOTAL ALLOCATION 852.2 3413203. 5.7 908485. TOTAL REQUIRED CAPACITY 845.6 SYSTEM REQUIREMENTS 746.0 3398000. SYSTEM LOAD FACTOR, % 52.0 FUEL TOTALS ~ erie oe “oe ao — eo wey | a | ony ey Boy wey BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 47 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 cn 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL, UNIT POWER CAP ENERGY FACTOR VAR O+f ONLY COST NUMBER SOURCE cry (UH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 2002 908485. 32746696. MCF NORTH GAS BURNS & MCDONNELL ENGINEERING COMPANY CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 UNIT POWER NUMBER SOURCE YEAR ENDING DEC 31, 2003 5 INTERTIE al 200MW CC 11 BELUGA 688 12 BELUGA 788 20 BERNICE 5 19 BELUGA 7 7 BELUGA 182 BELUGA 3 9 BELUGA 4 10 BELUGA 5 6 ADDTNL PUR 13 BERNICE 1 14 BERNICE 2 15 BERNIC 384 18 KNIK ARM 17 INTN 1,283 16 COOPER 182 1 AK P ADMIN 2 BRADLEY LA 3 SUPPL PURCH TOTAL ALLOCATION TOTAL REQUIRED CAPACITY SYSTEM REQUIRENENTS SYSTEM LOAD FACTOR, % Cap oD) 100.0 97.4 98.0 37.0 64.0 36.0 56.2 10.0 61.3 23.3 8.3 19.6 36.0 10.0 48.2 17.2 14.0 68.0 875.5 875.5 772.0 52.1 POWER SUPPLY PROGRAN TABLE 4 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE ENERGY (WH) 753360. 707068. 652767. 203979. 308717. 144569. 154693. 21673. 96955. 32654. 8006. 16620. 32321. 4391. 14840. 58009. 91980. 178704. 19038. 3500343. 3523000. CAPACITY FUEL PLUS FACTOR VAR O+M (PCT) 0.0 82:9 76.0 62.9 55.1 45.8 31.4 24.7 18.1 16.0 11.0 9.7 6.6 5.0 3.5 38.5 75.0 30.0 45.6 (MILLS/KWH) 0.00 261.27 5.97 296.81 5.97 296.81 125.40 359.08 132.09 3460.01 151.51 413.62 7.30 413.62 151.51 413.62 7.30 413.62 397.90 207.88 597.35 207.88 597.35 207.88 597.35 265.12 736.38 354.51 1018.55 2.94 23.50 17.16 597.00 FUEL ONLY (MILLS/KWH) 256.14 3.36 294.20 3.36 294.20 123.72 357.40 129.48 357.40 148.90 411.01 4.69 411.01 148.90 411.01 4.69 411.01 206.20 395.67 206.20 595.67 206.20 595.67 249.50 720.76 351.57 1015.62 FUEL COST ($1000) 192964. PAGE: 48 DATE: 21-May-83 TIME: 09:24 FILES: CHNGT.D1 GASGT.D2 VERSION: PS6-9/82 105626. 503041. SRARAGaaS ENSTAR GAS NORTH GAS ENSTAR GAS NORTH GAS ENSTAR GAS NORTH GAS HYDRO BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 49 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 “ena VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER CAP ENERGY FACTOR VAR O+M ONLY COST NUMBER SOURCE (rt) (TWH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 2003 FUEL TOTALS 1000185. 33381535. MCF NORTH GAS BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 50 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT. D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 TALE 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER Cap ENERGY FACTOR VAR ON ONLY COST NUMBER SOURCE (rw) (TWH) (PCT) = (MILLS/KWH) 9 <(MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 2004 5 INTERTIE 51.0 0. 0.0 0.00 A — AAT eee eee ai 200MW CC 100.0 733360. 96.0 282.17 276.63 208401. 6440255. NCF NORTH GAS 11 BELUGA 688 97.4 707910. 83.0 6.28 3.46 0. 0. MCF BELUGA GAS 320.56 317.74 224930. 6951026. MCF NORTH GAS 12 BELUGA 788 98.0 672544. 78.3 6.28 3.46 0. 0. MCF BELUGA GAS 320.56 317.74 213692. 6603764. NCF NORTH GAS 20 BERNICE 5 37.0 210211. 64.9 137.89 136.08 0. 0. NCF ENSTAR GAS 387.81 385.99 81140. 2507492. NCF NORTH GAS 19 BELUGA 9 64.0 324058. 57.8 142.62 139.80 0. 0. MCF BELUGA GAS 388.81 385.99 125084. 3865500. NCF NORTH GAS 7 BELUGA 182 34.0 134668. 49.0 163.59 160.77 0. 0. MCF BELUGA GAS 446.71 443.89 68656. 2121687. NCF NORTH GAS BELUGA 3 36.2 186109. 37.8 7.65 4.83 0. 0. MCF BELUGA GAS 446.71 443.89 82613. 2552992. MCF NORTH GAS 9 BELUGA 4 10.0 25215. 28.8 163.59 160.77 0. 0. NCF BELUGA GAS 446.71 443.89 11193. 345891. CF NORTH GAS 10 BELUGA 5 61.3 115779. 21.6 7.65 4.83 0. Oo. MCF BELUGA GAS 446.71 443.89 51394. 1588222. MCF NORTH GAS 6 ADDTNL PUR 53.2 77260. 16.6 645.00 recat: nse NN RRR 13 BERNICE 1 8.3 7155. 9.8 228.61 226.80 0. 0. MCF ENSTAR GAS 645.14 643.32 4403. 142239. CF NORTH GAS 14 BERNICE 2 19.6 14751. 8.46 228.61 226.80 0. 0. MCF ENSTAR GAS 645.14 $43.32 9490. 293261. MCF NORTH GAS 15 BERNIC 324 56.0 28660. 5.8 228.61 226.80 0. 0. CF ENSTAR GAS 645.14 $43.32 18438. 569784. NCF NORTH GAS 18 KNIK ARN 10.0 3889. 4.4 291.29 274. 43 0. 0. MCF ENSTAR GAS 7935.29 778. 42 3027. 93546. MCF NORTH GAS 17 INTN 1,283 48.2 13320. 3.2 389.87 386.469 0. 0. NCF ENSTAR GAS 1100.04 1096.87 14610. NiCr 16 COOPER 122 17.2 38009. 38.5 3.17 1 AK P ADMIN 14.0 91980. 73.0 25.85 leercerenee 2 BRADLEY LA 468.0 178704. 30.0 18.54 eee 25 SUPPL PURCH ---~ 17275. — 645.00 aoe TOTAL ALLOCATION 905.4 3640856. 45.9 1117271. TOTAL REQUIRED CAPACITY 905.4 SYSTEM REQUIREMENTS 798.0 3647000. SYSTEM LOAD FACTOR, % 32.2 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 51 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT..D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 omer 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL. PLUS FUEL FUEL UNIT POWER Cap ENERGY FACTOR VAR O+M ONLY COST NUMBER SOURCE cr) (TWH) (PCT) = (MILLS/KWH) = (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 2004 FUEL TOTALS 1117271. 34527166. MCF NORTH GAS BURNS & MCDONNELL ENGINEERING COMPANY CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 UNIT POWER NUMBER SOURCE YEAR ENDING DEC 31, 2005 5 INTERTIE 2i 200MW CC 11 BELUGA 688 12 BELUGA 728 20 BERNICE 5 19 BELUGA 9 7 BELUGA 182 BELUGA 3 9 BELUGA 4 10 BELUGA 5 13 BERNICE 1 14 BERNICE 2 15 BERNIC 384 6 ADDTNL PUR 18 KNIK ARM 17 INTN 1,283 16 COOPER 182 1 AK P ADMIN 2 BRADLEY LA 25 SUPPL PURCH TOTAL ALLOCATION TOTAL REQUIRED CAPACITY SYSTEM REQUIREMENTS SYSTEM LOAD FACTOR, % Cap (mW) 100.0 97.4 98.0 37.0 64.0 36.0 56.2 10.0 61.3 8.3 19.6 56.0 84.3 10.0 48.2 17.2 14.0 68.0 936.4 936.4 825.0 52.3 POWER SUPPLY PROGRAN ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY (WH) 753340. 708412. 687918. 219323. 340386. 164202. 213363. 31691. 135575. 14589. 30831. 64621. 63237. 3427. 11757. 38009. 91980. 178704. 14876. 3786262. 3780000. CAPACITY FUEL PLUS FACTOR (PCT) 0.0 83:0 80.1 67.7 60.7 52.1 43.3 34.2 25.2 20.1 18.0 13.2 8.6 3.9 2.8 38.5 75.0 30.0 46.2 TABLE 4 ENERGY PRICE FUEL VAR O+f ONLY (MILLS/KWH) = (MILLS/KWH) 0.00 304.74 298.76 6.50 3.46 346.20 343.16 6.50 3.46 346.20 343.16 151.72 149.76 418.83 416.87 154.00 150.96 419.92 416.87 176.465 173.60 482. 45 479.40 7.87 4.83 482.45 479.40 176.65 173.40 482.45 479.40 7.87 4.83 482. 45 479.40 251.56 249.60 696.75 694.79 251.56 249.60 696.75 $94.79 251.56 249.60 696.75 694.79 697.00 320.23 302.02 856.91 840.70 428.99 425.57 1188.04 1184.62 3.43 25.85 20.02 697.00 FUEL cosT ($1000) 225074. PAGE: 52 DATE: 21-May-63 TIME: 09:24 FILES: CHNGT.D1 GASGT.D2 VERSION: PS6-9/82 AMOUNT OF FUEL 6440255. MCF NORTH GAS 0. MCF BELUGA GAS 6955959. MCF NORTH GAS 0. MCF BELUGA GAS 6754722. MCF NORTH GAS 0. MCF ENSTAR GAS 2616179. MCF NORTH GAS Oo. MCF BELUGA GAS 4060272. MCF NORTH GAS 0. MCF BELUGA GAS 2252479. MCF NORTH GAS 0. MCF BELUGA GAS 2926855. MCF NORTH GAS 0. MCE BELUGA GAS 434729. MCF NORTH GAS 0. MCF BELUGA GAS 1859783. MCF NORTH GAS 0. MCF ENSTAR GAS 290043. MCF NORTH GAS 0. MCF ENSTAR GAS 412947. MCF NORTH GAS 0. MCF ENSTAR GAS 1284714. MCF NORTH GAS 0. MCF ENSTAR GAS 82427. MCF NORTH GAS 0. MCF ENSTAR GAS 398528. MCF NORTH GAS HYDRO 7 BURNS & MCDONNELL ENGINEERING COMPANY we: 53 POWER SUPPLY PROGRAM : 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 wees 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER Cap ENERGY FACTOR VAR O+f ONLY COST NUMBER SOURCE (ru) (WH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 2005 FUEL TOTALS CF 12972021. 36969892. NORTH GAS BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 54 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSHISSION COOP. PLAN: GAS (8%, 20 TABLE 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL, UNIT POWER Cap ENERGY FACTOR VAR O+M ONLY COST NUMBER SOURCE (iW) (TWH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 2006 5 INTERTIE 31.0 0. 0.0 0.00 ee ee ee 21 200MW CC 100.0 753360. 84.0 329.12 322.66 243079. 6440255. NCF NORTH GAS 11 BELUGA 688 97.4 708601. 83.0 6.84 3.56 0. 0. NCF BELUGA GAS 373.90 370.61 262614. 6957814. NCE NORTH GAS 12 BELUGA 788 8 98.0 695075. 81.0 6.84 3.56 0. 0. MCF BELUGA GAS 373.90 370.61 257601. 6825002. HCF NORTH GAS 20 BERNICE 5 37.0 234353. 72.3 166.75 164.64 0. 0. MCF ENSTAR GAS 452.34 450.22 105511. 2795464. MCF NORTH GAS 19 BELUGA 9 64.0 354365. 63.2 166.37 163.08 0. 0. MCF BELUGA GAS 453.51 450.22 159544. 4227022. 3 =NCF NORTH GAS BELUGA 182 36.0 176095. 55.8 190.83 187.54 0. 0. NCF BELUGA GAS 521.05 317.76 91175. = 2415622. CF NORTH GAS BELUGA 3 56.2 236055. 47.9 8.26 4.97 0. 0. MCF BELUGA GAS 521.05 517.76 122219. 3238129. MCF NORTH GAS BELUGA 4 10.0 37034. 42.3 190.83 187.54 0. 0. MCF BELUGA GAS 521.05 517.76 19175. 508024. MCF NORTH GAS 10 BELUGA 5 61.3 167536. 31.2 8.26 4.97 0. 0. MCF BELUGA GAS 521.05 517.76 86743. 2298213. MCF NORTH GAS 6 ADDTNL PUR 117.6 196520. 19.1 732.00 A —— EAN 13 BERNICE 1 8.3 5846. 8.0 276.51 274. 40 0. 0. MCF ENSTAR GAS 752.49 750.37 4387. 116228. NCF NORTH GAS 14 BERNICE 2 19.6 11993. 7.0 276.51 274. 40 0. 0. NCE ENSTAR GAS 7352.49 750.37 8999. 238432. MCF NORTH GAS 15 BERNIC 384 56.0 23891. 4.9 276.51 274.40 0. 0. NCF ENSTAR GAS 732.49 750.37 17927. 474970. MCF NORTH GAS 18 KNIK ARM 10.0 3244. 3.7 351.69 332.02 0. 0. MCF ENSTAR GAS 927.62 907.95 2945. 78033. MCF NORTH GAS 17 INTN 1,283 48.2 11199. 2.7 471.55 467.85 0. 0. NCF ENSTAR GAS 1283.09 1279.39 14328. 379620. MCF NORTH GAS 16 COOPER 122 17.2 58009. 38.5 3.70 HYDRO 1 AK P ADMIN § 14.0 91980. 75.0 25.85 Tener —— setae ORR 2 BRADLEY LA 48.0 178704. 30.0 21.62 i —— ac eas 25 SUPPL PURCH ---- 14676. een 732.00 aS: meme TOTAL ALLOCATION 969.8 3958537. 46.6 1396249. TOTAL REQUIRED CAPACITY 969.8 SYSTEM REQUIREMENTS 854.0 3920000. SYSTEM LOAD FACTOR, % 52.4 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 55 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 ao a VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL, UNIT POWER CAP ENERGY FACTOR VAR O+M ONLY COST NUMBER SOURCE «r) (UH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 2006 FUEL TOTALS 1396249. 36992829. MCF NORTH GAS BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 56 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 VERSION: PS6-9/82 TABLE 4 ENERGY ALLOCATIONS AND FUEL REQUIRENENTS ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL, UNIT POWER CAP ENERGY FACTOR VAR O+M ONLY cost NUMBER SOURCE (rd) (WH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 2007 = INTERTIE 31.0 0. 0.0 0.00 SS 21 200M CC 100.0 753360. 86.0 355.45 348. 47 262526. 6440255. MCF NORTH GAS 11 BELUGA 688 97.4 708603. 83.1 7.11 3.56 0. 0. MCF BELUGA GAS 403.81 400.26 283624. 6957829. MCF NORTH GAS 12 BELUGA 788 978.0 696775. 81.2 7.11 3.56 0. 0. MCF BELUGA GAS 403.81 400.26 278890. 6841698. MCF NORTH GAS 20 BERNICE 5 37.0 240457. 74.2 183. 48 181.20 0. 0. MCF ENSTAR GAS 488.52 486.24 116920. 2868279. NCF NORTH GAS 19 BELUGA 9 64.0 360215. 64.3 179.71 176.16 0. 0. MCF BELUGA GAS 489.79 486.24 175151. 4296796. CF NORTH GAS BELUGA 122 346.0 180872. 57.4 206.14 202.58 0. 0. MCF BELUGA GAS 562.73 559.18 101139. 2481141. NCF NORTH GAS BELUGA 3 36.2 242955. 49.3 8.52 4.97 0. 0. MCF BELUGA GAS 362.73 359.18 135855. 3332788. MCF NORTH GAS BELUGA 4 10.0 39294. 4.9 206.14 202.58 0. 0. NCF BELUGA GAS 562.73 559.18 21973. 539029. MCF NORTH GAS 10 BELUGA 5 61.3 185116. 34.5 8.52 4.97 0. 0. NCE BELUGA GAS 362.73 357.18 103513. 25397359. MCF NORTH GAS 13 BERNICE 1 8.3 19647. 27.0 304. 28 302.00 0. 0. MCF ENSTAR GAS 812.469 810.40 15922. 390605. MCF NORTH GAS 14 BERNICE 2 19.6 424978. 24.8 304. 28 302.00 0. Oo. MCF ENSTAR GAS 812.69 810.40 34440. 844881. NCF NORTH GAS 15 BERNIC 324 54.0 89612. 18.3 304. 28 302.00 0. 0. MCF ENSTAR GAS 812.69 810.40 72622. 1781544. MCF NORTH GAS 6 ADDTNL PUR 151.0 128105. 9.7 ° 813.00 i eee ie esas 18 KNIK ARM 10.0 2592. 3.0 386.446 365.42 0. 0. MCF ENSTAR GAS 1001.83 980.59 2542. 62355. MCF NORTH GAS 17 INTN 1,283 48.2 8905. 21 318.90 314.91 0. 0. NCE ENSTAR GAS 1385.73 1381.74 12305. 301866. MCF NORTH GAS 16 COOPER 122 17.2 58009. 38.5 3.99 HYDRO 1 AK P ADMIN 14.0 91980. 75.0 28.42 ELLAND aad 2 BRADLEY LA 48.0 178704. 30.0 23.35 ssanmenek;—_seneeenieeieneieesmmrmnneneinermnemnntettene 23 SUPPL PURCH -~-~ 11459. aaa 813.00 TSA TOTAL ALLOCATION 1003.2 4039158. 44.0 1617422. TOTAL REQUIRED CAPACITY 1003.2 SYSTEM REQUIREMENTS 883.0 4061000. SYSTEM LOAD FACTOR, % 52.5 m ’ i ' i a - . “ % (al ae ord —a — aa eee atom ™ . . aang om BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 57 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 UE 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER CAP ENERGY FACTOR VAR Ot ONLY COST NUMBER SOURCE cr) (AH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 2007 FUEL TOTALS NCF 1617422. 39678425. NORTH GAS BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 58 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT. D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 TABLE 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REGUIRENENTS ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER CAP ENERGY FACTOR VAR ON ONLY COST NUMBER SOURCE (rw) (TWH) (PCT) = (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR a DEC 31, 2008 INTERTIE 51.0 0. 0.0 0.00 a aT Ree — a 200MW CC 100.0 753360. 84.0 383.88 376.35 283528. 6440255. NCF NORTH GAS 22 200M CC 200.0 1489975. 85.0 383.88 376.35 560754. 12737360. MCF NORTH GAS ll BELUGA 688 97.4 567773. 66.5 7.49 3.45 0. 0. MCF BELUGA GAS 436.11 432.28 245436. 5575007. NCF NORTH GAS 12 BELUGA 7288 8698.0 452555. 532.7 7.49 3.465 0. 0. MCF BELUGA GAS 436.11 432.28 195630. 4443677. MCF NORTH GAS 20 BERNICE 5 37.0 142362. 44.0 201.79 199.32 0. 0. MCF ENSTAR GAS 527.61 325.14 74865. 1700541. NCF NORTH GAS 19 BELUGA 9 64.0 162724. 29.0 194.04 190.20 0. 0. NCF BELUGA GAS 528.98 525.14 85453. reais MCF NORTH GAS 7 BELUGA 1282 36.0 70707. 22.4 222.57 218.73 0. NCE BELUGA GAS 607.75 603.91 42701. 969949. NCE NORTH GAS BELUGA 3 36.2 81827. 16.6 8.94 5.11 0. NCF BELUGA GAS 607.75 603.91 49416. 1122404. NCF NORTH GAS 9 BELUGA 4 10.0 12477. 14.2 222.57 218.73 0. 0. NCF BELUGA GAS 607.75 603.91 7535. 171155. NCE NORTH GAS 10 BELUGA 5 61.3 58061. 10.8 8.94 5.11 0. 0. MCF BELUGA GAS 607.75 603.91 35064. —_ NCF NORTH GAS 13 BERNICE 1 8.3 6423. 8.8 334.67 332.20 0. NCE ENSTAR GAS 877.70 875.24 3622. 127691: NCF NORTH GAS 14 BERNICE 2 19.6 13575. 79 334. 67 332.20 0. 0. NCF ENSTAR GAS 877.70 875.24 11881. 269883. NCF NORTH GAS 15 BERNIC 3284 56.0 28036. 5.7 334. 67 332.20 0. 0. MCF ENSTAR GAS 877.70 875.24 24539. 557385. MCF NORTH GAS 18 KNIK ARM 10.0 4006. 4.6 424.90 401.96 0. 0. NCE ENSTAR GAS 1081.98 1059.03 4243. 96378. MCF NORTH GAS 17 INTN 1,283 48.2 14604. 3.5 570.72 566.40 0. 0. NCE ENSTAR GAS 1496.59 1492.28 21793. 495033. MCF NORTH GAS 16 COOPER 182 17.2 58009. 38.5 4.31 HYDRO 1 AK P ADMIN 14.0 91980. 75.0 28.42 necanes ae 2 BRADLEY LA 468.0 178704. 30.0 25.22 a SUPPL PURCH --— 24933. seaman 878.00 TOTAL ALLOCATION 1052.2 4212291. 45.7 TOTAL REQUIRED CAPACITY 1037.6 SYSTEM REQUIREMENTS 913.0 4207000. SYSTEM LOAD FACTOR, % 32.6 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 59 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 a VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL. FUEL UNIT POWER CAP ENERGY FACTOR VAR O+N ONLY cost NUMBER SOURCE (rd) WH) (PCT) = (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 2008 FUEL TOTALS 1648459. 37444287. MCF NORTH GAS BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 60 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 TAMLE 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER cap ENERGY FACTOR VAR O+M ONLY COST NUMBER SOURCE (rid) (TWH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 2009 5 INTERTIE 31.0 0. 0.0 0.00 Ss | 2i 200hW CC 100.0 7353360. 84.0 414.40 406.46 306210. 6440255. NCF NORTH GAS 22 200M CC 200.0 14974700. 85.3 414. 60 406.46 607535. 12777754. MCF NORTH GAS 11 BELUGA 688 97.4 596973. 70.0 7.80 3.465 0. 0. MCF BELUGA GAS 471.00 466.86 278703. 5861729. MCF NORTH GAS 12 BELUGA 788 98.0 472866. 35.1 7.80 3.65 0. 0. NCF BELUGA GAS 471.00 466.86 220763. 4643113. NCF NORTH GAS 20 BERNICE 5 37.0 153844. 47.5 221.90 219.24 0. Oo. MF. ENSTAR GAS 569.82 367.15 87253. 1835112. MCF NORTH GAS 19 BELUGA 9 64.0 193844. 34.6 209.58 205.44 0. 0. MCF BELUGA GAS 571.29 367.15 109940. 2312273. MCF NORTH GAS BELUGA 182 = 34.0 80932. 25.7 240.40 236.26 0. 0. NCE BELUGA GAS 654.37 652.23 52786. 1110195. MCF NORTH GAS BELUGA 3 36.2 92449. 18.8 9.25 5.11 0. 0. NCF BELUGA GAS 656.37 $52.23 60298. 1268186. NCF NORTH GAS BELUGA 4 10.0 13933. 15.9 240.40 236.26 0. 0. MCF BELUGA GAS 654.37 652.23 9087. 191122. MCF NORTH GAS 10 BELUGA 5 61.3 646734. 12.4 9.25 5.11 0. 0. MCF BELUGA GAS 656.37 $52.23 43525. 915431. MCF NORTH GAS 13 BERNICE 1 8.3 7436. 10.2 348.06 365.40 0. Oo. MCF ENSTAR GAS 947.92 943.25 7029. 147831. NCF NORTH GAS 14 BERNICE 2 19.6 15893. 9.3 368.06 365.40 0. 0. MCF ENSTAR GAS 947.92 945.25 15023. 315968. MCF NORTH GAS 15 BERNIC 324 56.0 33650. 6.9 3468.06 365.40 0. 0. MCF ENSTAR GAS 947.92 945.25 31808. 668992. MCF NORTH GAS é ADDTNL PUR 22.3 12049. 6.2 948.00 ie eS a ere ee REUSE LSRLEERISES EAL a 18 KNIK ARM 10.0 3836. 4.4 466.91 442.13 0. 0. MCF ENSTAR GAS 1148.54 1143.76 4387. 92268. MCF NORTH GAS 17 INTN 1,283 48.2 13918. 3.3 627.67 $23.01 0. 0. MCF ENSTAR GAS 1616.32 1611.46 22431. 471771. CF NORTH GAS 16 COOPER 182 17.2 58009. 38.5 4.66 HYDRO 1 AK P ADMIN § 14.0 91980. 75.0 28.42 ore || reece ee erry 2 BRADLEY LA 48.0 178704. 30.0 27.24 SS a 25 SUPPL PURCH ---- 23821. _—— 948.00 rey || eee een Ree ca To tretee TOTAL ALLOCATION 1074.4 4358930. %.3 1856777. TOTAL REQUIRED CAPACITY 1074.4 SYSTEM REQUIREMENTS 945.0 4363000. SYSTEM LOAD FACTOR, % 32.7 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 61 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC.. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 ums 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL, UNIT POWER CAP ENERGY FACTOR VAR O+M ONLY cost NUMBER SOURCE (rd) (TWH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 2009 FUEL TOTALS 1856777. 39051999. MCF NORTH GAS BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 62 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 TABLE 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL. UNIT POWER CAP ENERGY FACTOR VAR O+M ONLY Cost NUMBER SOURCE (rm) (WH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 2010 5 INTERTIE 51.0 0. 0.0 0.00 manasa || | lapenininnsnanierestunnnsstesineareniereennhtinarseoniinn 21 200MW CC 100.0 733360. 84.0 447.76 438.98 330707. 6440255. NCF NORTH GAS 22 200MW CC 200.0 1498270. 85.5 447.76 438.98 657705. 12808275. NCF NORTH GAS 11 BELUGA 688 97.4 624475. 73.2 8.23 3.75 0. 0. NCE BELUGA GAS 508. 68 504.21 314867. 6131778. NCF NORTH GAS 12Z BELUGA 7288 8 98.0 496302. 57.8 8.23 3.75 0. 0. MCF BELUGA GAS 508. 68 504.21 250240. 4873232. NCF NORTH GAS 20 BERNICE 5 37.0 162730. 50.2 243.96 241.08 0. 0. MCF ENSTAR GAS 615. 40 612.52 99676. 1941117. MCF NORTH GAS 19 BELUGA 9 64.0 232364. 41.4 226.35 221.88 0. 0. NCF BELUGA GAS 617.00 612.52 142328. 2771732. MCF NORTH GAS 7 BELUGA 182 36.0 92951. 29.5 259.64 255.16 0. 0. MCF BELUGA GAS 708. 88 704. 40 65475. 1275067. CF NORTH GAS BELUGA 3 36.2 112134. 22.8 9.72 5.24 0. 0. MCF BELUGA GAS 708. 88 704. 40 78988. 1538225. NCF NORTH GAS 9 BELUGA 4 10.0 16878. 19.3 259.64 255.16 0. 0. NCF BELUGA GAS 708. 88 704. 40 11889. 231533. MCF NORTH GAS 10 BELUGA 5 61.3 81834. 15.2 9.72 5.24 0. 0. NCF BELUGA GAS 708. 88 704. 40 57644. 1122578. MCF NORTH GAS 13 BERNICE 1 8.3 9198. 12.7 404. 68 401.80 0. 0. MCF ENSTAR GAS 1023.75 1020.87 9390. 182855. MCF NORTH GAS 14 BERNICE 2 19.4 19756. 11.5 404. 68 401.80 0. 0. MCF ENSTAR GAS 1023.75 1020.87 20169. 392768. MCF NORTH GAS 15 BERNIC 384 56.0 43207. 8.8 404. 68 401.80 0. 0. MCF ENSTAR GAS 1023.75 1020.87 44109. 859978. NCF NORTH GAS 6 ADDTNL PUR = 59.1 36226. 7.0 1024.00 seneeen | | Aaiehaeebnerenesnienneneceetonnneminensiecenatnits 18 KNIK ARM 10.0 3616. 4.1 312.94 486.18 0. 0. MCF ENSTAR GAS 1262.02 1235.26 4467. 86982. NCF NORTH GAS 17 INTN 1,283 48.2 13147. 3.1 690.10 685.07 0. 0. MCF ENSTAR GAS 1745.62 1740.59 22883. HCF 16 COOPER 182 17.2 38009. 38.5 5.03 1 AK P ADMIN § 14.0 91980. 73.0 Gee hh heeV<7V37 2 BRADLEY LA 648.0 178704. 30.0 29.42 a 23 SUPPL PURCH --—— 22480. -_— 1024.00 sae TOTAL ALLOCATION 1111.3 4547622. 4.7 2110536. TOTAL REQUIRED CAPACITY 1111.3 SYSTEM REQUIREMENTS 977.0 4519000. SYSTEM LOAD FACTOR, % 52.8 BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 TABLE 4 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER CAP ENERGY FACTOR VAR O+ ONLY COST NUMBER SOURCE «rw (WH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) YEAR ENDING DEC 31, 2010 2110536. DATE: 2i-tay-aa TIME: 09:24 FILES: CHHGT.D1 GASGT.D2 VERSION: PS6-9/82 AMOUNT OF FUEL FUEL TOTALS NCF 41101006. NORTH GAS BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 64 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TINE: 09:24 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 TALE 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER CAP ENERGY FACTOR VAR O+N ONLY COST NUMBER SOURCE (mW) (TWH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 2011 5 INTERTIE 51.0 0. 0.90 0.00 Aaa eT 2i 200 CC 100.0 733360. 86.0 483.58 474.09 357163. 6440255. MCF NORTH GAS 22 200M CC 200.0 14978985. 85.6 483.58 474.09 710660. 12814386. MCF NORTH GAS il BELUGA 688 97.4 635168. 74.4 8.58 3.75 0. 0. MCF BELUGA GAS 549.38 344.55 345878. 6236768. MCF NORTH GAS 12 BELUGA 788 98.0 305115. 58.8 8.58 3.75 0. 0. MCF BELUGA GAS 349.38 344.55 275059. 4959770. MCF NORTH GAS 20 BERNICE 5 37.0 166046. 51.2 268.31 265.20 0. 0. MCF ENSTAR GAS 664.63 $61.53 107844. 1980472. MCF NORTH GAS 19 BELUGA 9 64.0 247075. 44.1 244. 47 239.64 0. 0. NCF BELUGA GAS 666.36 661.53 163447. 92947220. MCF NORTH GAS 7 BELUGA 182 36.0 102416. 32.5 280. 42 275.59 0. 0. MCF BELUGA GAS 765.59 760.76 77913. 1404908. CF NORTH GAS BELUGA 3 34.2 121584. 24.7 10.08 3.24 0. 0. MCF BELUGA GAS 765.59 760.76 92498. 1667886. MCF NORTH GAS 9 BELUGA 4 10.0 18283. 20.9 280. 42 275.59 0. 0. MCF BELUGA GAS 765.59 760.76 13909. 250796. MCF NORTH GAS 10 BELUGA 5 61.3 89534. 16.7 10.08 3.24 0. Oo. MCF BELUGA GAS 765.59 760.76 68113. 1228197. MCF NORTH GAS 6 ADDTNL PUR 97.0 104742. 12.3 1105.00 = a 13 BERNICE 1 8.3 4727. 6.5 445.11 442.00 0. 0. MCE ENSTAR GAS 1105.65 1102.54 3212. 93979. CF NORTH GAS 14 BERNICE 2 19.6 9897. 5.8 445.11 442.00 0. Oo. MCF ENSTAR GAS 1105.45 1102.54 10912. 196755. MCF NORTH GAS 15 BERNIC 384 56.0 20479. 4.2 445.11 442.00 0. 0. MCF ENSTAR GAS 1105.65 1102.54 22579. 407135. MCF NORTH GAS 18 KNIK ARN 10.0 2908. 3.3 563.72 534.82 0. 0. MCF ENSTAR GAS 1342.98 1334.08 3879. 69953. MCF NORTH GAS 17 INTN 1,283 48.2 10568. 2.5 759.05 733.61 0. 0. MCF ENSTAR GAS 1885.27 1879.84 19846. 3562146. MCF NORTH GAS 16 COOPER 182 17.2 58009. 38.5 5.44 1 AK P ADMIN 14.0 91980. 75.0 31.27 vamos 2 BRADLEY LA 48.0 178704. 30.0 31.77 eee a SUPPL PURCH ---- 17891. saa 1105.00 seats TOTAL ALLOCATION 1149.2 4637473. 46.1 2276932. TOTAL REQUIRED CAPACITY 1149.2 SYSTEM REQUIREMENTS 1010.0 4680000. SYSTEM LOAD FACTOR, % 52.9 E f ‘ - Brean Bears enicemenad SS eee oer moro — a) core al en are - is . we wre BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 65 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHMNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSHISSION COOP. PLAN: GAS (8%, 20 TALE 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER Cap ENERGY FACTOR VAR O+M ONLY COST NUMBER SOURCE (rd) (TWH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 2011 FUEL TOTALS 2276932. 41056895. NCF NORTH GAS BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 44 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT. D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 TABLE 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER Cap ENERGY FACTOR VAR O+M ONLY COsT NUMBER SOURCE (rad) (rH) (PCT) §=(MILLS/KWH) §=(MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 2012 5 INTERTIE 51.0 0. 0.0 0.00 ree mamma aes 21 200MW CC 100.0 733360. 86.0 522.27 512.02 385737. 6440255. NCF NORTH GAS 22 200MW CC 200.0 1501655. 85.7 522.27 512.02 768880. 12837210. MCF NORTH GAS 11 BELUGA 688 97.4 660006. 77.4 9.07 3.85 0. 0. MCF BELUGA GAS 593.33 588.11 388156. 6480651. MCF NORTH GAS 12 BELUGA 7288 98.0 526932. 61.4 9.07 3.85 0. 0. MCF BELUGA GAS 393.33 388.11 309894. 5173987. MCF NORTH GAS 20 BERNICE 5 37.0 173888. 53.6 295.07 291.72 0. 0. CF ENSTAR GAS 717.80 714. 45 124234. 2074212. MCF NORTH GAS 19 BELUGA 9 64.0 269896. 48.1 264.06 258.84 0. 0. MCF BELUGA GAS 719.67 714. 45 192827. 3219440. NCF NORTH GAS BELUGA 182 36.0 125217. 39.7 302.88 297.67 0. 0. CF BELUGA GAS 826.83 821.62 102880. 1717690. NCF NORTH GAS BELUGA 3 36.2 146080. 29.7 10.60 5.38 0. 0. MCF BELUGA GAS 8246.83 821.62 120022. 2003687. MCF NORTH GAS BELUGA 4 10.0 22112. 3.2 302.88 297.67 0. 0. MCF BELUGA GAS 824.83 821.62 18167. 303323. MCF NORTH GAS 10 BELUGA 5 61.3 107722. 20.1 10.60 5.38 0. 0. MCF BELUGA GAS 826.83 821.42 88506. 1477691. NCF NORTH GAS 4 ADDTNL PUR 137.3 161059. 13.4 1194.00 SSRI eter mntnenresennerneenmeeniainseietian 13 BERNICE 1 8.3 4321. 5.9 489.55 486.20 0. 0. MCF ENSTAR GAS 1194.10 1190.75 5146. 85912. CF NORTH GAS 14 BERNICE 2 19.6 9101. 5.3 489.55 486.20 0. 0. MCF ENSTAR GAS 1194.10 1190.75 10837. 180929. NCF NORTH GAS 15 BERNIC 384 54.0 18969. 3.9 489.55 486.20 0. oO. MCF ENSTAR GAS 1194.10 1190.75 22588. 377122. NCE NORTH GAS 18 KNIK ARM 10.0 2717. 3.1 619.51 588.30 0. 0. MCF ENSTAR GAS 1472.02 1440.80 3914. 65349. NCF NORTH GAS 17 INTN 1,283 48.2 9904. 2.3 834.84 828.97 NCF 2036.09 2030. 22 HCF 16 COOPER 122 17.2 58009. 38.5 5.87 1 AK P ADMIN 14.0 91980. 75.0 31.27 2 BRADLEY LA 68.0 178704. 30.0 34.31 2 SUPPL PURCH --—- 17261. — 1194.00 TOTAL ALLOCATION 1189.4 48388972. 46.4 TOTAL REQUIRED CAPACITY 1189.4 SYSTEM REQUIREMENTS 1045.0 4852000. SYSTEM LOAD FACTOR, % 53.0 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 67 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 TLE 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER CAP ENERGY FACTOR VAR O+N ONLY COST NUMBER SOURCE «rd (WH) (PCT) = <(MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 2012 FUEL TOTALS 2561894. 42773362. CF NORTH GAS BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 68 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.02 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 cae a VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER CAP ENERGY FACTOR VAR OH ONLY cost NUMBER SOURCE (ri) (WH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 2013 5 INTERTIE 51.0 0. 0.0 0.00 aaa a Aaalnn inte 21 200MW CC 100.0 753360. 86.0 564.05 352.98 416595. 6440255. NCF NORTH GAS 22 200MW CC 200.0 1503656. 85.8 364.05 552.98 831497. 12854317. MCF NORTH GAS 23 200MW CC 200.0 1268231. 72.4 564.05 352.98 701310. 10841732. MCF NORTH GAS 11 BELUGA 688 97.4 444555. 52.1 9.49 3.85 0. 0. NCF BELUGA GAS 640.79 635.16 2823463. 4365127. MCF NORTH GAS 12 BELUGA 788 98.0 302486. 35.2 9.49 3.85 0. 0. MCF BELUGA GAS 640.79 635.16 192126. 2970132. MCF NORTH GAS 20 BERNICE 5 37.0 83012. 25.6 324.50 320.88 0. 0. MCF ENSTAR GAS 775.23 771.60 64052. 990197. CF NORTH GAS 19 BELUGA 9 64.0 110739. 19.8 285.12 279.48 0. 0. NCF BELUGA GAS 777.24 771.40 85447. 1320944. MCF NORTH GAS BELUGA 182 34.0 50191. 15.9 327.04 321.40 0. 0. MCF BELUGA GAS 892.98 887.35 4534. 688501. CF NORTH GAS BELUGA 3 36.2 59316. 12.0 11.02 5.38 0. 0. MCF BELUGA GAS 892.98 887.35 32634. 813685. MCF NORTH GAS BELUGA 4 10.0 9049. 10.3 327.04 321.40 0. 0. MCF BELUGA GAS 892.98 887.35 8030. 124132. MCF NORTH GAS 10 BELUGA 5 61.3 43492. 8.1 11.02 3.38 0. 0. MCF BELUGA GAS 892.98 887.35 38592. 396607. MCF NORTH GAS 13 BERNICE 1 8.3 4873. 6.7 538.42 334.80 0. 0. MCF ENSTAR GAS 1289.63 1286.01 6267. 96882. NCF NORTH GAS 14 BERNICE 2 19.6 10417. 6.1 538. 42 534.80 0. 0. MCF ENSTAR GAS 1289.63 1286.01 13396. 207096. =HNCF NORTH GAS 15 BERNIC 324 56.0 22383. 4.6 538.42 334.80 0. 0. MCF ENSTAR GAS 1289.63 1286.01 28784, 444982. MCF NORTH GAS 18 KNIK ARM 10.0 3297. 3.8 680. 82 647.11 0. 0. MCF ENSTAR GAS 1589.78 1556.07 3131. 797316. MCF NORTH GAS 17 INTN 1,283 48.2 12546. 3.0 918.17 911.83 0. 0. MCF ENSTAR GAS 2198.98 2192.64 27509. 425270. WCF NORTH GAS 16 COOPER 182 17.2 58009. 38.5 6.34 1 AK P ADMIN § 14.0 91980. 73.0 34.39 — 2 BRADLEY LA 68.0 178704. 30.0 37.05 ene 23 SUPPL PURCH ---— 26014. en 1289.00 eure TOTAL ALLOCATION 1252.2 5036311. 5.9 2798271. TOTAL REQUIRED CAPACITY 1230.9 SYSTEM REQUIREMENTS 1081.0 5028000. SYSTEM LOAD FACTOR, % 53.1 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 69 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOFER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 TAME 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER CAP ENERGY FACTOR VAR O+" ONLY COST NUMBER SOURCE (ra) (PWJH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 2013 FUEL TOTALS 2798271. 43259174. MCF NORTH GAS BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 70 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT. D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 Tae VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER Cap ENERGY FACTOR VAR ON ONLY COST NUMBER SOURCE <r) (TWH) (PCT) = (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 2014 5 INTERTIE 51.0 0. 0.0 0.00 Se 21 200MW CC 100.0 753360. 86.0 609.18 397.22 449923. 6440255. NCF NORTH GAS 22 200MW CC 200.0 1505116. 85.9 609.18 397.22 8978888. 12866794. CF NORTH GAS 23 200MW CC 200.0 1311173. 74.8 609.18 597.22 783061. 11208832. MCF NORTH GAS 11 BELUGA 688 97.4 465264. 54.5 10.04 3.95 0. Oo NCF BELUGA GAS 692.06 685.97 319158. 4568471. MCF NORTH GAS 12 BELUGA 788 98.0 348288. 4.6 10.04 3.95 0. 0. MCF BELUGA GAS 692.06 685.97 238916. 3419872. MCF NORTH GAS 20 BERNICE 5 37.0 92756. 28.6 356.95 353.04 0. 0. MCF ENSTAR GAS 837.25 833.33 77297. 1106436. CF NORTH GAS 19 BELUGA 9 64.0 125289. 22.3 308.01 301.92 0. 0. NCF BELUGA GAS 839. 42 833.33 104407. 1494498. CF NORTH GAS BELUGA 182 36.0 57471. 18.2 353.29 347.21 0. 0. NCF BELUGA GAS 964. 42 958.33 35076. 788364. HCF NORTH GAS BELUGA 3 56.2 68885. 14.0 11.61 5.52 0. 0. MCF BELUGA GAS 964. 42 958.33 66014. 944938. MCF NORTH GAS 9 BELUGA 4 10.0 10442. 11.9 353.29 347.21 0. 0. MCF BELUGA GAS 964. 42 958.33 10007. 143235. NCF NORTH GAS 10 BELUGA 5 61.3 50693. 9.4 11.61 5.52 0. 0. MCF BELUGA GAS 964. 42 958.33 48581. 695394. MCF NORTH GAS 13 BERNICE 1 8.3 5717. 7.9 592.31 388. 40 0. 0. MCF ENSTAR GAS 1392.80 1388.69 79%. 113655. MCF NORTH GAS 14 BERNICE 2 19.6 12334. 7.2 592.31 588. 40 0. 0. MCF ENSTAR GAS 1392.80 1388.89 17131. 245216. MCF NORTH GAS 15 BERNIC 384 56.0 26957. 5.5 592.31 588. 40 0. 0. MCF ENSTAR GAS 1392.80 1388.89 37441. 535734. MCF NORTH GAS 6 ADDTNL PUR 21.2 9591. 5.2 1393.00 Se eee ereeenenenenmmmnanenaemenenen 18 KNIK ARM 10.0 3271. 3.7 748.37 711.96 0. 0. MCF ENSTAR GAS 1716.96 1680.55 3497. 78684. MCF NORTH GAS 17 INTN 1,283 48.2 12457. 3.0 1010.07 1003. 22 0. 0. NCF ENSTAR GAS 2374.90 .2368. 05 29500. 422263. MCF NORTH GAS 16 COOPER 182 17.2 358009. 38.5 6.85 HYDRO 1 AK P ADMIN 14.0 91980. 75.0 34.39 rrr nnn nnnneca 2 BRADLEY LA 48.0 178704. 30.0 40.02 rrr renee nnnnnee 2 SUPPL PURCH ---~ 26122. —— 1393.00 eR ne nem rmenneneneneenenenaenemmemenmen TOTAL ALLOCATION 1273.4 5213879. %.7 3148837. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 71 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 TALE 4 VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER CAP ENERGY FACTOR VAR O+f ONLY COST NUMBER SOURCE (rd) (WH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 2014 TOTAL REQUIRED CAPACITY 1273.4 SYSTEM REQUIREMENTS 1118.0 5210000. SYSTEM LOAD FACTOR, x 33.2 FUEL TOTALS 3148837. 45072839. MCF NORTH GAS BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 72 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHMGT.01 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (82, 20 “ae & VERSION: PS6-9/82 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS ENERGY PRICE CAPACITY FUEL PLUS FUEL FUEL UNIT POWER CAP ENERGY FACTOR VAR OM ONLY cost NUMBER SOURCE (It) (TWH) (PCT) (MILLS/KWH) (MILLS/KWH) ($1000) AMOUNT OF FUEL YEAR ENDING DEC 31, 2015 5 INTERTIE 51.0 0. 0.0 0.00 ES __ eRe one 21 200MW CC 100.0 753360. 86.0 657.91 645.00 485917. 6440255. MCF NORTH GAS 22 200MW CC 200.0 1506120. 84.0 657.91 645.00 971447. 12875377. MCF NORTH GAS 23 200MW CC 200.0 1351956. 77.2 657.91 645.00 872011. 11557478. MCF NORTH GAS 11 BELUGA 688 97.4 483361. 36.7 10.52 3.95 0. 0. MCF BELUGA GAS 747.42 740.85 358097. 4746159. NCF NORTH GAS 12 BELUGA 788 8698.0 374863. %.0 10.52 3.95 0. 0. MCF BELUGA GAS 747.42 740.85 292534. 3877194. NCF NORTH GAS 20 BERNICE 5 37.0 106382. 32.8 372.55 388.32 0. 0. MCF ENSTAR GAS 904. 22 900.00 95744. 1268967. CF NORTH GAS 19 BELUGA 9 64.0 145344. 5.9 332.61 326.04 0. oO MCF BELUGA GAS 906.57 900.00 130810. 1733730. MCF NORTH GAS 7 BELUGA 182 346.0 65817. 20.9 381.52 374.95 0. 0. MCF BELUGA GAS 1041.57 1035.00 68121. 902861. MCF NORTH GAS BELUGA 3 34.2 82665. 16.8 12.09 3.52 0. 0. MCF BELUGA GAS 1041.57 1035.00 85558. 1133975. MCF NORTH GAS 9 BELUGA 4 10.0 12503. 14.3 381.52 374.95 0. 0. MCF BELUGA GAS 1041.57 1035.00 129740. 171508. MCF NORTH GAS 10 BELUGA 5 61.3 62030. 11.6 12.09 3.52 0. 0. MCF BELUGA GAS 1041.57 1035.00 64201. 850904. MCF NORTH GAS 6 ADDTNL PUR 64.9 55387. 97 1504.00 ST eterno renner eielat-e rent 13 BERNICE 1 8.3 4427. ~ 6.1 651.43 647.20 0. 0. MCF ENSTAR GAS 1504. 22 1500.00 6640. 88006. = NCF NORTH GAS 14 BERNICE 2 19.6 9468. 5.5 651.43 647.20 0. Oo. MCF ENSTAR GAS 1504.22 1500. 00 14203. 188240. NCF NORTH GAS 15 BERNIC 384 54.0 20503. 4.2 651.43 647.20 0. Oo. MCF ENSTAR GAS 1504.22 1500.00 30755. 407618. = NCF NORTH GAS 18 KNIK ARM 10.0 3005. 3.4 822.43 783.11 0. Oo. MCF ENSTAR GAS 1854.32 1815.00 3455. 72294. MCF NORTH GAS 17 INTN 1,283 48.2 11464, 2.7 1110.87 1103. 48 0. 0. MCF ENSTAR GAS 2564.89 2557.50 29320. 388608. MCF NORTH GAS 16 COOPER 182 17.2 58009. 38.5 7.39 HYDRO 1 AK P ADMIN §=14.0 91980. 73.0 34.39 atl 2 BRADLEY LA 48.0 178704. 30.0 43.22 nds 2 SUPPL PURCH ---- 23703. —— 1504.00 a TOTAL ALLOCATION 1317.1 5421050. 47.0 3523752. = % Ped a c 4 t { BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 TABLE 4 ENERGY ALLOCATIONS AND FUEL REQUIREMENTS (CONTINUED) ENERGY PRICE CAPACITY FUEL PLUS FUEL UNIT POWER Cap ENERGY FACTOR VAR O+M ONLY NUMBER SOURCE cm) (WH) (PCT) =(MILLS/KWH) = (MILLS/KWH) YEAR ENDING DEC 31, 2015 TOTAL REQUIRED CAPACITY 1317.1 SYSTEM REQUIREMENTS 1156.0 5397000. SYSTEM LOAD FACTOR, % 33.3 ($1000) 3523752. 46703173. PAGE: 73 DATE: 21-May-83 TIME: 09:24 FILES: CHNGT.D1 GASGT. D2 VERSION: PS6-9/82 FUEL TOTALS NORTH GAS BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: €82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 YEAR ENDING DEC 31 NEW GENERATORS, IW (NET) COMBUSTION TURBINE HYDRO STEAN PRODUCTION COMBINED CYCLE GENERAL PLANT TOTAL NEW GENERATORS INVESTMENTS, $/(NET) KW COMBUSTION TURBINE HYDRO STEAM PROOUCTION COMBINED CYCLE GENERAL PLANT INVESTNENTS, $1000 COMBUSTION TURBINE HYDRO STEAM PRODUCTION COMBINED CYCLE GENERAL PLANT SUBSTATION/XMISSION TOTAL INVESTMENTS INVESTMENTS AND CASH REQUIREMENTS 1983 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 1984 64. 0. 0. 0. 0. 64. 40. 0. 0. 0. 0. 25574. 0. 0. 0. 3800. 0. 29374, TABLE 6 1985 37. 0. 0. 0. 0. 37. 432. 0. 0. 107675. 1989 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. oO. 0. PAGE: DATE: 21-May-83 TIME: 09:24 FILES: CHNGT.D1 GASGT.D2 VERSION: PS6-9/82 1991 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. t BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 TABLE 6 INVESTMENTS AND CASH REQUIREMENTS YEAR ENDING DEC 31 1992 1993 1994 1995 NEW GENERATORS, MW (NET) COMBUSTION TURBINE 0. 0. 0. 0. HYDRO 0. 0. 0. 0. STEAM PRODUCTION 0. 0. 0. 0. COMBINED CYCLE 0. 0. 0. 0. GENERAL PLANT 0. 0. 0. 0. TOTAL NEW GENERATORS 0. 0. 0. 0. INVESTMENTS, $/(NET) KW COMBUSTION TURBINE 0. 0. 0. 0. HYDRO 0. 0. 0. 0. STEAN PRODUCTION 0. 0. 0. 0. COMBINED CYCLE 0. 0. 1 0. 0. GENERAL PLANT 0. 0. 0. 0. INVESTMENTS, $1000 COMBUSTION TURBINE 0. 0. 0. 0. HYDRO 0. 0. 0. 0. STEAM PRODUCTION 0. 0. 0. 0. COMBINED CYCLE 0. 0. 0. 0. GENERAL PLANT 0. 0. 0. 0. SUBSTATION/XMISSION 0. 0. 0. 21213. TOTAL INVESTMENTS 0. 0. 0. 21213. = PAGE: 75 DATE: 21-May-83 TIME: 09:24 FILES: CHNGT.D1 GASGT..D2 VERSION: PS6-9/82 1998 1999 2000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. o. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 28860. 0. 0. 28860. 0. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 YEAR ENDING DEC 31 NEW GENERATORS, MW (NET) COMBUSTION TURBINE HYDRO STEAM PRODUCTION COMBINED CYCLE GENERAL PLANT TOTAL NEW GENERATORS INVESTMENTS, $/(NET) KW COMBUSTION TURBINE HYDRO STEAM PRODUCTION COMBINED CYCLE GENERAL PLANT INVESTNENTS, $1000 COMBUSTION TURBINE HYDRO STEAM PRODUCTION COMBINED CYCLE GENERAL. PLANT SUBSTATION/XMISSION TOTAL INVESTMENTS TABLE 6 INVESTMENTS AND CASH REQUIREMENTS 2001 2002 2003 2004 2005 2006 2007 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 100. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 100. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 5015. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. Qo. 0. 0. 501500. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 33662. 0. 0. 0. 0. 0. 0. 535163. 0. 0. 0. 0. 0. 0. PAGE: DATE: 21-May-83 TIME: 09:24 FILES: CHNGT.D1 GASGT. D2 VERSION: PS6-9/82 2009 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 77 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT..D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 ene 6 VERSION: PS6-9/82 INVESTMENTS AND CASH REQUIREMENTS YEAR ENDING DEC 31 2010 2011 2012 2013 2014 2015 =TOTALS NEW GENERATORS, MMW (NET) COMBUSTION TURBINE 0. 0. 0. 0. 0. 0. 101. HYDRO 0. 0.. 0. 0. 0. 0. 0. STEAM PRODUCTION 0. 0. 0. 0. 0. 0. 0. COMBINED CYCLE o. 0. 0. 200. 0. 0. 500. GENERAL PLANT 0. 0. 0. 0. 0. 0. 0. TOTAL NEW GENERATORS o. 0. 0. 200. 0. 0. 601. INVESTMENTS, $/(NET) KW COMBUSTION TURBINE 0. 0. 0. 0. 0. 0. HYDRO 0. 0. 0. 0. 0. 0. STEAN PRODUCTION 0. 0. 0. 0. 0. 0. COMBINED CYCLE 0. 0. 1 Ow 12629. 0. 0. GENERAL PLANT 0. 0. 0. 0. 0. 0. INVESTMENTS, $1000 COMBUSTION TURBINE 0. 0. 0. 0. 0. 0. 41542. HYDRO 0. 0. 0. 0. 0. 0. 0. STEAM PRODUCTION 0. 0. 0. 0. 0. 0. 0. COMBINED CYCLE 0. 0. 0. 2525727. 0. 0. 4746195. GENERAL PLANT 0. 0. 0. 0. 0. 0. 3800. SUBSTATION/XMISSION 0. 0. 0. 0. 0. 0. _261034. TOTAL INVESTMENTS 0. 0. 0. 2525727. Oo. 0. 53052571. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 78 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: §2-113-4-000 FILES: CHMGT.O1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 VERSION: PS6-9/82 TABLE 7 INCREMENTAL CASH EXPENDITURES ($1000) YEAR ENDING DEC 31 1983 1984 1985 19846 1987 1988 1989 1990 1991 DEMAND-RELATED (FIXED) CASH EXPENSES AK P ADMIN POWER 0. 0. 0. 0. 0. 0. 0. 0. 0. BRADLEY LA POWER 0. 0. 0. 0. 0. 24834. 24847. 24868. 24988. INTERTIE POWER 0. 0. 785. 847. 913. 984. 1066. 1153. 1244. ADDTHL PUR POWER 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PURCHASED POWER 0. 0. 785. 847. 913. 25818. 25913. 26020. 26132. FIXED G+ 4388. 4836. 5786. 6458. 6974. 7532. 8135. 8786. 9489. SUBSTATION/TRANSMISSION LINE O+f 210. 226. 1162. 1254. 1355. 1880. 2031. 2193. 2369. ADMINISTRATIVE AND GENERAL 0. 39. 267. 372. 402. 434. 469. 506. 347. INTERNAL FINANCING 0. 0. 0. 0. 0. 0. 0. 0. 0. LONG-TERM LEASES 133. 133. 133. 133. 133. 133. 133. 133. 133. ADDITIONAL G&T STAFF 0. 340. 770. 1097. 15463. 2227. 3174. 3428. 3702. SUSITNA BARGE EXP 700. 720. 742. 44. 465. 492. 522. 553. 388. G & T ORGANIZATION 200. 200. 150. 0. 0. 0. 0. 0. 0. INTERIM REPLACEMENTS 42. 64. 332. 378. 378. 462. 462. 462. 462. INSURANCE 21. 35. 187. 220. 220. 262. 262. 262. 262. PRINCIPAL 116. 134, 657. 734. 840. 1148. 1311. 1461. 1798. INTEREST 2306. 3174. 15884. 17251. 17164. 21657. 21514. 21364. 21189. PROPERTY TAXES 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL GENERATION & XMSN EXPENSES 8116. 10103. 26070. 28358. 29495. 36248. 38012. 39148. 40539. TOTAL DEMAND-RELATED CASH EXPENSES 8116. 10103. 26855. 29204, 30408.. 62066. 63926. 65168. 66671. LESS CAPACITY SALES 0. 0. 0. 0. 0. 0. 0. 0. 0. NET DEMAND-RELATED CASH EXPENSES 8116. 10103. 26855. 29204. 30408. 62066. 63926. 65168. 66671. ENERGY-RELATED (VARIABLE) CASH EXPENSES AK P ADMIN ENERGY 1220. 1220. 1220. 1342. 1342. 1342. 1476. 1476. 1476. BRADLEY LA ENERGY 0. 0. 0. 0. 0. 967. 1044. 1128. 1219. INTERTIE ENERGY 0. 0. 0. 0. 0. 0. 0. 0. 0. ADDTNL_ PUR ENERGY 0. 0. 0. 0. 0. 0. 0. 0. 0. SUPPLEMENTAL PURCHASES 72. 32. 24. 32. 53. 19. 44. 85. 176. TOTAL PURCHASED ENERGY 1291. 1252. 1243. 1374. 1395. 2328. 2564. 2689. 2871. FUEL EXPENSE 3126. 6146. 6517. 7631. 9012. 8195. 9644. 11364. 62604. VARIABLE 03N 914, 1026. 1134. 1282. 1444. 1461. 1654. 1844. 2088. TOTAL GENERATION EXPENSES 6040. 7172. 7652. 8913. 10458. 9656. 11298. 13208. 64692. BURNS & MCOONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 YEAR ENDING DEC 31 TOTAL ENERGY-RELATED CASH EXPENSES NET ENERGY-RELATED CASH EXPENSES TOTAL CASH EXPENDITURES DEMAND-RELATED EXPENSES, $/KW-YR ENERGY-RELATED EXPENSES, MILLS/KWH TOTAL EXPENSES, MILLS/KWH TABLE 7 INCREMENTAL CASH EXPENDITURES ($1000) 1983 1984 1985 1986 7331. 8424. 8895. 10287. 7331. 8424. 8895. 10287. 15447. 18527. 35750. 39491. 20.65 24.82 63.94 67.14 4.25 4.71 4.81 5.35 8.95 10.35 19.31 20.56 1987 11853. 11853. 42262. 67.57 5.95 21.23 1988 11984. 11984. 74050. 133.47 5.81 35.93 1989 13862. 13862. 77787. 132.90 6.49 36.42 PAGE: 79 DATE: 21-May-83 TIME: 09:24 FILES: CHNGT.D1 GASGT.D2 VERSION: PS6-9/82 1990 1991 15897. 67562. 15897. 675362. 81066. 134233. 130.86 129.46 7.17 29.43 36.58 58.46 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 80 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 THLE 7 VERSION: PS6-9/82 INCREMENTAL CASH EXPENDITURES ($1000) YEAR ENDING DEC 31 1992 1993 1994 1995 1996 1997 1998 1999 2000 DEMAND-RELATED (FIXED) CASH EXPENSES AK P ADMIN POWER 0. 0. 0. 0. 0. 0. 0. 0. 0. BRADLEY LA POWER 24902. 24929. 24949. 24976. 24997. 25031. 25058. 25092. 25126. INTERTIE POWER 1341. 1448. 1564. 1688. 1826. 1974. 2132. 2300. 2484. ADDTNL PUR POWER 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PURCHASED POWER 26243. 26377. 26515. 26665. 26823. 27004. 27190. 27392. 27610. FIXED G+" 10248. 11068. 11953. 12909. 13942. 15057. 16262. 175463. 18968. SUBSTATION/TRANSMISSION LINE O+f1 2558. 2763. 29784. 3435. 3939. 4254. 4594, 5250. 5670. ADMINISTRATIVE AND GENERAL 590. 637. 688. 744. 803. 867. 937. 1012. 1093. INTERNAL FINANCING 0. 0. 0. 0. 0. 0. 0. 0. 0. LONG-TERM LEASES 133. 133. 133. 133. 133. 133. 133. 133. 133. ADDITIONAL G&T STAFF 3998. 4318. 4664. 5037. 3440. 5875. 6345. 6852. 7401. SUSITNA BARGE EXP 625. 665. 708. 755. 805. 859. 918. 981. 925. G & T ORGANIZATION 0. 0. 0. 0. 0. 0. 0. 0. 0. INTERIM REPLACEMENTS 462. 462. 462. 304. 350. 330. 350. 608. 608. INSURANCE 262. 262. 262. 283. 306. 306. 306. 335. 335. PRINCIPAL 2096. 2337. 2605. 3021. 3499. 3905. 4353. 5011. 5592. INTEREST 20980. 20739. 20471. 22506. 24675. 24269. 23821. 26497. 25916. PROPERTY TAXES 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL GENERATION & XMSN EXPENSES 41952. 43384. 44931. 49327. 354092. 56075. 38219. 64242. 66641. TOTAL DEMAND-RELATED CASH EXPENSES 68195. 69761. 71445. 75992. 80914. 83080. 85409. 91634. 94250. LESS CAPACITY SALES 0. 0. 0. 0. 0. 0. 0. 0. 0. NET DEMAND-RELATED CASH EXPENSES 68195. 69761. 71445. 75992. 80914. 83080. 85409. 91634. 94250. ENERGY-RELATED (VARIABLE) CASH EXPENSES AK P ADMIN ENERGY 1624. 1624. 1624. 1784. 1786. 1784. 1966. 1946. 1966. BRADLEY LA ENERGY 1315. 1421. 1535. 1657. 1791. 1934. 2087. 2255. 2436. INTERTIE ENERGY 0. 0. 0. 0. 0. 0. 0. 0. 0. ADDTNL PUR ENERGY 0. 0. 0. 0. 0. 0. 0. 8280. 33982. SUPPLEMENTAL PURCHASES 319. 682. 1003. 1802. 3240. 4976. 8570. 9213. 9948. TOTAL PURCHASED ENERGY 3258. 3727. 4162. 3245. 6817. 8496. 12643. 21714. 48331. FUEL EXPENSE 75447. 935670. 115312. 217101. 332995. 535647. 615126. 676881. 757600. VARIABLE O&M 2321. 2640. 2922. 3294. 3715. 4071. 4602. 5053. 3638. TOTAL GENERATION EXPENSES 77768. 98311. 118234. 220395. 336710. 539717. 619729. 681934. 763238. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 YEAR ENDING DEC 31 TOTAL ENERGY-RELATED CASH EXPENSES NET ENERGY-RELATED CASH EXPENSES TOTAL CASH EXPENDITURES DEMAND-RELATED EXPENSES, $/KW-YR ENERGY-RELATED EXPENSES, MILLS/KWH TOTAL EXPENSES, MILLS/KWH TABLE 7 INCREMENTAL CASH EXPENDITURES ($1000) 19972 1993 1994 1995 81027. 102038. 122396. 225640. 81027. 102038. 122396. 225540. 149222. 171799. 193842. 301632. 128.19 126.61 125.34 129.02 34.09 41.38 47.87 85.24 62.78 69.67 75.81 113.95 632372. 632372. 717780. 130.99 214.58 243.56 343528. 343528. 348413. 348413. 431493. 131.87 192.97 154.79 222.20 PAGE: 81 DATE: 21-May-83 TIME: 09:24 FILES: CHMGT.D1 GASGT.D2 VERSION: PS6-9/82 1999 2000 703648. 811569. 703648. 811569. 795282. 905819. 135.95 135.22 230.55 256.58 260.58 286.38 CHUGACH, PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (82, 20 YEAR ENDING DEC 31 DENMAND-RELATED (FIXED) CASH EXPENSES AK P ADMIN POWER BRADLEY LA POWER INTERTIE POWER ADDTNL PUR POWER TOTAL PURCHASED POWER FIXED O+M SUBSTATION/TRANSNISSION LINE O+f ADMINISTRATIVE AND GENERAL INTERNAL. FINANCING LONG-TERM LEASES ADDITIONAL G&T STAFF SUSITNA BARGE EXP G & T ORGANIZATION INTERIM REPLACEMENTS INSURANCE PRINCIPAL INTEREST PROPERTY TAXES TOTAL GENERATION & XMSN EXPENSES TOTAL DEMAND-RELATED CASH EXPENSES LESS CAPACITY SALES NET DEMAND-RELATED CASH EXPENSES ENERGY-RELATED (VARIABLE) CASH EXPENSES AK P ADMIN ENERGY BRADLEY LA ENERGY INTERTIE ENERGY ADDTNL PUR ENERGY SUPPLEMENTAL PURCHASES TOTAL PURCHASED ENERGY FUEL EXPENSE VARIABLE O&n" TOTAL GENERATION EXPENSES BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN HOMER & MATANUSKA ELEC. ASSOCIATIONS TABLE 7 INCREMENTAL CASH EXPENDITURES ($1000) 2001 2002 2003 2004 0. 0. 0. 0. 25167. 25208. 25255. 25303. 2683. 2897. 313i. 3381. 27849. 28104. 28387. 28684. 26679. 28014. 31119. 33608. 6460. 6977. 7535. 8138. 3657. 3950. 4266. 4607. 0. 0. 0. 0. 133. 133. 133. 133. 7993. 8632. 9323. 10068. 999. 1079. 1145. 1258. 0. 0. 0. 0. 2430. 2430. 2430. 2430. 1622. 1622. 1622. 1622. 6420. 7163. 7984. 899. eaia3. 83379. 82978. 81663. 140537. 144200. 148156. 152428. 168986. 172904. 176543. 181112. 168386. 172304. 176543. 181112. 2162. 2162. 2162. 2378. 2631. 2840. 3067. 3313. 0. 0. 0. 0. 0. 0. 19495. 49833. 7977. 11217. 11366. 11142. 12469. 16218. 36088. 44666. 799893. 908435. 1000185. 1117271. 8216. 9154. 10029. 11099. 808109. 917638. 1010213. 1128370. ee 2005 0. 25357. 3652. 0. 29009. 36297. 8789. 4976. 0. 133. 10874. 1359. 0. 2430. 1622. 9920. 80643. 0. 157043. 186052. 0. 186052. 2378. 3578. 0. 44076. 10368. 60400. 1292021. 12397. 1304418. 2006 0. 25418. 3942. 0. 29361. 39201. 9492. 5374. 0. 133. 11744. 1468. 0. 2430. 1622. 11057. 79506. 0. 162027. 191387. 191387. 2378. 3864. 147783. 11036. 145060. 1396249. 13577. 1409826. PAGE: 82 DATE: 21-May-83 TIME: 09:24 FILES: CHNGT.D1 GASGT.D2 VERSION: PS6-9/82 2007 2008 2009 0. 0. 0. 25480. 25548. 25616. 4259. 4600. 4967. 29738. 30148. 30583. 42337. 66954. 72310. 10251. 11071. 11957. 5804. 14760. 15941. 0. 0. 0. 133. 133. 133. 12683. 13698. 14794. 1585. 1712. 1849. 0. 0. 0. 2430. 8447. 8447. 1622. 5920. 5920. 12324. 16629. 18535. 78239. 265796. 263890. 167408. 405120. 413776. 19714, 435268. 444359. 197146. 435268. 444359. 2614, 2614. 2614. 4173. 4507. 4868. 0. 0. 0. 104149. 0. 11422. 9316. 21891. 22582. 120252. 29012. 41484. 1617422. 1648459. 1856777. 15044. 23168. 25568. 1632446. 1671627. 1882345. BURNS & MCOONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 TABLE 7 INCREMENTAL CASH EXPENDITURES ($1000) YEAR ENDING DEC 31 2001 2002 2003 2004 2005 TOTAL ENERGY-RELATED CASH EXPENSES 820778. 933856. 1046302. 1195036. 1364818. NET ENERGY-RELATED CASH EXPENSES 820778. 933856. 1046302. 1195036. 1364818. TOTAL CASH EXPENDITURES 989164. 1106161. 1222844. 1376148. 1550870. DEMAND-RELATED EXPENSES, $/KW-YR 233.55 230.97 228.68 226.96 225.52 ENERGY-RELATED EXPENSES, MILLS/KWH 250.39 274.83 296.99 327.50 361.06 TOTAL EXPENSES, MILLS/KWH 301.76 325.53 347.10 377.13 410.28 DATE: 21-May-83 TIME: 09:24 FILES: CHAGT.D1 GASGT.D2 VERSION: PS6-9/82 2006 2007 2008 2009 1574886. 1752719. 1700639. 1923832. 1574886. 1752719. 1700639. 1923832. 1766273. 1949865. 21359707. 2368190. 224.11 223.27 476.74 470.22 41.76 431.60 404.24 440.94 450.58 480.14 507.70 542.79 BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 8&2-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (82,20 TABLE 7 INCREMENTAL CASH EXPENDITURES ($1000) YEAR ENDING DEC 31 2010 2011 2012 2013 2014 DEMAND-RELATED (FIXED) CASH EXPENSES AK P ADMIN POWER 0. 0. 0. 0. 0. BRADLEY LA POWER 25697. 25779. 25874. 25969. 26078. INTERTIE POWER 3365. 5794. 6253. 6758. 7298. ADDTNL PUR POWER 0. 0. 0. 0. 0. TOTAL PURCHASED POWER 31062. 31572. 32127. 32727. 33376. FIXED O+n 78095. 84343. 91090. 129571. 139937. SUBSTATION/TRANSMISSION LINE O+M 12913. 13747. 15062. 16267. 17569. ADMINISTRATIVE AND GENERAL 17217. 18594. 20081. 34166. 36899. INTERNAL FINANCING 0. 0. 0. 0. 0. LONG-TERM LEASES 133. 133. 133. 133. 133. ADDITIONAL G&T STAFF 15977. 17256. 18636. 20127. 21737. SUSITNA BARGE EXP 1997. 2157. 2329. 2516. 2717. G & T ORGANIZATION 0. 0. 0. 9. 0. INTERIM REPLACEMENTS 8447. 8447. 8447. 17287. 17287. INSURANCE 5920. 5920. 5920. 12234. 12234, PRINCIPAL 20660. 20515. 22866. 14492. 161534. INTEREST 261765. 259488. 257137. 532745. 531084. PROPERTY TAXES 0. 0. 0. 0. 0. TOTAL GENERATION & XMSN EXPENSES 423124. 430799. 441701. 779539. 795750. TOTAL DEMAND-RELATED CASH EXPENSES 454186. 462371. 473828. 812266. 829126. LESS CAPACITY SALES 0. 0. 0. 0. 0. NET DEMAND-RELATED CASH EXPENSES 434186. 462371. 473828. 812266. 8297126. ENERGY-RELATED (VARIABLE) CASH EXPENSES AK P ADMIN ENERGY 2876. 2876. 2876. 3163. 3163. BRADLEY LA ENERGY 5257. 5677. 6131. 6621. 7152. INTERTIE ENERGY 0. 0. 0. 0. 0. ADDTNL PUR ENERGY 37096. 115740. 192305. 0. 13360. SUPPLEMENTAL PURCHASES 23020. 19769. 20610. 33535. 36388. TOTAL PURCHASED ENERGY 68249. 144063. 221922. 43319. 60063. FUEL EXPENSE 2110536. 2276932. 2561894. 2798271. 3148837. VARIABLE O&M 28327. 30761. 339781. 45763. 30648. TOTAL GENERATION EXPENSES 2138863. 2307694. 2595875. 2844034. 3199505. Werner bene ve Rew ee ae eee a a ew — ee 2015 956847. 856847. 3163. 7724. 0. 83301. 35649. 129837. 3523752. 56047. 3579799. TOTALS 1241841. 223528. ee 4394. 283449. 39587. 550. 118903. 82049. 262195. a. 6319332. 7124379. 7124379. 67821. 921688. 860822. 326074. 1346905. 31605002. 420907. 32025909. PAGE: 84 DATE: 21-May-83 TIME: 09:24 FILES: CHMGT.D1 GASGT.D2 VERSION: PS6-9/82 one oe = ——— a os me —s — BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 YEAR ENDING DEC 31 TOTAL ENERGY-RELATED CASH EXPENSES NET ENERGY-RELATED CASH EXPENSES TOTAL CASH EXPENDITURES DEMAND-RELATED EXPENSES, $/KW-YR ENERGY-RELATED EXPENSES, MILLS/KWH TOTAL EXPENSES, MILLS/KWH TABLE 7 INCREMENTAL CASH EXPENDITURES ($1000) 2010 2011 2012 2013 2014 2015 =~ TOTALS 2207112. 2451757. 2817797. 2887353. 3259549. 3709636. 33372814. 2207112. 2451757. 2817797. 2887353. 3259569. 3709634. 33372814. 2661298. 2914128. 32914625. 34699618. 4088695. 4566483. 40497193. 464. 88 457.79 453. 42 731.40 741.62 741.22 304. 30 488. 41 523.88 580.75 574.25 625.64 687.35 312.93 588.91 622.68 678.41 735.80 784.78 846.12 379.74 DATE: 21-May-83 TIME: 09:24 FILES: CHMGT.D1 GASGT.D2 VERSION: PS6-9/82 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 86 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. a PLAN: GAS (8%, 20 me 8 VERSION: PS6-9/82 INCREMENTAL ACCRUAL EXPENSES ($1000) YEAR ENDING DEC 31 1983 1984 1985 1986 1987 1988 1989 1990 1991 DENAND-RELATED (FIXED) ACCRUAL EXPENSES AK P ADMIN POWER 0. 0. 0. 0. 0. 0. 0. 0. 0. BRADLEY LA POWER 0. 0. 0. 0. 0. 24834. 24847. 24868. 24888. INTERTIE POWER 0. 0. 785. 847. 913. 984. 1066. 1153. 1244, ADDTNL PUR POWER 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PURCHASED POWER 0. 0. 785. 847. 913. 25618. 25913. 26020. 26132. FIXED O+M 4388. 4836. 5786. 6458. 6974. 7532. 8135. 8786. 9489. SUBSTATION/TRANSMISSION LINE O+" 210. 226. 1162. 1254. 1355. 1880. 2031. 2193. 2369. ADMINISTRATIVE AND GENERAL 0. 39. 267. 372. 402. 434. 469. 506. 547. LONG-TERM LEASES 133. 133. 133. 133. 133. 133. 133. 133. 133. ADDITIONAL G&T STAFF 0. 340. 770. 1097. 1563. 2227. 3174. 3428. 3702. SUSITNA BARGE EXP 700. 720. 742. 440. 465. 492. 522. 553. 588. G & T ORGANIZATION 200. 200. 150. 0. 0. 0. 0. 0. 0. INSURANCE 21. 35. 187. 220. 220. 262. 262. 262. 262. STRAIGHT LINE DEPRECIATION 376. 819. 4061. 4460. 4460. 5608. 3608. - 5608. 5608. INTEREST 2306. 3174. 15884. 17251. 17164. 21657. 21514. 21364. 21189. PROPERTY TAXES 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL GENERATION & XMSN EXPENSES 8534. 10723. 297142. 31686. 32737. 40226. 41847. 42833. 43886. TOTAL DEMAND-RELATED ACCRUAL EXPENSES 8534. 10723. 29927. 32532. 33650. 66044. 67760. 68853. 70019. LESS CAPACITY SALES 0. 0. 0. 0. 0. 0. 0. 0. 0. NET DEMAND-RELATED ACCRUAL EXPENSES 8534. 10723. 29927. 32532. 33650. 66044, 67760. 68853. 70019. ENERGY-RELATED (VARIABLE) ACCRUAL EXPENSES AK P ADMIN ENERGY 1220. 1220. 1220. 1342. 1342. 1342. 1476. 1476. 1476. BRADLEY LA ENERGY 0. 0. 0. 0. 0. 967. 1044. 1128. 1219. INTERTIE ENERGY 0. 0. 0. 0. 0. 0. 0. 0. 0. ADDTNL PUR ENERGY 0. 0. 0. 0. 0. 0. 0. 0. 0. SUPPLEMENTAL PURCHASES 72. 32. 24. 32. 53. 19. 44. 85. 176. TOTAL PURCHASED ENERGY 1291. 1252. 1243. 1374. 1395. 2328. 2564. 2689. 2871. FUEL EXPENSE 3126. 6146. 6517. 7631. 9012. 8195. 9644. 11364. 62604. VARIABLE O&M 914, 1026. 1134. 1282. 1446. 1441. 1654. 1844, 2088. TOTAL GENERATION EXPENSES 6040. 7172. 7652. 8913. 10458. 9656. 11298. 13208. 64692. TOTAL ENERGY-RELATED ACCRUAL EXPENSES 7331. 8424, 8895. 10287. 11853. 11984. 13862. 15897. 67562. NET ENERGY-RELATED ACCRUAL EXPENSES 7331. 8424. 8895. 10287. 11853. 11984. 13862, 15897. 67562. CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 YEAR ENDING DEC 31 TOTAL ACCRUAL EXPENDITURES DEMAND-RELATED EXPENSES, $/KW-YR ENERGY-RELATED EXPENSES, MILLS/KWH TOTAL EXPENSES, MILLS/KWH BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM TABLE 8 INCREMENTAL ACCRUAL EXPENSES ($1000) 81622. 140.87 38.21 45503. 78028. 142.03 37.86 42819. 74.79 22.29 19147. 26.35 10.70 38822. 71.25 20.97 15865. 21.72 22.85 ae 4 DATE: 2i-tlay-@9 TIME: 09:24 FILES: CHHGT.D1 GASGT.D2 VERSION: PS6-9/82 1990 1991 84750. 137581. 138.26 135.96 7.17 29.43 38.24 59.92 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 88 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT..02 GENERATION AND TRANSHISSION COOP. PLAN: GAS (8%, 20 TABLE @ VERSION: PS6-9/82 INCREMENTAL ACCRUAL EXPENSES ($1000) YEAR ENDING DEC 31 1992 1993 1994 1995 1996 1997 1998 1999 2000 DEMAND-RELATED (FIXED) ACCRUAL EXPENSES AK P ADMIN POWER 0. 0. 0. 0. 0. 0. 0. 0. 0. BRADLEY LA POWER 24902. 24929. 24749. 24976. 24997. 25031. 25058. 25092. 25126. INTERTIE POWER 1341. 1448. 1566. 1688. 1826. 1974. 2132. 2300. 2484. ADDTNL. PUR POWER 0. 0. o. 0. 0. 0. 0. 0. 0. TOTAL PURCHASED POWER 26243. 26377. 26515. 26665. 26823. 27004, 27190. 27392. 27610. FIXED O+n 10248. 11068. 11953. 12909. 13942. 15057. 16262. 17363. 18968. SUBSTATION/TRANSNISSION LINE O+f 2558. 2763. 2984. 3435. 3939. 4254. 4594, 5250. 5670. ADMINISTRATIVE AND GENERAL 590. 637. 688. 744. 803. 867. 937. 1012. 1093. LONG-TERM LEASES 133. 133. 133. 133. 133. 133. 133. 133. 133. ADDITIONAL G&T STAFF 3998. 4318. 4664. 3037. 3440. 5875. 6345. 6852. 7401. SUSITNA BARGE EXP 625. 665. 708. 733. 805. 859. 918. 981. 925. G & T ORGANIZATION 0. 0. 0. 0. 0. 0. 0. 0. 0. INSURANCE 262. 262. 262. 283. 306. 306. 306. 335. 335. STRAIGHT LINE DEPRECIATION 5608. 5608. 5608. 6191. 6821. 6821. 6821. 7615. 7615. INTEREST 20980. 20739. 20471. 22506. 24675. 24269. 23821. 26497. 25916. PROPERTY TAXES 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL GENERATION & XMSN EXPENSES 45002. 46193. 47472. 31993. 56864. 58442. 60137. 66238. 68055. TOTAL DEMAND-RELATED ACCRUAL EXPENSES 71245. 72570. 73987. 78658. 83687. 85446. 87327. 93630. 95665. LESS CAPACITY SALES 0. 0. 0. 0. 0. 0. 0. 0. NET DEMAND-RELATED ACCRUAL EXPENSES 71245. 72570. 73987. 78658. 83687. 85444. 87327. 93630. 95665. ENERGY-RELATED (VARIABLE) ACCRUAL EXPENSES AK P ADMIN ENERGY 1624. 1624. 1624, 1786. 1786. 1786. 1966. 1964. 1966. BRADLEY LA ENERGY 1315. 1421. 1535. 1657. 1791. 1934. 2087. 2255. 2436. INTERTIE ENERGY 0. 0. 0. 0. 0. 0. 0. 0. 0. ADDTNL PUR ENERGY 0. 0. 0. 0. 0. 0. 0. 8280. 33982. SUPPLEMENTAL PURCHASES 319. 682. 1003. 1802. 3240. 4976. 8590. 9213. 9948. TOTAL PURCHASED ENERGY 3258. 3727. 4162. 5245. 6817. 8496. 12643. 21714. 48331. FUEL EXPENSE 73447. 95670. 115312. 217101. 332995. 535647. 615126. 676881. 757600. VARIABLE 08M 2321. 2640. 2922. 3294. 3715. 4071. 4602. 5053. 5638. TOTAL GENERATION EXPENSES 77768. 98311. 118234. 220395. 336710. 539717. 619729. 681934. 763238. TOTAL ENERGY-RELATED ACCRUAL EXPENSES 81027. 102038. 122396. 225640. 343528. 548413. 632372. 703648. 811569. NET ENERGY-RELATED ACCRUAL EXPENSES 81027. 102038. 122396. 225640. 343528. 548413. 632372. 703648. 811549. . es | Ee | ie . breccia emt ree BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 89 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHMNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 TABLE @ VERSION: PS6-9/82 INCREMENTAL ACCRUAL EXPENSES ($1000) YEAR ENDING DEC 31 1992 1993 1994 1995 1996 1997 1998 1999 2000 TOTAL ACCRUAL EXPENDITURES 152272. 174609. 196383. 304298. 427215. 633859. 719699. 797278. 907234. DEMAND-RELATED EXPENSES, $/KW-YR 133.92 131.71 129.80 133.54 137.42 135.63 133.94 138.92 137.25 ENERGY-RELATED EXPENSES, MILLS/KWH 34.09 41.38 47.87 85.24 125.28 192.97 214.58 230.55 256.58 TOTAL EXPENSES, MILLS/KWH $4.06 70.81 76.80 114.96 155.80 223.03 244.21 261.23 286.83 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 90 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSHISSION COOP. PLAN: GAS (8%, 20 TALE 8 VERSION: PS6-9/82 INCREMENTAL ACCRUAL EXPENSES ($1000) YEAR ENDING DEC 31 2001 2002 2003 2004 2005 2006 2007 2008 2009 DEMAND-RELATED (FIXED) ACCRUAL EXPENSES AK P ADMIN POWER 0. 0. 0. 0. 0. 0. 0. 0. 0. BRADLEY LA POWER 25167. 25208. 25255. 23303. 25357. 25418. 23480. 25348. 23616. INTERTIE POWER 2683. 2897. 3131. 3381. 3652. 3942. 4259. 4600. 4967. ADDTNL PUR POWER 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PURCHASED POWER 27849. 28104. 28387. 28684, 29009. 27361. 29738. 30148. 30583. FIXED. 0+ 26679. 28814. 31119. 33608. 36297. 39201. 42337. 66954. 72310. SUBSTATION/TRANSMISSION LINE O+M 6460. 6977. 7535. 9138. 8789. 9492. 10251. 11071. 11957. ADMINISTRATIVE AND GENERAL 3657. 3950. 4266. 4607. 4976. 5374. 5804. 14760. 15941. LONG-TERM LEASES 133. 133. 133. 133. 133. 133. 133. 133. 133. ADDITIONAL G&T STAFF 7993. 8432. 9323. 100468. 10874. 11744. 12683. 13698. 14794. SUSITNA BARGE EXP 999. 1079. 1165. 1258. 1359. 1468. 1585. 1712. 1849. G & T ORGANIZATION 0. 0. 0. 0. 0. 0. 0. 0. 0. INSURANCE 1622. 1622. 1622, 1622. 1622. 1622. 1622. 5920. 5920. STRAIGHT LINE DEPRECIATION 23601. 23601. 23601. 23601. 23601. 23601. 23601. 73222. 73222. INTEREST 84143. 83399. 82578. 81663. 80643. 79506. 78239. 265796. 263890. PROPERTY TAXES 0. 0. 0. 0. 0. 0. 0. 0. 5 0. 5 . TOTAL GENERATION & XMSN EXPENSES 155288. 158207. 161342. 164699. 1682794. 172141. 176255. 455266. 462016. TOTAL DEMAND-RELATED ACCRUAL EXPENSES 183137. 186311. 189727. 193383. 197303. 201501. 2059773. 485414. 4972599. LESS CAPACITY SALES 0. 0. 0. 0. 0. 0. 0. 0. 0. NET DEMAND-RELATED ACCRUAL EXPENSES 183137. 186311. 189729. 193383. 197303. 201501. 205999. 485414. 492599. ENERGY-RELATED (VARIABLE) ACCRUAL EXPENSES AK P ADMIN ENERGY 2162. 2162. 2162. 2378. 2378. 2378. 2614, 2614. 2614. BRADLEY LA ENERGY 2631. 2840. 3067. 3313. 3578. 3864. 4173. 4507. 4868. INTERTIE ENERGY 0. 0. 0. 0. 0. 0. 0. 0. 0. ADDTNL PUR ENERGY 0. 0. 19495. 49833. 44076. 147783. 104149. 0. 11422. SUPPLEMENTAL PURCHASES 7877. 11217. 11366. 11142. 10368. 11036. 9316. 218971. 22582. TOTAL PURCHASED ENERGY 12669. 16218. 36088. 66666. 60400. 165060. 120252. 29012. 41486. FUEL EXPENSE 799893. 908485. 1000185. 1117271. 1292021. 1396249. 1617422. 1648459. 1856777. VARIABLE 08h 8216. 9154. 10029. 11099. 12397. 13577. 15044, 23168. 25568. TOTAL GENERATION EXPENSES 808109. 917638. 1010213. 1128370. 1304418. 1409826. 1632466. 1671627. 1882345. TOTAL ENERGY-RELATED ACCRUAL EXPENSES 820778. 933856. 1046302. 1195036. 1364818. 1574886. 1752719. 1700639. 1923832. NET ENERGY-RELATED ACCRUAL EXPENSES 820778. 939856. 1046302. 1195036. 1364818. 1574886. 1752719. 1700639. 1923832. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 91 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 09:24 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 — VERSION: PS6-9/82 INCREMENTAL ACCRUAL EXPENSES ($1000) YEAR ENDING DEC 31 2001 2002 2003 2004 2005 2006 2007 2008 2009 TOTAL ACCRUAL EXPENDITURES DEMAND-RELATED EXPENSES, $/KW-YR ENERGY-RELATED EXPENSES, MILLS/KWH TOTAL EXPENSES, MILLS/KWH 1003915. 1120168. 1236031. 1388419. 1562121. 1776387. 1958712. 2186053. 2416430. 254.00 249.75 245.76 242.33 239.15 235.95 233.29 331.67 321.27 250.39 274.83 2976.99 327.50 361.06 401.76 431.60 404.24 440.94 306.26 329.66 350.85 380.49 413.26 453.16 482.32 519.42 553.85 BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSHISSION COOP. PLAN: GAS (8%, 20 TABLE 8 INCREMENTAL ACCRUAL EXPENSES ($1000) YEAR ENDING DEC 31 2010 2011 2012 2013 2014 DEMAND-RELATED (FIXED) ACCRUAL EXPENSES AK P ADMIN POWER 0. 0. 0. 0. 0. BRADLEY LA POWER 25697. 25779. 25874. 25969. 26078. INTERTIE POWER 3365. 5794. 6253. 6758. 7298. ADDTNL PUR POWER 0. 0. 0. 0. 0. TOTAL PURCHASED POWER 31062. 31572. 32127. 32727. 33376. FIXED O+n 78095. 84343. 91090. 129571. 139937. SUBSTATION/TRANSMISSION LINE O+f1 12913. 13947. 15062. 16267. 17569. ADMINISTRATIVE AND GENERAL 17217. 18594. 20081. 34166. 36899. LONG-TERM LEASES 133. 133. 133. 133. 133. ADDITIONAL G&T STAFF 15977. 17256. 18634. 20127. 21737. SUSITNA BARGE EXP 1997. 2157. 2329. 2516. 2717. G & T ORGANIZATION 0. 0. 0. 0. 0. INSURANCE 5920. 59720. 5920. 12234. 12234. STRAIGHT LINE DEPRECIATION 75222. 75222. 73222. 151069. 151069. INTEREST 261765. 259488. 257137. 532745. 531084. PROPERTY TAXES 0. 0. 0. 0. 0. TOTAL GENERATION & XMSN EXPENSES 469239. 477059. 485610. 898829. 913379. TOTAL DEMAND-RELATED ACCRUAL EXPENSES 500301. 508631. 517737. 931556. a LESS CAPACITY SALES 0. 0. 0. 0. NET DEMAND-RELATEO ACCRUAL EXPENSES 500301. 508631. 517737. 931556. 9% ENERGY-RELATED (VARIABLE) ACCRUAL EXPENSES AK P ADMIN ENERGY 2876. 2876. 2876. 3163. BRADLEY LA ENERGY 3257. 5677. 6131. 6621. INTERTIE ENERGY 0. 0. 0. 0. ADDTNL PUR ENERGY 37096. 115740. 192305. 0. SUPPLEMENTAL PURCHASES 23020. 19769. 20610. 33535. TOTAL PURCHASED ENERGY 68249. 144063. 221922. 43319. FUEL EXPENSE 2110536. 2276932. 2561894. 2798271. 31 VARIABLE 0324 28327. 30761. 33981. 45763. TOTAL GENERATION EXPENSES 2138863. 2307694. 2595875. 2844034. 31 46755. 3163. 7152. 0. 13360. 36388. 60063. 48837. 50668. 99505. TOTAL ENERGY-RELATED ACCRUAL EXPENSES 2207112. 2451757. 2817797. 2887353. 3259549. NET ENERGY-RELATED ACCRUAL EXPENSES 2207112. 2451757. 2817797. 2887353. 3259569. 2015 0. 26194. 7880. 0. 34073. 151132. 18974. 39851. 133. 23476. 2934. 0. 12234. 151069. a} 928636. 962709. 0. 962709. 3163. 7724. 0. 83301. 35649. 129837. 3523752. 56047. 3579799. 3709636. 3709636. TOTALS 0. 708438. 96609. 805047. 1241841. 223528. 240550. 4394. 283449. 39587. 550. 82049. 1090037. =e . 7028271. 7633318. 7833318. 67821. y2168. 860822. 326074. 1346905. 31605002. 420907. 32025909. 33372814, 33372814. PAGE: 92 DATE: 21-May-83 TIME: 09:24 FILES: CHHGT.D1 GASGT. D2 VERSION: PS6-9/82 BURNS & MCDONNELL ENGINEERING COMPANY CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 YEAR ENDING DEC 31 TOTAL ACCRUAL EXPENDITURES DEMANO-RELATED EXPENSES, $/KW-YR ENERGY-RELATED EXPENSES, MILLS/KWH TOTAL EXPENSES, MILLS/KWH 2010 2707413. 312.08 488.41 599.12 POWER SUPPLY PROGRAM TABLE 8 INCREMENTAL ACCRUAL EXPENSES ($1000) 2011 2012 2013 2960388. 3335534. 3818908. 4206324. 2014 2015 TOTALS 4672345. 41206132. 503.460 495.44 861.75 844.83 832.79 334.59 323.88 380.75 374.25 632.56 687.46 759.53 625.64 687.35 807.36 845.73 312.93 384.39 DATE: 2i-ta TIME: op:za" FILES: CHMGT.D1 GASGT. D2 VERSION: PS6-9/62 BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS (8%, 20 TABLE 9 SUMMARY ($1000) 33-YEAR PERIOD TOTAL CASH EXPENDITURES 40497193. PRESENT VALUE OF CASH EXPENDITURES (1983$) 1983 TO 2015 3635130. TOTAL ACCRUAL EXPENSES 41206132. PRESENT VALUE OF ACCRUAL EXPENSES (1983$) 3694657. TOTAL INVESTMENT 5052571. ACCUMULATED DEPRECIATION 1990037. NET INVESTMENT 3962535. AVERAGE INCREMENTAL ACCRUAL ENERGY COST 386.39 MILLS/KWH TOTAL FUEL AMOUNTS REQUIRED BELUGA GAS 226547676. MCF NORTH GAS 737674256. MCF ENSTAR GAS 9299725. MCF BELUGA GAS 7701992. MCF b . . ee PAGE: 94 DATE: 21-May-83 TIME: 09:24 FILES: CHMGT.D1 GASGT.D2 VERSION: PS6-9/82 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 95 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:17 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(B%, 20YR) VERSION: FIN. FORE. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) CONTRACT YEAR 1983 1984 1985 1986 1987 1988 1989 1990 1991 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE FO010 4 1979 4 1986 731. 9.187 34.0 7.0 3 2013 25. 131/$1, 000, 000 BALANCE AT START OF YEAR 4731. 4731. 4731. 4731. 4699. 4654. 4604. 4550. 4490. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 435. 435. 435. 434. 430. 426. 421. 416. 410. PRINCIPAL PAYMENTS 0. 0. 0. 32. 5. 50. 34. 60. 65. TOTAL PAYMENTS 435. 435. 435. 465. 476. 76. 476. 76. 476. BALANCE AT END OF YEAR 4731. W1. Wi. 4699. 4654. 4604. 4550. 4490. 4425. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. Fo015 3 1979 3S 1986 2237. 9.347 34.0 7.0 4 2013 25. 469/$1, 000, 000 BALANCE AT START OF YEAR 2239. 2239. 2239. 2239. 2226. 2205. 2183. 2158. 2130. ADVANCES DURING THE YEAR 0. 0. 1 06 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 209. 209. 209. 209. 207. 205. 203. 201. 198. PRINCIPAL PAYMENTS 0. 0. 0. 13. 21. 23. 25. 27. 30. TOTAL PAYMENTS 209. 209. 209. 222. 228. 228. 228. 228. 228. BALANCE AT END OF YEAR 2239. 2239. 2239. 2226. 2205. 2183. 2158. 2130. 2100. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. F0020 11 1979 11 1986 1189. 9.345 34.0 7.0 10 2013 25. 465/$1, 000, 000 BALANCE AT START OF YEAR 1189. 1189. 1189. 1189. 1187. 1177. 1145. 1153. 1139. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 111. 111. 111. 111. 111. 110. 108. 107. 106. PRINCIPAL PAYMENTS 0. 0. 0. 2. 11. 12. 13. 14. 15. TOTAL PAYMENTS 111. 111. 111. 113. 121. 121. 121. 121. 121. BALANCE AT END OF YEAR 1189. 1189. 1189. 1187. 1177. 1145. 1153. 1139. 1123. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. F0025 & 1979 & 1986 1169. 9.075 34.0 7.0 3 2013 24.895/$1, 000, 000 BALANCE AT START OF YEAR 1169. 1149. 1169. 1169. 1143. 1152. 1139. 1126. 1111. ADVANCES DURING THE YEAR o. 0. 9%. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 106. 106. 106. 106. 105. 104, 103. 102. 100. PRINCIPAL PAYMENTS o. 0. 0. 6. 11. 12. 13. 15. 16. TOTAL PAYMENTS 106. 104. 104. 112. 114. 116. 116. 116. 116. BALANCE AT END OF YEAR 1169. 1169. 1169. 1143. 1152. 1139. 1124. 1111. 1095. INTEREST CHARGEO TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. F0030 Z 1979 7 1986 1100. 8.989 34.0 7.0 6 2013 24.714/$1, 000, 000 BALANCE AT START OF YEAR 1100. 1100. 1100. 1100. 1095. 1084. 1073. 1060. 1044. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 99. 99. 99. 99. 98. 97. 96. 95. 94, PRINCIPAL PAYMENTS 0. 0. 0. 3. 11. 12. 13. 14. 15. TOTAL PAYMENTS 99. 99. 99. 104. 109. 109. 109. 109. 109. BALANCE AT END OF_ YEAR 1100. 1100. 1100. 1095. 1084. 1073. 1060. 1046. 1031. INTEREST CHARGED TO CONSTR-CREDIT 0. %- 0. 0. 0. 0. 0. 0. 0. at BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 96 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:17 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) VERSION: FIN. FORE. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE FO010 4 1979 4 1986 473i. 9.187 34.0 7.0 3 2013 25. 131/$1, 000, 000 BALANCE AT START OF YEAR 4425. 4353. 4275. 4189. 4095. 3993. 3880. 3757. 3622. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0.- 0. 0. INTEREST PAYMENTS 404. 397. 390. 382. 373. 363. 352. 341. 328. PRINCIPAL PAYMENTS 71. 78. 86. 94. 103. 113. 123. 135. 148. TOTAL PAYMENTS 476. 476. 476. 476. 476. 476. 476. 476. 476. BALANCE AT END OF YEAR 4353. 4275. 4189. 4095. 3993. 3880. 3757. 3622. 3474. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. FO015 SAIS. 5 1986 2239. 9.347 34.0 7.0 4 2013 25. 469/$1, 000, 000 BALANCE AT START OF YEAR 2100. 2067. 2031. 1992. 1948. 1900. 1848. 1791. 1728. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 195. 192. 188. 185. 180. 176. 171. 165. 159. PRINCIPAL PAYMENTS 33. 36. 40. 43. 48. 52. 57. 63. 69. TOTAL PAYMENTS 228. 228. 228. 228. 228. 228. 228. 228. 228. BALANCE AT END OF YEAR 2067. 2031. 1992. 1948. 1900. 1848. 1791. 1728. 1659. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. F0020 11 1979 11° 1986 1187. 9.345 34.0 7.0 10 2013 25. 465/$1, 000, 000 BALANCE AT START OF YEAR 1123. 1107. 1088. 1068. 1046. 1022. 996. 967. 935. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 104. 103. 101. 99. 97. 95. 92. 89. 864. PRINCIPAL PAYMENTS 17. 18. 20. 22. 24. 27. 29. 32. 35. TOTAL PAYMENTS 121. 121. 121. 121. 121. 121. 121. 121. 121. BALANCE AT END OF YEAR 1107. 1088. 1068. 1046. 1022. 996. 967. 935. 900. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. F0025 6 1979 & 1986 1169. 9.075 34.0 7.0 5 2013 24.895/$1, 000, 000 BALANCE AT START OF YEAR 1095. 1077. 1058. 1037. 1014. 988. 961. 931. 898. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 99. 97. 95. 93. 91. 89. 86. 83. 80. PRINCIPAL. PAYMENTS 18. 19. 21. 23. 25. 28. 30. 33. 36. TOTAL PAYMENTS 116. 116. 116. 116. 116. 116. 114. 116. 116. BALANCE AT END OF YEAR 1077. 1058. 1037. 1014. 988. 961. 931. 898. 861. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. F0030 7 1979 7 1986 1100. 8.9879 34.0 7.0 6 2013 24.714/$1, 000, 000 BALANCE AT START OF YEAR 1031. 1014. 996. 976. 954. 930. 904. 876. 845. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 92. 91. 89. 87. 85. 83. 80. 78. 75. PRINCIPAL PAYMENTS 17. 18. 20. 22. 24. 26. 28. 31. 34. TOTAL PAYMENTS 109. 109. 109, 109. 109. 109. 109. 109. 109. BALANCE AT END OF YEAR 1014. 996. 976. 954. 930. 904. 876. 845. 811. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. b. Cece tot Ses acieagl BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) TABLE 10 LONG-TERM DEBT ~— EXISTING ($1, 000) CONTRACT YEAR 2001 . 2002 2003 2004 2005 2006 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE FOO10 4 1979 4 1986 4731. 9.187 34.0 7.0 3 2013 25. 131/$1, 000, 000 BALANCE AT START OF YEAR 3474. 3312. 3135. 29741. 2728. 2495. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 314. 298. 281. 263. 243. 221. PRINCIPAL PAYMENTS 162. 177. 194. 213. 233. 255. TOTAL PAYMENTS 476. 476. 476. 476. 476. 476. BALANCE AT END OF YEAR 3312. 3135. 2741. 2728. 2495. 2240. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. Foo15 3 1979 3 1986 2239. 9.347 34.0 7.0 4 2013 25.469/$1, 000, 000 BALANCE AT START OF YEAR 1659. 1583. 1500. 1409. 1309. 1200. ADVANCES DURING THE YEAR 0. 0. 1 0. 0. 0. 0. INTEREST PAYMENTS 152. 145. 137. 128. 119. 108. PRINCIPAL PAYMENTS 76. 63. 91. 100. 109. 120. TOTAL PAYMENTS 228. 228. 228. 228. 228. 228. BALANCE AT END OF YEAR 1583. 1500. 1409. 1309. 1200. 1080. INTEREST CHARGED TO CONSTR-CREDIT o. 0. 0. 0. 0. 0. F0020 11 1979 11 1986 1189. 9.345 34.0 7.0 10 2013 25. 465/$1, 000, 000 BALANCE AT START OF YEAR 900. 861. 819. 773» 723. 667. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 83. 79. 73. 71. 66. 60. PRINCIPAL PAYMENTS 38. 42. 4%. si. 35. 61. TOTAL PAYMENTS 121. 121. 121. 121. 121. 121. BALANCE AT END OF YEAR 861. 819. 773. 723. 667. 606. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. F0025 6 1979 & 1986 1169. 9.075 34.0 7.0 5 2013 24.895/$1, 000, 000 BALANCE AT START OF YEAR 861. 822. 779. 731. 679. 0 ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 77. 73. 69. 65. 60. 34. PRINCIPAL PAYMENTS 40. 43. 47. 32. 37. 62. TOTAL PAYMENTS 116. 116. 116. 116. 116. 116. BALANCE AT END OF YEAR 822. 779. 731. 679. 623. 341. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. o. F0030 7. 1979 7 1986 1100. 8.989 34.0 7.0 6 2013 24.714/$1, 000, 000 BALANCE AT START OF YEAR 811. 774. 734. 689. 641. 588. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 72. 68. 64. 60. 54. Si. PRINCIPAL PAYMENTS 37. 4i. 44. 48. 33. 38. TOTAL PAYMENTS 109. 109. 109. 109. 109. 109. BALANCE AT END OF YEAR 774. 734. 689. 641. 388. 330. INTEREST CHARGED TO CONSTR-CREDIT 0. Oo 0. 0. 0. 0. 2007 194. 1961. PAGE: 97 DATE: 21-May-83 TIME: 10:17 FILES: CHNGT.D1 GASGT..D2 VERSION: FIN. FORE. 2008 2009 —_— 1655. 170. 141. 306. 335. 476. 476. 1655. 1320. 0. 0. 948. 804. 0. 0. 84. 70. 144, 158. 228. 228. 804. 645. 0. 0. 339. 466. 0. 0. 48. 41. 73. 80. 121. 121. 466. 384. 0. 0. 493. 419. 0. 0. 42. 35. 74. 81. 116. 116. 419. 338. 0. 0. 467. 3978. 0. 0. w. 33. 69. 73. 109. 109. 398. 323. 0. 0. CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE FOO10 4 1979 4 1986 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT FO01S 5 1979 3 1986 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT Fo020 11 1979 11 1986 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0025 & 1979 & 1986 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT FO030 7 1979 7 1986 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN 2010 AMOUNT APR 4731. 1189. 1169. 1100. 9.187 1320. 0. 109. 367. 476. 954. 0. 9 645. 0. 54. 174, 228. 471. 0. 9.345 386. 0. 33. 88. 121. 298. 0. 9.075 338. 0. 28. 89. 116. 249. 0. 8.989 323. 0. 26. 82. 109. 240. 0. TABLE 10 LONG-TERM DEBT - EXISTING ($1, 000) 2011 2012 2013 TERM DEFR MAT DATE 34.0 7.0 3 2013 954. 352. 112. 0. 0. 0. 74. 36. 3. 402. 440. 112. 476. 476. 115. 332. 112. 0. 0. 0. 0. 34.0 7.0 4 2013 471. 281. 72. 0. 0. 0. 38. 19. 2. 191. 209. 72. 228. 228. 74. 281. 72. , 0. 0. 0. 0. 34.0 7.0 10 2013 2978. 201. 95. 0. 0. 0. 23. 15. 5. 97. 106. 95. 121. 121. 100. 201. 95. 0. 0. 0. 0. 34.0 7.0 5 2013 249. 152. 4. 0. 0. 0. 19. 10. 1. 97. 106. 44. 116. 116. 47. 152. 46. 0. 0. 0. 0. 34.0 7.0 & 2013 240. 150. 51. 0. 0. 0. 19. 10. 2. 90. 99. 31. 109. 109. 53. 150. Si. 0. 0. 0. 0. hecer mde al ae mes 2014 2015 QTLY ANORT RATE 25.131/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 25. 469/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 25. 465/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 24. 895/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 24.714/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. PAGE: 98 DATE: 21-May-83 TIME: 10:17 FILES: CHNGT.D1 GASGT.D2 VERSION: FIN. FORE. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) TABLE 10 LONG-TERM DEBT - EXISTING ($1, 000) CONTRACT YEAR 1983 1984 1985 1986 1987 1988 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE Q@TLY AMORT RATE F0035 9 1979 9 1986 1654. 9.248 34.0 7.0 8 2013 25. 260/61, 000, 000 BALANCE AT START OF YEAR 1654, 1654. 1654. 1654. 1649. 1634. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 153. 153. 153. 153. 152. 151. PRINCIPAL PAYMENTS 0. 0. 0. 5. 15. 17. TOTAL PAYMENTS 153. 153. 153. 158. 167. 167. BALANCE AT END OF YEAR 1654. 1654. 1654. 1649. 1634. 1617. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. FO040 9 1979 9 1986 8623. 9.202 34.0 7.0 8 2013 25. 163/$1, 000, 000 BALANCE AT START OF YEAR 8623. 8423. 8623. 8623. 8597. 6518. ADVANCES DURING THE YEAR 0. 0. 1 0. 0. 0. 0. INTEREST PAYMENTS 793. 793. 793. 793. 788. 781. PRINCIPAL PAYMENTS 0. 0. 0. 26. 790 87. TOTAL PAYMENTS 793. 793. 793. 818. 848. 848. BALANCE AT END OF YEAR 8623. 8623. 8623. 8597. 8518. 8431. INTEREST CHARGED TO CONSTR-CREDIT Oo. 0. 0. 0. 0. 0. F0045 10 1979 10 1986 1010. 10.194 34.0 7.0 9 2013 27.286/$1, 000, 000 BALANCE AT START OF YEAR 1010. 1010. 1010. 1010. 1008. 1000. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 103. 103. 103. 103. 102. 102. PRINCIPAL PAYMENTS 0. 0. 0. 2. 8. 9. TOTAL PAYMENTS 103. 103. 103. 105. 110. 110. BALANCE AT END OF YEAR 1010. 1010. 1010. 1008. 1000. 992. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. FO0SO 11. 1979 11 1986 3287. 10.341 34.0 7.0 10 2013 27.406/$1, 000, 000 BALANCE AT START OF YEAR 3287. 3287. 3287. 3287. 3283. 3259. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 340. 340. 340. 340. 339. 336. PRINCIPAL PAYMENTS 0. 0. 0. 4. 24, 27. TOTAL PAYMENTS 340. 340. 340. 344. 363. 3463. BALANCE AT END OF YEAR 3287. 3287. 3287. 3283. 3259. 3232. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. FO0S5 11 1979 11 1986 1187. 10.133 34.0 7.0 10 2013 27.154/$1, 000, 000 BALANCE AT START OF YEAR 1189. 1189. 1189. 1189. 1188. 1178. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 120. 120. 120. 120. 120. 119. PRINCIPAL PAYMENTS 0. 0. 0. 1. 9. 10. TOTAL PAYMENTS 120. 120. 120. 122. 129. 129. BALANCE AT END OF YEAR 1189. 1189. 1189. 1188. 1178. 1148. INTEREST CHARGED TO CONSTR-CREDIT 0. oO. 0. 0. 0. 0. Ae me ee wes 7~= we ey omy im 1989 1157. SAE Png TIME: 10:17 FILES: CHNGT.Di GASGT.D2 VERSION: FIN. FORE. 1990 1991 1599. 1579. 0. 0. 147. 145. 20. 22. 167. 167. 1579. 1558. 0. 0. 8335. 8231. 0. 0. 763. 734. 104. 114, 848. 868. 8231. 8117. 0. 0. 982. 972. 0. 0. 100. 99. 10. 12. 110. 110. 972. 960. 0. 0. 3202. 3169. 0. 0. 330. 326. 33. 37. 363. 363. 3169. 3132. 0. 0. 1157. 1145. 0. 0. 117. 115. 12. 14, 129. 129. 1145. 1131. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 100 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:17 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSHISSION COOP. PLAN: GAS(8Z, 20YR) VERSION: FIN. FORE. TABLE 10 LONG-TERM DEBT ~- EXISTING ($1, 000) CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE FO035 9 1979 9 1986 1654. 9.248 34.0 7.0 8 2013 25. 260/$1, 000, 000 BALANCE AT START OF YEAR 1558. 1534. 1508. 1479. 1447. 1413. 1375. 1334, 1289. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 143. 141. 138. 136. 133. 129. 126. 122. 117. PRINCIPAL PAYMENTS 24. 24. 29. 31. 34. 38. 41. 5. 50. TOTAL PAYMENTS 167. 167. 167. 167. 167. 167. 167. 167. 167. BALANCE AT END OF YEAR 1534. 1508. 1479. 1447. 1413. 1375. 1334, 1289. 1239. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. F0040 9 1979 9 1986 8623. 9.202 34.0 7.0 8 2013 25. 163/$1, 000, 000 BALANCE AT START OF YEAR 8117. 7971. 7854. 7704. 75%. 7359. 7162. 6946. 6709. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 743. 731. 718. 703. 688. 671. 652. 631. 609. PRINCIPAL PAYMENTS 125. 137. 150. 165. 180. 197. 216. 237. 259. TOTAL PAYMENTS 868. 848. 848. 868. 848. 848. 848. 848. 848. BALANCE AT END OF YEAR 799A. 7854. 7704. 7354. 7359. 7162. 6946. 6709. 6450. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. F0045 10 1979 10 1986 1010. 10.194 34.0 7.0 9 2013 27..286/$1, 000, 000 BALANCE AT START OF YEAR 960. 947. 933. 917. 900. 881. 840. 834. 810. ADVANCES DURING THE YEAR 0. 0. 0. 0. o. 0. 0. 0. 0. INTEREST PAYMENTS 97. 96. 95. 93. 91. 89. 87. 84. 62. PRINCIPAL PAYMENTS 13. 14. 14. 17. 19. 21. 23. 26. 29. TOTAL PAYMENTS 110. 110. 110. 110. 110. 110. 110. 110. 110. BALANCE AT END OF YEAR 947. 933. 917. 900. 881. 840. 834. 810. 781. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. FOOSO 11 1979 11 1986 3287. 10.341 34.0 7.0 10 2013 27. 606/$1, 000, 000 BALANCE AT START OF YEAR 3132. 3091. 3046. 2996. 29741. 2880. 2812. 2737. 2654. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 322. 318. 313. 308. 302. 295. 288. 280. 271. PRINCIPAL PAYMENTS 41. 5. 50. 55. 61. 68. 73. 83. 92. TOTAL PAYMENTS 363. 343. 363. 3463. 363. 363. 343. 363. 363. BALANCE AT END OF YEAR 3091. 3046. 2996. 2741. 2880. 2812. 2737. 2654. 2562. INTEREST CHARGEO TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. FO055 11 1979 11 1986 1187. 10.133 34.0 7.0 10 2013 27.154/$1, 000, 000 BALANCE AT START OF YEAR 1131. 1116. 1099. 1081. 1060. 1038. 1013. 985. 955. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 114. 112. 111. 109. 107. 104. 102. 99. 96. PRINCIPAL PAYMENTS 15. 17. 18. 20. 23. 2. 28. 30. 34, TOTAL PAYMENTS 129. 129. 129. 129. 129. 129. 129. 129. 129. BALANCE AT END OF YEAR 1116. 1099. 1081. 1040. 1038. 1013. 985. 955. 921. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. CHUGACH, PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE FO035 9 1979 9 1986 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0040 9 1979 9 1986 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0045 10 1979 10 1986 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT FO050 11 1979 11 1986 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT FOOSS 11 1979 11 1986 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM HOMER & MATANUSKA ELEC. ASSOCIATIONS 2004 DATE 2013 1060. 0. 96. 72. 167. 988. 0. 2013 3514. 0. 495. 373. 848. 3141. 0. 2013 676. 0. 67. 43. 110. 633. 0. 2013 2223. 0. 225. 138. 343. 2084. 0. 2013 798. 0. 79. 50. 129. TABLE 10 LONG-TERM DEBT ~ EXISTING ($1,000) 2001 2002 2003 AMOUNT APR TERM DEFR MAT 1654. 9.248 34.0 7.0 8 1239. 1185. 1125. 0. 0. 0. 113. 108. 102. 34. 60. 65. 167. 167. 167. 1185. 1125. 1060. 0. 0. 0. 8623. 9.202 34.0 7.0 8 6450. 6164. 3855. 0. 0. 0. 584. 357. 327. 284, 311. 341. 848. 848. 848. 6146. 5855. 5514. 0. 0. 0. 1010. 10.194 34.0 7.0 9 781. 750. 715. 0. 0. 0. 78. 73. 71. 32. 35. 39. 110. 110. 110. 750. 715. 676. 0. 0. 0. 3267. 10.341 34.0 7.0 10 2562. 2461. 2348. 0. 0. 0. 261. 250. 238. 102. 113. 125. 363. 343. 363. 2461. 2348. 2223. 0. 0. 0. 1189. 10.133 34.0 7.0 10 921. 884. 843. 0. 0. 0. 92. 88. 84. 37. 4. 45. 129. 129. 129. 884. 843. 798. 0. 0. 9. 748. 0. 2005 2006 QTLY AMORT RATE 25. 260/$1, 000, 000 988. 910. 0. 0. 89. 81. 78. 84. 167. 167. 910. 824. 0. 0. 25. 163/$1, 000, 000 5141. 4732. 0. 0. 459. 420. 409. 448. 848. 848. 4732. 4284. 0. 0. 27. 286/$1, 000, 000 633. 585. 0. 0. 63. 38. 8. 33. 110. 110. 585. 533. 0. 0. 27.606/$1, 000, 000 2084. 1931. 0. 0. 210. 193. 153. 170. 363. 363. 1931. 1762. 0. 0. 27.154/$1, 000, 000 7%. 692. 0. 0. 74. 68. J5- 61. 129. 129. 692. 631. 0. 0. 2007 824. 0. 94. 167. 7H. 0. 4284. 0. 378. 490. 3794, 0. 533. 0. 32. 110. 475. 0. 1762. 175. 188. 363. 1574. Oo. 631. 0. 41. 129. 363. PAGE: 101 DATE: 21-May-83 TIME: 10:17 FILES: CHMGT.D1 GASGT.D2 VERSION: FIN. FORE. 2008 2009 730. 627. 0. 0. 64. 34. 103. 113. 167. 167. 627. 513. 0. 0. 3794. 3257. 0. 0. 331. 280. 537. 588. 848. 848. 3257. 2669. 0. 0. 475. 410. 0. 0. 4%. 39. 64. 71. 110. 110. 410. 339. 0. 0. 1574. 1365. 0. 0. 155. 132. 208. 231. 363. 363. 1365. 1135. 0. 0. 563. 488. 0. 0. 34. 4%. 75. 83. 129. 129. 488. 405. 0. 0. ult BURNS & MCDONNELL ENGINEERING COMPANY CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE F0035 9 1979 9 1986 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0040 9 1979 9 1986 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYNENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT FO045 10 1979 10 1986 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0050 11 1979 11 1986 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT FO055 11 1979 11 1986 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 2010 POWER SUPPLY PROGRAN AMOUNT APR 1654. 9. 313. 0. 43. 124. 167. 390. 0. 8623. 9. 2669. 0. 224. 644. 848. 2025. 0. 1010. 10. 339. 0. 32. 79. 110. 261. 0. 3287. 10. 1135. 0. 108. 255. 363. 880. 0. 1187. 10. 405. 9. 38. 91. 129. 314. 0. 248 202 194 341 133 TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) 2011 2012 2013 TERM DEFR MAT DATE 34.0 7.0 8 2013 370. 234. 105. 0. 0. 0. 31. 18. 3. 134. 149. 105. 167. 167. 110. 254. 105. 0. 0. 0. 0. 34.0 7.0 8 2013 2025. 1319. 347. 0. 0. 0. 162. 95. 24. 705. 773. 347. 848. 868. 570. 1319. 347. Ow 0. 0. 0. 34.0 7.0 9 2013 261. 174. 78. 0. 0. 0. 23. 14. 4. 87. 96. 78. 110. 110. 82. 174. 78. 0. 0. 0. 0. 34.0 7.0 10 2013 880. 597. 284. 0. 0. 0. 80. 50. 16. 283. 313. 284, 363. 363. 300. 597. 284. 0. 0. 0. 0. 34.0 7.0 10 2013 314. 213. 101. 0. 0. 0. 28. 17. 6. 101. 112. 101. 129. 129. 107. 213. 101. 0. 0. 0. 0. See — nd ~ 2014 2015 QTLY AMORT RATE 25. 260/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 25. 163/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 27..286/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 27..606/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 27.154/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. PAGE: 102 DATE: 21-May-83 TINE: 10:17 FILES: CHNGT.D1 GASGT.02 VERSION: FIN. FORE. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 103 ° POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:17 PROJECT: 82-113-4-000 FILES: CHNGT.01 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) VERSION: FIN. FORE. TABLE 10 LONG-TERM DEBT - EXISTING ($1, 000) CONTRACT YEAR 1983 1984 1985 1984 1987 1988 1989 1990 1991 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE F0060 2 1980 2 1987 7250._ 11.740 34.0 7.0 1 2014 30. 700/$1, 000, 000 BALANCE AT START OF YEAR 7250. 7250. 7250. 7250. 7250. 7213. 7167. 7116. 7059. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 851. 851. 851. 851. 850. 845. 839. 833. 826. PRINCIPAL PAYMENTS 0. 0. 0. 0. 37. 44. 51. 57. 64. TOTAL PAYMENTS 851. 851. 851. 851. 887. 8970. 890. 890. 8970. BALANCE AT END OF YEAR 7250. 7250. 7250. 7250. 7213. 7167. 7114. 7059. 6994. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. F0065 2 1980 2 1987 3447. 11.621 34.0 7.0 1 2014 30. 882/$1, 000, 000 BALANCE AT START OF YEAR 3447. 3447. 3447. 3447. 3447. 3429. 3408. 3384. 3357. ADVANCES DURING THE YEAR o. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 407. 47. 47. 407. 407. 404. 402. 399. 396. PRINCIPAL PAYMENTS 0. 0. 0. 0. 18. 21. 24, 27. 30. TOTAL PAYMENTS 407. 407. 407. 407. 424, 426. 426, 426. 426. BALANCE AT END OF YEAR 3447. 3447. 3447. 3447. 3429. 3408. 3384. 3357. 3327. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. Oo. F0070 3 1980 3 1987 650. 12.245 34.0 7.0 2 2014 31.839/$1, 000, 000 BALANCE AT START OF YEAR 650. 650. 650. 650. 650. 647. 644. 639. 635. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 80. 80. 60. 80. 79. 79. 79. 78. 77. PRINCIPAL PAYMENTS 0. 0. 0. 0. 3. 4. 4. 5. 5. TOTAL PAYMENTS 80. 80. 80. 80. 82. 83. 83. 83. 83. BALANCE AT END OF YEAR 650. 650. 650. 650. 647. 644. 639. 635. 629. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. F0075 4 1980 4 1987 1131. 11.8798 34.0 7.0 3 2014 31.055/$1, 000, 000 BALANCE AT START OF YEAR 1131. 1131. 1131. 1131. 1131. 1126. 1120. 1112. 1103. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 135. 135. 135. 135. 134. 134. 133. 132. 131. PRINCIPAL PAYMENTS 0. 0. 0. 0. 5. 7. 8. 9. 10. TOTAL PAYMENTS 135. 135. 135. 135. 139. 140. 140. 140. 140. BALANCE AT END OF YEAR 1131. 1131. 1131. 1131. 1126. 1120. 1112. 1103. 1094. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. o. FOO80 3 1980 3 1987 811. 10.369 34.0 7.0 4 2014 27.667/$%1,000,000 BALANCE AT START OF YEAR 811. 811. 811. 811. 811. 807. 801. 794. 786. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 84. 84. 84. 84. 84. 83. 83. 82. 81. PRINCIPAL PAYMENTS 0. 0. 0. 0. 4. 6. 7. 8. 9. TOTAL PAYMENTS 84. 84. 84. 84. 88. 90. 90. 90. 90. BALANCE AT END OF YEAR Sil. 811. 811. 811. 807. 801. 794. 786. 777. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 9. 0. 0. 0. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 104 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:17 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.02 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) VERSION: FIN. FORE. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE F0060 2 1980 2 1987 7250. 11.740 34.0 7.0 1 2014 30.700/$1, 000, 000 BALANCE AT START OF YEAR 6994. 6922. 6841. 6750. 6647. 6532. 6404. 6259. 6094. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 818. 809. 799. 788. 773. 761. 746. 728. 708. PRINCIPAL PAYMENTS 72. 81. 91. 102. 115. 129. 145. 142. 182. TOTAL PAYMENTS 890. 890. 8970. 890. 890. 890. 890. 890. 890. BALANCE AT END OF YEAR 6922. 6841. 6750. 6647. 6532. 6404. 6259. 6096. 5914. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. F006S 2 1980 2 1987 3447. 11.821 34.0 7.0 1 2014 30. 882/$1, 000, 000 BALANCE AT START OF YEAR 3327. 3293. 3255. 3212. 3164. 3110. 3049. 2980. 2903. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 392. 388. 383. 378. 372. 365. 357. 349. 339. PRINCIPAL PAYMENTS 34. 38. 43. 48. 34. 61. 68. 77. 84. TOTAL PAYMENTS 426. 426. 426. 426. 426. 426. 426, 426. 426. BALANCE AT END OF YEAR 3293. 3255. 3212. 3164. 3110. 3049. 2980. 2903. 2817. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. F0070 3 1980 3 1987 650. 12.245 34.0 7.0 2 2014 31.839/$1, 000, 000 BALANCE AT START OF YEAR 629. 623. 617. 609. 600. 591. 580. 367. 553. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 77. 76. 75. 74. 73. 72. 70. 69. 67. PRINCIPAL PAYMENTS 6. 7. 8. 9. 10. 11. 12. 14. 16. TOTAL PAYMENTS 83. 83. 83. 83. 83. 83. 83. 83. 83. BALANCE AT END OF YEAR 623. 617. 609. 600. 591. 380. 367. 553. 538. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. F0075 4 1980 4 1987 1131. 11.878 34.0 7.0 3 2014 31.055/$1, 000, 000 BALANCE AT START OF YEAR 1094. 1083. 1071. 1057. 1042. 1024. 1005. 983. 958. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYNENTS 130. 128. 127. 125. 123. 121. 119. 116. 113. PRINCIPAL PAYMENTS il. 12. 14. 15. 17. 19. 22. 25. 28. TOTAL PAYMENTS 140. 140. 140. 140. 140. 140. 140. 140. 140. BALANCE AT END OF YEAR 1083. 1071. 1057. 1042. 1024. 1005. 983. 958. 931. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. FOO80 3 1980 3 1987 B11. 10.369 34.0 7.0 4 2014 27.667/$1, 000, 000 BALANCE AT START OF YEAR 777. 768. 757. 746. 733. 719. 703. 685. 666. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 80. 79. 78. 77. 75. 74. 72. 70. 68. PRINCIPAL PAYMENTS 9. 11. 12. 13. 14. 16. 18. 19. 22. TOTAL PAYMENTS 90. 90. 90. 90. 70. 90. 90. 90. 90. BALANCE AT END OF YEAR 768. 757. 746. 733. 719. 703. 685. 646. 644, INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOrER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE F0060 2 1980 2 1987 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0065 2 1980 2 1987 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0070 3 1980 3 1987 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0075 4 1980 4 1987 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT Fo080 3 1980 3 1987 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) 2001 2002 2003 2004 2005 2006 AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE 7250. 11.740 34.0 7.0 1 2014 30. 700/$1, 000, 000 5914. 5709. 3479. 3221. 4931. 4606. 0. 0. 0. 0. 0. 0. 685. 640. 632. 600. 565. 525. 205. 230. 258. 290. 325. 365. 890. 890. 890. 890. 890. 890. 5709. 3479. 5221. 4931. 4606. 4241. 0. 0. 0. 0. 0. 0. 3447. (11.621 34.0 7.0 1 2014 30.882/$1, 000, 000 2817. 2720. 2611. 2489. 2351. 2197. 0. 0. ' 0. 0. 0. 0. 329. 317. 303. 288. 271. 252. 97. 109. 122. 138. 155. 174. 426. 426. 426. 426. 426. 426. 2720. 2611. 2489. 2351. 2197. 2023. 0. 0. 0. 0. 0. 0. 650. 12.245 34.0 7.0 2 2014 31.839/$1, 000, 000 338. 320. 300. 477. 452. 423. 0. 0. 0. 0. 0. 0. 65. 63. 60. 37. 34. 30. 18. 20. 23. 25. 29. 32. 83. 83. 83. 83. 83. 83. 520. 500. 477. 2. 423. 391. 0. 0. 0. 0. 0. 0. 1131. 11.898 34.0 7.0 3 2014 31.055/$1, 000, 000 931. 900. 865. 825. 781. 731. 0. 0. 0. 0. 0. 0. 109. 104. 101. 96. 91. 85. 31. 35. 39. 44, 50. 34. 140. 140. 140. 140. 140. 140. 900. 845. 825. 781. 731. 675. 0. 0. 0. 0. 0. 0. 811. 10.369 34.0 7.0 4 2014 27..667/$1, 000, 000 644. 620. 394. 365. 332. 496. 0. 0. 0. 0. 0. 0. 66. 63. 60. 37. 34. 50. 24. 26. 29. 32. 36. x. 90. 90. 90. 90. 90. 90. 620. 594. 365. 532. 496. 57. 0. 0. 0. 0. 0. 0. 2007 PAGE: 105 DATE: 21-May-83 TIME: 10:17 FILES: CHMGT.D1 GASGT.D2 VERSION: FIN. FORE. 2008 2009 3830. 3370. 0. 0. 430. 373. 460. 517. 890. 890. 3370. 2853. 0. 0. 1828. 1609. 0. 0. 207. 180. 219. 246. 426. 426. 1609. 1362. 0. 0. 354. 313. 0. 0. 42. 36. 41. 7. 83. 83. 313. 267. 0. 0. 613. 342. 0. 0. 70. 61. 71. 79. 140. 140. 342. 462. 0. 0. 412. 364. 0. 0. 41. 36. 49. 54. 90. 90. 364. 309. 0. 0. CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE F0060 2 1980 2 1987 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT FO06S 2 1980 2 1987 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0070 3 1980 3 1987 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0075 4 1980 4 1987 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT FOO8O 3 1980 3S 1987 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 7250. 1131. 811. BURNS & MCDONNELL ENGINEERING COMPANY 2010 AMOUNT POWER SUPPLY PROGRAN APR 11. Si. 140. 373. 0. 10. 309. 0. 30. 60. 90. 250. 0. 7% 821 245 369 TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) 2011 2012 2013 TERM DEFR NAT DATE 34.0 7.0 1 2014 2273. 1621. 890. 0. 0. 0. 239. 159. 69. 651. 731. 821. 8970. 890. 890. 1621. 890. 69. 0. 0. 0. 34.0 7.0 1 2014 1086. 773. 435. 0. 0. 0. 115. 76. 33. 311. 349. 3972. 426. 426. 426. 773. 425. 33. 0. 0. 0. 34.0 7.0 2 2014 214. 155. 88. 0. 0. 0. 24. 16. 7. 59. 67. 73. 83. 83. 83. 155. 88. 13. 0. 0. 0. 34.0 7.0 3 2014 373. 273. 160. 0. 0. 0. 4X. 28. 13. 100. 113. 127. 140. 140. 140. 273. 160. 33. 0. 0. 0. 34.0 7.0 4 2014 250. 183. 110. 0. 0. 0. 23. 16. 8. 64. 74. 81. 90. 90. 90. 183. 110. 28. 0. 0. 0. wee ew 2014 2015 QTLY AMORT RATE 30.700/$1, 000, 000 69. 0. 0. 0. 2. 0. 69. 0. 71. 0. 0. 0. 0. 0. 30. 882/$1, 000, 000 33. 0. 0. 0. 1. 0. 33. 0. 34. 0. 0. 0. 0. 0. 31.839/$1, 000, 000 13. 0. 0. 0. 0. 0. 13. 0. 13. 0. 0. 0. 0. 0. 31.055/$1, 000, 000 33. 0. 0. 0. 1. 0. 33. 0. 34. 0. 0. 0. 0. 0. 27.667/$1, 000, 000 28. 0. 0. 0. 1. 0. 28. 0. 29. 0. 0. 0. 0. 0. PAGE: 106 DATE: 21-May-83 TIME: 10:17 FILES: CHMGT.01 GASGT.D2 VERSION: FIN. FORE. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE Foo8S 6 1980 & 1987 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F00?0 1980 7 1987 BALANCE AT start OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT FO095 9 1980 9 1987 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0100 « 10 1980 10 1987 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0105 10 1980 10 1987 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 1983 AMOUNT APR 1024. 9.769 1 —_ -_ 100. 1024. 0. 10.075 _ 559. 0. 359. 35347. 0. 11.098 1041. 0. 116. 0. 116. 1041. 0. 3547. 1041. 1503. 11.661 = 173: 173. 1503. 0. 6325. 12.122 6325. 0. 767. 0. 767. 6325. 0. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) 1984 1985 1986 TERM DEFR MAT DATE 34.0 7.0 5 2014 1024. 1024. 1024. 0. 0. 0. 100. 100. a0. 0. 0. 100. 100. 100. 1024. 1024. 1024. 0. 0. 0. 34.0 7.0 6 2014 3547. 5347. 3547. 0. 0. 0. 359. 359. 559. 0. 0. 9. 359. 559. 359. 5347. 5547. 3347. 0. 0. 0. 34.0 7.0 8 2014 1041. 1041. 1041. 0. 0. 0. 1146. 1164. 116. 0. 0. 0. 116. 116. 116. 1041. 1041. 1041. 0. 0. 0. 34.0 7.0 9 2014 = _ =. 173: 175. 175. 0. 0. 73. 175. 175. 1503. 1503. 1503. 0. 0. 0. 34.0 7.0 9 2014 6325. 6325. 6325. 0. 0. 0. 767. 767. 767. 0. 0. 0. 767. 767. 767. 6325. 6325. 6325. 0. 0. 0. 1987 1988 QTLY AMORT RATE 26. 369/$1, 000, 000 1024. 1019. 0. 0. a om 105. 108. 1019. 1010. 0. 0. 27.029/%1, 000, 000 3547. 3526. 0. 0. 538. 355. 21. s. 579. 600. 3526. 3481. 0. 0. 29.268/$1, 000, 000 1041. 1039. 0. 0. 115. 115. 2. 7. 118. 122. 1039. 1032. 0. 0. 30. 523/$1, 000, 000 _ 7) @ 173: vW7 194. 1501. 1492. 0. 0. 31.561/$1, 000, 000 6325. 6317. 0. 0. 766. 764. 8. 34. 775. 798. 6317. 6282. 0. 0. 1989 DATE: 21-May-83 TIME: 10:17 FILES: CHMGT.D1 GASGT.D2 VERSION: FIN. FORE. 1990 1991 1001. 990. 0. 0. 97. 96. 11. 12. 108. 108. 990. 978. 0. 0. 3432. 3377. 0. 0. 345. 340. 34. 60. 600. 600. 3377. 5317. 0. 0. 1024. 1016. 0. 0. 113. 112. 9. 10. 122. 122. 1016. 1006. 0. 0. 1482. 1471. 0. 0. 172. 171. 11. 13. 184. 184. 1471. 1458. 0. 0. 6244. 6200. 0. 0. 7355. 749. 44, 4. 798. 798. 6200. 6151. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 108 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TINE: 10:17 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) VERSION: FIN. FORE. TABLE 10 LONG-TERM DEBT - EXISTING ($1, 000) CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE FOo8S 6 1980 6 1987 1024. 9.769 34.0 7.0 3 2014 26.369/$1, 000, 000 BALANCE AT START OF YEAR 978. 966. 951. 936. 919. 900. 879. 856. 830. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 95. 94. 92. 91. 89. 87. 85. 83. 80. PRINCIPAL PAYMENTS 13. 14. 16. 17. 19. 21. 23. 2. 28. TOTAL PAYMENTS 108. 108. 108. 108. 108. 108. 108. 108. 108. BALANCE AT END OF YEAR 966. 951. 936. 919. 900. 879. 856. 830. 802. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. FO0090 7 1980 7 1987 5547. 10.075 34.0 7.0 6 2014 27.029/$1, 000, 000 BALANCE AT START OF YEAR 3317. 3251. 5177. 5096. 5007. 4908. 778. 4678. 4544, ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 533. 526. 519. 510. 301. 490. 479. 466. 452. PRINCIPAL PAYMENTS 66. 73. 81. 90. 99. 109. 121. 133. 147. TOTAL PAYMENTS 600. 600. 600. 600. 600. 600. 600. 600. 600. BALANCE AT END OF YEAR 5251. 5177. 5096. 5007. 4908. 4798. 4678. 4544. 4397. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. FO095 9 1980 9 1987 1041. 11.098 34.0 7.0 8 2014 29.268/$1, 000, 000 BALANCE AT START OF YEAR 1006. 996. 984. 970. 956. 939. 921. 900. 877. ADVANCES DURING THE YEAR 0. 0. 0. 0. o. 0. 0. 0. 0. INTEREST PAYMENTS 111. 110. 109. 107. 105. 103. 101. 99. 96. PRINCIPAL PAYMENTS 11. 12. 13. 15. 16. 18. 21. 23. 26. TOTAL PAYMENTS 122. 122. 122. 122. 122. 122. 122. 122. 122. BALANCE AT END OF YEAR 996. 984. 970. 956. 939. 921. 900. 877. 852. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. F0100 10 1980 10 1987 1503. 11.661 34.0 7.0 9 2014 30.523/$1, 000, 000 BALANCE AT START OF YEAR 1458. 1444. 1429. 1411. 1391. 1369. 1344. 1316. 1284, ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 169. 168. 166. 164. 161. 159. 156. 152. 148. PRINCIPAL PAYMENTS 14, 16. 18. 20. 22. 25. 28. 31. 35. TOTAL PAYMENTS 184. 184. 184. 184, 184. 184. 184. 184. 184. BALANCE AT END OF YEAR 1444. 1429. 1411. 1391. 1369. 1344. 1316. 1284. 1249. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. F0105 10 1980 10 1987 6325. 12.122 34.0 7.0 9 2014 31.561/$1, 000, 000 BALANCE AT START OF YEAR 6151. 6096. 6034. 5963. 5884. 5795. 3695. 5581. 5454. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 743. 736. 728. 719. 709. 698. 685. 671. 655. PRINCIPAL PAYMENTS 55. 62. 70. 79. 89. 100. 113. 128. 144. TOTAL PAYMENTS 798. 798. 798. 798. 798. 798. 798. 798. 798. BALANCE AT END OF YEAR 6096. 6034. 5963. 5884. 5795. 3695. 5581. 5454. 5310. INTEREST CHARGEO TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. “ve onl uw Ht en beac ee ——— ee beewene meee Sees 5 microns - CHUGACH, PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) CONTRACT YEAR LOAN © EXE DATE BAS DATE FoosS 6 1980 & 1987 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0090 1980 7 1987 BALANCE AT start OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT FOO9S 9 1980 9 1987 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT FO100 10 1980 10 1987 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0105 10 1980 10 1987 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM HOMER & MATANUSKA ELEC. ASSOCIATIONS 2001 AMOUNT = APR 1024. 9.769 802. 0. 77. 31. 108. 772. 0. 10.075 4397. 0. 437. 163. 600. 4234. 0. 1041. 11.098 a 9 9: 28. 122. 823. 0. 11.661 1249. 0. 144, 40. 184. 1210. 0. 3347. 1503. 12.122 3310. 0. 637. 162. 798. 5148. 0. 6325. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) 2002 2003 2004 TERM DEFR MAT DATE 34.0 7.0 3 2014 772. 738. 701. 0. 0. 0. 74, 71. 67. 34. 37. 41. 108. 108. 108. 738. 701. 660. 0. 0. 0. 34.0 7.0 6 2014 4234. 4055. 3856. 0. 1 0. 0. 420. 41. 380. 180. 199. 219. 600. 600. 600. 455. 3856. 3637. 0. 0. 0. 34.0 7.0 8 2014 823. 792. 756. 0. 0. 0. 0. 84. 82. 32. 35. 4%. 122. 122. 122. 792. 736. 716. 0. 0. 0. 34.0 7.0 9 2014 1210. 1165. 1116. 0. 0. 0. 139. 134. 128. 44. 30. 36. 184. 184. 184. 1165. 1116. 1060. 0. 0. 0. 34.0 7.0 9 2014 3148. 4966. 4760. 0. 0. 0. 614. 393. 567. 183. 206. 232. 798. 798. 798. 4964. 4760. 4528. 0. 0. 0. 2005 2006 QTLY AMORT RATE 26. 369/$1, 000, 000 660. 614. 0. 0. 63. 38. 5. 50. 108. 108. 614. 565. 0. 0. 27.029/%1, 000, 000 3637. 3394. 0. 0. 357. 332. 242. 268. 600. 600. 3394. 3127. 0. 0. 29..268/$1, 000, 000 716. 672. 0. 0. 78. 73. 44. 49. 122. 122. 672. 623. 0. 0. 30. 523/$1, 000, 000 _ “~ 121. 113 63. 70. 184. 184. 997. 927. 0. 0. 31.561/$1, 000, 000 528. 4267. 0. 0. 337. 304. 261. 294. 798. 798. 4267. 3973. 0. 0. 2007 3641. DATE: 21-Hay-83 TIME: 10:17 FILES: CHMGT.D1 GASGT.D2 VERSION: FIN. FORE. 2008 2009 510. 4499. 0. 0. 48. 42. 60. 64. 108. 108. 449. 383. 0. 0. 2831. 2505. 0. 0. 273. 239. 327. 361. 600. 600. 2505. 2144. 0. 0. 348. 507. 0. 0. 61. 53. 61. 68. 122. 122. 507. 438. 0. 0. 848. 760. 0. 0. 95. 84. 88. 99. 184. 184. 760. 661. 0. 0. 3641. 3268. 0. 0. 425. 377. 374. 421. 798. 798. 3268. 2847. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%Z, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE Fooss 6 1980 & 1987 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT FO090 7 1980 7 1987 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT FOO95 9 1980 9 1987 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0100 10 1980 10 1987 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT FO105 10 1980 10 1987 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 2010 AMOUNT APR 1024. 9.769 383. 0. 35. 73. 108. 310. 0. 5547. 10.075 2144. 0. 201. 398. 600. 1745. 0. 1041. 11.098 438. 0. 44. 76. 122. 362. 0. 1503. 11.661 661. 0. 72. 111. 184. 550. 0. 6325. 12.122 2847. 0. 324. 474. 798. 2372. 0. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) 2011 2012 2013 TERM DEFR MAT DATE 34.0 7.0 5 2014 310. 229. 140. 0. 0. 0. 27. 19. 10. 81. 89. 98. 108. 108. 108. 229. 140. 42. 0. 0. 0. 34.0 7.0 6 2014 1745. 1305. 819. 0. 0. 0. 160. 114. 63. 440. 486. 537. Ss, Bigs oat 0. 0. 0. 34.0 7.0 8 2014 362. 277. 182. 0. 0. 0. 37. 27. 16. 85. 95. 106. 122. 122. 122. 277. 182. 76. 0. 0. 0. 34.0 7.0 9 2014 550. 425. 285. 0. 0. 0. 37. 44. 27. 125. 140. 157. 184. 184. 184, 425. 285. 128. 0. 0. 0. 34.0 7.0 9 2014 2372. 1837. 1235. 0. 0. 0. 264. 196. 120. 535. 602. 679. 778. 798. 798. 1837. 1235. 556. 0. 0. 0. ed — ee - 2014 2015 QTLY AMORT RATE 26.369/$1, 000, 000 42. 0. 0. 0. 1. 0. 42. 0. 44. 0. 0. 0. 0. 0. 27..029/$1, 000, 000 262. 0. 0. 0. 11. 0. 282. 0. 292. 0. 0. 0. 0. 0. 29.268/$1, 000, 000 76. 0. 0. 0. 4. 0. 76. 0. 80. 0. 0. 0. 0. 0. 30.523/$1, 000, 000 128. 0. 0. 0. 7. 0. 128. 0. 136. 0. 0. 0. 0. 0. 31.561/$1, 000, 000 556. 0. 0. 0. 34. 0. 556. 0. 590. 0. 0. 0. 0. 0. PAGE: 110 DATE: 21-May-83 TINE: 10:17 FILES: CHNGT.D1 GASGT.D2 VERSION: FIN. FORE. BURNS & MCDONNELL ENGINEERING COMPANY CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE F0110 12 1980 12 1987 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT Fo115 1 1981 1 1988 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0120 , 4 1981 4 1988 BALANCE AT START OF YEAR ADVANCES QURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT Fo125 3 1981 5 1988 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0130 6 1981 & 1988 BALANCE. AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL, PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 0. 812. 0. 812. 6092. 0. 1591. 13. 1591. 0. 208. 0. 208. 1591. 0. 2533. 12. 2533. 0. 319. 0. 319. 2533. 0. POWER SUPPLY PROGRAM 076 612 TABLE 10 LONG-TERM DEBT ~ EXISTING ($1,000) 1984 1985 1986 TERN DEFR MAT DATE 34.0 7.0 11 2014 3302. 3302. 3302. 0. 0. 0. Ail. 411. 4i1. 0. 0. 0. 4il. 411. 411. 3302. 3302. 3302. 0. 0. 0. 34.0 7.0 12 2014 5944. 3944. 3944. 0. '_ 0. 0. 711. 7i1. 711. 0. 0. 0. 711. 711. 711. 59744. 5944. 3944. 0. 0. 0. 34.0 7.0 3 2015 6092. 6092. 60972. 0. 0. 0. 812. 812. 812. 0. 0. 0. 812. 812. 812. 6092. 6092. 6092. 0. 0. 0. 34.0 7.0 4 2015 1591. 1591. 1591. 0. 0. 0. 208. 208. 208. 0. 0. 0. 208. 208. 208. 1591. 1591. 1591. 0. 0. 0. 34.0 7.0 3 2015 2533. 2533. 2533. 0. 0. 0. 319. 319. 319. 0. 0. 0. 319. 319. 319. 2532. 2533. 2533. 0. 9%. 0. 1987 1988 QTLY AMORT RATE 32. 323/$1, 000, 000 3302. 3301. 0. 0. 4i1. 410. 1. 16. 413. 427. 3301. 3284. 0. 0. 31.213/$1, 000, 000 5944. 5944. 0. 0. 711. 710. 0. 32. 711. 742. 5944. 5912. 0. 0. 34. 316/$1, 000, 000 6092. 6092. 0. 0. 812. 811. 0. 19. 812. 830. 6092. 6073. 0. 0. 33.736/$1, 000, 000 1591. 1591. 0. 0. 208. 208. 0. 3. 208. 212. 1591. 1586. 0. 0. 32. 673/$1, 000, 000 2533. 2533. 0. 0. 319. 319. 0. 7. 319. 326. 2533. 2526. 0. 0. 1989 2513. PAGE: 111 DATE: 21-May-83 TIME: 10:17 FILES: CHNGT.D1 GASGT. D2 VERSION: FIN. FORE. 1990 1991 3266. 3244. 0. 0. 6. 403. 2i. 24. 427. 427. 3244. 3221. 0. 0. 3876. 3835. 0. 0. 701. 6964. 41. 4%. 742. 742. 5835. 5789. 0. 0. 6045. 6013. 0. 0. 804. 800. 32. 37. 836. 834. 6013. 5976. 0. 0. 1579. 1570. 0. 0. 204. 205. 9. 10. 215. 215. 1570. 1560. 0. 0. 2513. 2498. 0. 0. 316. 314. 15. 17. 331. 331. 2498. 2481. 0. 0. Pea =a BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 112 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:17 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT. D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z%, 20YR) VERSION: FIN. FORE. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE FO110 12 1980 12 1987 3302. 12.458 34.0 7.0 11 2014 32.323/$1, 000, 000 BALANCE AT START OF YEAR 3221. 3194. 3163. 3127. 3090. 3046. 2796. 2940. 2877. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 400. 396. 393. 388. 383. 377. 371. 363. 355. PRINCIPAL PAYMENTS 27. 30. 34. 39. 44, 30. 34. 64. 72. TOTAL PAYMENTS 427. 427. 427. 427. 427. 427. 427. 427. 427. BALANCE AT END OF YEAR 3194. 3163. 3129. 3090. 3046. 2996. 294. 2877. 2805. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. FO115 1 1981 1 1988 5944. (11.968 34.0 7.0 12 2014 31.213/$1, 000, 000 BALANCE AT START OF YEAR 5789. 5738. 3680. 3614. 5341. 5459. 3366. 5261. 5143. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 691. 684. 677. 669. 640. 649. 638. 624. 610. PRINCIPAL PAYMENTS 52. 58. 65. 730 83. 93. 105. 118. 132. TOTAL PAYMENTS 742. 742. 742. 742. 742. 742. 742. 742. 742. BALANCE AT END OF YEAR 5738. 5680. 3614. 3541. 3459. 3366. 3261. 3143. 5011. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. F0120 4 1981 4 1988 6092. 13.328 34.0 7.0 3 2015 34.316/$1, 000, 000 BALANCE AT START OF YEAR 5976. 5934. 3887. 5832. 5770. 5700. 3619. 5528. 3423. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 794. 789. 782. 774. 766. 736. 744. 732. 717. PRINCIPAL PAYMENTS 42. 48. 34. 62. 71. 80. 92. 105. 119. TOTAL PAYMENTS 836. 834. 836. 836. 836. 836. 834. 836. 834. BALANCE AT END OF YEAR 5934. 5887. 5832. 5770. 5700. 5619. 3528. 3423. 5304. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. F0125 3 1981 5 1988 1591. 13.076 34.0 7.0 4 2015 33.736/$1, 000, 000 BALANCE AT START OF YEAR 1560. 1549. 1536. 1522. 1505. 1484. 1465. 1441. 1413. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 203. 202. 200. 198. 196. 193. 190. 187. 183. PRINCIPAL PAYMENTS il. 13. 15. 17. 19. 21. 24. 28. 31. TOTAL PAYMENTS 215. 215. 215. 215. 215. 215. 215. 215. 215. BALANCE AT END OF YEAR 1549. 1536. 1522. 1505. 1486. 1445. 1441. 1413. 1382. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. F0130 6 1981 6& 1988 2533. 12.612 34.0 7.0 3 2015 32. 673/$1, 000, 000 BALANCE AT START OF YEAR 2481. 2462. 2441. 2416. 2389. 2358. 2322. 2282. 2237. ADVANCES DURING THE YEAR 0. o. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 312. 310. 307. 303. 300. 296. 291. 286. 280. PRINCIPAL PAYMENTS 19. 21. 24. 28. 31. 35. x. 45. 51. TOTAL PAYMENTS 331. 331. 331. 331. 331. 331. 331. 331. 331. BALANCE AT END OF YEAR j 2462. 2441. 2414, 2389. 2358. 2322. 2282. 2237. 21864. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOPER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) TABLE 10 LONG-TERM DEBT - EXISTING ($1, 000) CONTRACT YEAR 2001 2002 2003 2004 2005 2006 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE F0110 12 1980 12 1987 3302. 12.458 34.0 7.0 11 2014 32..323/$1, 000, 000 BALANCE AT START OF YEAR 2805. 2724. 2632. 2528. 2411. 2278. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 346. 335. 323. 310. 294. 277. PRINCIPAL PAYMENTS 81. 92. 104. 117. 133. 150. TOTAL PAYMENTS 427. 427. 427. 427. 427. 427. BALANCE AT END OF YEAR 2724. 2632. 2528. 2411. 2278. 2129. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. Fo115 1 1981 1 1988 5944. 11.968 34.0 7.0 12 2014 31.213/$1, 000, 000 BALANCE AT START OF YEAR 5011. 4862. 4695. 4506. 4294. 4055. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 593. 575. 334. 330. 503. 474. PRINCIPAL PAYMENTS 149. 168. 189. 212. 239. 269. TOTAL PAYMENTS 742. 742. 742. 742. 742. 742. BALANCE AT END OF YEAR 4862. 4695. 4506. 42974. 4053. 3787. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. F0120 4 1981 4 1988 6092. 13.328 34.0 7.0 3 2015 34.316/$1, 000, 000 BALANCE AT START OF YEAR 5304. 5168. 5013. 4836. 4635. 4405. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 700. 681. 660. 635. 607. 574. PRINCIPAL PAYMENTS 136. 155. 177. 201. 230. 262. TOTAL PAYMENTS 8364. 834. 836. 836. 836. 834. BALANCE AT END OF YEAR 3168. 5013. 4836. 4635. 4405. 4144. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. Fo125 3 1981 3 1988 1591. 13.076 34.0 7.0 4 2015 33.734/$1, 000, 000 BALANCE AT START OF YEAR 1382. 1344. 1305. 1259. 1207. 1147. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 179. 174, 168. 142. 155. 147. PRINCIPAL PAYMENTS 36. 41. 46. 33. 60. 68. TOTAL PAYMENTS 215. 215. 215. 215. 215. 215. BALANCE AT END OF YEAR 1344. 1305. 1259. 1207. 1147. 1079. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. F0130 & 1981 & 1988 2533. 12.612 34.0 7.0 3 2015 32. 673/$1, 000, 000 BALANCE AT START OF YEAR 21864. 2128. 2062. 1988. 1903. 1808. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST RAYMENTS 273. 265. 257. 247. 236. 223. PRINCIPAL PAYMENTS 58. 46. 74. 84. %. 108. TOTAL PAYMENTS 331. 331. 331. 331. 331. 331. BALANCE AT END OF YEAR 2128. 2062. 1988. 1903. 1808. 1700. INTEREST CHARGED TO CONSTR-CREDIT 0. 9. 0. 0. 0. 0. 2007 742. 4144. 1700. 122. 331. 1578. 0. PAGE: 113 DATE: 21-May-83 TIME: 10:17 FILES: CHMGT.D1 GASGT.D2 VERSION: FIN. FORE. 2008 = 2009 1959. 1768. 0. 0. 235. 210. 192. 217. 427. 427. 1768. 1551. 0. 0. 3485. 3145. 0. 0. 42. 340. 340. 382. 742. 742. 3145. 2762. 0. 0. 3845. 3505. 0. 0. 496. 448. 340. 388. 834. 836. 3505. 3117. 0. 0. 1002. 914, 0. 0. 127. 115. 88. 100. 215. 215. 914. 814. 0. o. 1578. 1439. 0. 0. 193. 174. 138. 157. 331. 331. 1439. 1283. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE F0110 12 1980 12 1987 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT Fo115 1 1981 1 1988 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0120 4 1981 4 1988 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0125 3 1981 5 1988 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0130 6 1981 & 1988 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 2010 AMOUNT APR 3302. 12.458 1551. 0. 182. 245. 427. 1306. 0. 5944. 11.968 2762. 0. 312. 430. 742. 2332. 0. 6092. 13.328 3117. 0. 394. 442. 834. 2675. 0. 1591. 13.076 814. 0. 101. 114, 215. 700. 0. 2533. 12.612 1283. 0. 154. 177. 331. 1105. 0. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) 2011 2012 2013 TERM DEFR MAT DATE 34.0 7.0 11 2014 1306. 1029. 716. 0. 0. 9. 150. 114. 73. 277. 313. 354. 427. 427. 427. 1029. 716. 363. 0. 0. 0. 34.0 7.0 12 2014 2332. 1848. 1303. 0. 0. 0. 258. 197. 129. 434. 345. 613. 742. 742. 742. 1848. 1303. 690. 0. 0. 0. 34.0 7.0 3 2015 2675. 2170. 1595. 0. 0. 0. 332. 261. 181. 504. 575. 655. 834. 834. 836. 2170. 1595. 940. 0. 0. 0. 34.0 7.0 4 2015 700. 571. 424, 0. 0. 0. 85. 68. 47. 129. 147. 167. 215. 215. 215. 571. 424. 256. 0. 0. 0. 34.0 7.0 3 2015 1105. 904, 677. 0. 0. 0. 120. 104. 73. 201. 227. 258. 331. 331. 331. 904. 677. 419. 9. 0. 0. 2014 2015 QTLY ANORT RATE 32. 323/$1, 000, 000 363. 0. 0. 0. 27. 0. 363. 0. 390. 0. 0. 0. 0. 0. 31.213/$1, 000, 000 690. A 0. 0. 32. 0. 690. 0. 742. 0. 0. 0. 0. 0. 34.316/$1, 000, 000 940. 193. 0. 0. 89. 6. 747. 193. 834. 199. 193. 0. 0. 0. 33. 736/$1, 000, 000 256. 64. 0. 0. 24. 3. 190. 66. 215. 69. 66. 0. 0. 0. 32.673/$1, 000, 000 419. 128. 0. 0. 37. é. 292. 128. 331. 133. 128. 0. 0. 0. PAGE: 114 DATE: 21-May-83 TIME: 10:17 FILES: CHMGT.D1 GASGT.D2 VERSION: FIN. FORE. BURNS & MCDONNELL ENGINEERING COMPANY CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE F0135 8 1981 8 1988 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0140 9 1981 9 1988 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0145 9 1981 9 1988 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0150 10 1981 10 1988 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0155 11 1981 11 1988 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT POWER SUPPLY PROGRAM TABLE 10 LONG-TERM DEBT - EXISTING ($1, 000) 1983 1984 1986 AMOUNT APR TERM DEFR MAT DATE 1450. 14.044 34.0 7 2015 1450. 1450. 1450. 1450. 0. 0. 0. 204. 204. 204. 0. 0. 0. 204. 204. 204. 1450. 1450. 1450. 1450. 0. 0. 0. 2558. 14. 34.0 2015 2558. 2558. 2558. 2558. 372. 372. 372. 0. 0. 0. 372. 372. 372. 2558. 2558. 2558. 2558. 0. 0. 0. 11312. 14.545 34.0 7.0 2015 41312. 11312. 11312. 11312. 0. 0. 0. 0. 1643. 1643. 1645. 1643. 1645. 1645. 1645. 1645. 11312. 11312. 11312. 11312. 0. 0. 0. 6000. 15. 34.0 2015 6000. “4000. "6009. 8000. 908. 908. 908. 0. 0. 0. 908. 908. 908. 0. 0. 0. 2307. 13. 34.0 2015 2307. 2307. 2307. 2307. 0. 0. 0. 301. 301. 301. 0. 0. 0. 301. 201. 301. 2307. 2307. 2307. 2307. e Ve \ Vo 1987 1988 QTLY AMORT RATE. 35.976/$1, 000, 000 1450. 1450. 0. 0. 204. 204. 0. 2. 204. 206. 1450. 1448. 0. 0. 37. 147/$%1, 000, 000 2558. 2558. 0. 0. 372. 372. 0. 3. 372. 375. 2558. 2555. 0. 0. 37. 147/$1, 000, 000 11312. 11312. 0. 0. 1645. 1645. 0. 12. 1645. 1657. 11312. 11300. 0. 0. 38.519/$1, 000, 000 6000. 6000. 0. 0. 908. 907. 0. 4. 908. 912. 6000. 5996. 0. 0. 33. 685/$1, 000, 000 2307. 2307. 0. 0. 301. 301. 0. 2. 301. 303. 2307. 2305. 0. 0. 1989 3996. 0. 18. 924. 5977. 0. 0. 10. 311. 2295. 0. PAGE: 115 DATE: 21-May-83 TIME: 10:17 FILES: CHNGT.D1 GASGT.D2 VERSION: FIN. FORE. 1990 1991 1442. 1436. 0. 0. 202. 201. 6. 7. 209. 209. 1436. 1428. 0. 0. 2546. 2534. 0. 0. 370. 368. 10. 12. 380. 380. 2536. 2524. 0. Oo. 11260. 11215. 0. 0. 1635. 1628. s. 52. 1681. 1681. 11215. 11162. 0. 0. 5977. 5956. 0. 0. 903. 900. 21. 25. 924. 924. 5956. 5931. 0. 0. 2295. 2263. 0. 0. 299. 297. 12. 13. 311. 311. 2283. 2270. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 116 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TINE: 10:17 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT. D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) VERSION: FIN. FORE. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY ANORT RATE. F0135 8 1981 8 1988 1450. 14.044 34.0 7.0 7 2015 35..976/$1, 000, 000 BALANCE AT START OF YEAR 1428. 1420. 1410. 1399. 1386. 1371. 1354, 1335. 1312. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 200. 199. 197. 196. 194, 192. 189. 186. 183. PRINCIPAL PAYMENTS 9. 10. 11. 13. 15. 17. 19. 22. 26. TOTAL PAYMENTS 209. 209. 209. 209. 209. 209. 209. 209. 209. BALANCE AT END OF YEAR 1420. 1410. 1399. 1384. 1371. 1354. 1335. 1312. 1287. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. F0140 9 1981 9 1988 2558. 14.545 34.0 7.0 8 2015 37.147/$1, 000, 000 BALANCE AT START OF YEAR 2524. 2510. 2495. 2476. 2455. 2431. 2403. 2371. 2334. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 366. 364. 362. 359. 356. 352. 348. 343. 337. PRINCIPAL PAYMENTS 14. 16. 18. 21. 24. 28. 32. 37. 43. TOTAL PAYMENTS 380. 380. 380. 380. 380. 380. 380. 380. 380. BALANCE AT END OF YEAR 2510. 2495. 2476. 2455. 2431. 2403. 2371. 2334. 22971. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. F0145 9 1981 9 1988 11312. 14.545 34.0 7.0 8 2015 37. 147/$1, 000, 000 BALANCE AT START OF YEAR 11162. 11102. 11032. 10951. 10859. 10751. 10628. 10485. 10321. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 1620. 1611. 1600. 1588. 1574. 1557. 1538. 1516. 1491. PRINCIPAL PAYMENTS 60. 70. 80. 93. 107. 124, 143. 164. 190. TOTAL PAYMENTS 1681. 1681. 1681. 1681. 1681. 1681. 1681. 1681. 1681. BALANCE AT END OF YEAR 11102. 11032. 10951. 10859. 10751. 10628. 10485. 10321. 10131. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. FO150 10 1981 10 1988 6000. 15.128 34.0 7.0 9 2015 38.519/$1, 000, 000 BALANCE AT START OF YEAR 5931. 5902. 5869. 5830. 5785. 5733. 5672. 34602. 3520. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 896. 891. 886. 879. 872. 844. 854. 843. 830. PRINCIPAL PAYMENTS 29. 33. 39. 5. 52. 61. 70. 82. 95. TOTAL PAYMENTS 924. 924. 924. 924. 924. 924. 924. 924. 924. BALANCE AT END OF YEAR 5902. 5869. 5830. 3785. 5733. 5672. 3602. 5520. 3426. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. FO155 11 (1981 11 1988 2307. 13.054 34.0 7.0 10 2015 33. 485/$1, 000, 000 BALANCE AT START OF YEAR 2270. 2254. 2237. 2217. 2195. 2169. 21%. 2107. 2069. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 296. 293. 271. 288. 285. 282. 278. 273. 268. PRINCIPAL PAYMENTS 15. 17. 20. 22. 26. 29. 33. 38. 43. TOTAL PAYMENTS 311. 311. 311. 311. 311. 311. 311. 311. 311. BALANCE AT END OF YEAR 2254. 2237. 2217. 2195. 2169. 2140. 2107. 2069. 2027. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE F0135 8 1981 8 1988 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT FO140 1981 9 1988 BALANCE AT stat OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGEO TO CONSTR-CREDIT F0145 9 1981 9 1988 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0150 10 1981 10 1988 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT FO155 11 1981 11 1988 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT TABLE 10 LONG-TERM DEBT - EXISTING ($1, 000) 2001 2002 2003 2004 2005 2006 AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE 1450. 14.044 34.0 7.0 7 2015 35. 976/$1, 000, 000 1287. 1257. 1224. 1185. 1140. 1089. 0. 0. 0. 0. 0. 0. 179. 175. 170. 164. 158. 150. 29. 34. 39. 45. 51. 59. 209. 209. 209. 209. 209. 209. 1257. 1224. 1185. 1140. 1089. 1030. 0. 0. 0. 0. 0. 0. 2558. 14.545 34.0 7.0 8 2015 37. 147/61, 000, 000 aa%}. _ _ = -_ _ 331. 323. 314. 304. 272. 279. 49. 57. 66. 76. 88. 101. 380. 380. 380. 380. 380. 380. 2241. 2184. 2119. 2043. 1955. 1854. 0. 0. 0. 0. 0. ° 11312. 14.545 34.0 7.0 8 2015 37. 147/$1, 000, 000 aa. —_ ™. vm = _ 1462. 1428. 1390. 1345. 1293. 1234 219. 292. 271. 334. 388. 447. 1681. 1681. 1681. 1681. 1681. 1681. 9912. 9660. 9369. 9033. 8645. 8198. 0. 0. 0. 0. 0. 0. 6000. 15.128 34.0 7.0 9 2015 38.519/$1, 000, 000 3426. 5316. 3189. 3041. 4870. i 0. 0. 0. 0. 0. 815. 797. 777. 733. 726. 49a 110. 127. 148. 171. 199. 230. 924. 924. 924. 924. 924. 924. 5316. 5187. 3041. 4870. 4671. 4441. 0. 0. 0. 0. 0. 0. 2307. 13.054 34.0 7.0 10 2015 33. 685/$1, 000, 000 2027. 1978. 1923. 1860. 1788. 1707. 0. 0. 0. 0. 0. 0. 262. 256. 248. 239. 230. 218. 49. 55. 63. 71. 81. 92. 311. 311. 311. 311. 311. 311. 1978. 1923. 1840. 1788. 1707. 1615. 0. 0. 0. 0. 0. 0. 2007 1030. 141. 8198. 1165. 316. 1681. 7682. 0. PAGE: 117 DATE: 21-May-83 TIME: 10:17 FILES: CHMGT.D1 GASGT.D2 VERSION: FIN. FORE. 2008 131. 1737. 0. 246. 135. 380. 1603. 0. 7682. 0. 1084. 595. 1681. 7088. 0. 4173. 0. 614. 310. 924. 0. 1510. igi. 119. 311. 1390. 0. 2009 0. 120. 797. 0. 1603. °. 225. 155. 1448. 0. 7088. 0. 995. 686. 1681. 6401. 0. 3863. 0. 565. 924. 3503. 0. 1390. 175. 136. 311. 1254. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE Fo135 8 1981 8 1988 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0140 9 1981 9 1988 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF _YEAR INTEREST CHARGED TO CONSTR-CREDIT Fo145 9 1981 9 1988 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0150 10 1981 10 1988 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYNENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT FO155 11 1981 11 1988 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 2010 AMOUNT APR 1450. 14.044 7974 0. 107. 102. 209. 695. 0. 14.545 1448. 0. 201. 179. 380. 1269. 0. 2558. 11312. 14.545 6401. 0. 889. 792. 1681. 5610. 0. 6000. 15.128 3503. 0. 507.., 417. 924. 3086. 0. 13.054 1254. o. 156. 154, 311. 1100. 0. 2307. 2013 DATE 2015 443. o. 34. 154. 209. 289. 0. 2015 824. 0. 105. 275. 380. 349. ‘0. 2015 3643. 0. 466. 1215. 1681. 2428. 0. 2015 2040. 0. 273. 652. 924. 1388. 0. 2015 725. 0. 84. 227. 311. 497. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) 2011 2012 TERM DEFR MAT 34.0 7.0 7 695. 578. 0. 0. 92. 74. 117. 134, 209. 209. 578. 443. 0. 0. 34.0 7.0 8 1269. 1062. 0. 0. 174. 142. 207. 238. 380. 380. 1062. 824. 0. 0. 34.0 7.0 8 5610. 4696. 0. 0. 768. 627. 913. 1053. 1681. 1681. 4696. 3643. 0. 0. 34.0 7.0 9 3086. 2602. 0. 0. 4%. 363. 484. 362. 924, 924. 2602, 2040. 0. 0. 34.0 7.0 10 1100. 924. 0. 0. 135. 111. 176. 200. 311. 311. 924, 725. 0. 0. 2014 2015 QTLY AMORT RATE 35.976/$1, 000, 000 289. 112. 0. 0. 32. 7. 177. 112. 209. 118. 112. 0. 0. 0. 37.147/$1, 000, 000 349. 5 0. 0. 63. 14. 317. 232. 380. 248. 232. 0. 0. 0. 37.147/$1,000, 000 2428. 1026. 0. 0. 279. 70. 1402. 1026. 1681. 1095. 1026. 0. 0. 0. 38.519/$1, 000, 000 1388. 632. 0. 0. 168. 48. 756. 632. 924. 680. 632. 0. 0. 0. 33. 685/61, 000, 000 497. 239. o. 0. 53. 17. 258. 239. 311. 256. 239. 0. 0. 0. PAGE: 118 DATE: 21-May-83 TIME: 10:17 FILES: CHNGT.D1 GASGT.02 VERSION: FIN. FORE. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) TABLE 10 LONG-TERM DEBT ~ EXISTING ($1,000) CONTRACT YEAR 1983 1984 1985 1986 1987 1988 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE F0160 12 1981 12 1988 1277. 13.266 34.0 7.0 11 (2015 34. 173/%1, 000, 000 BALANCE AT START OF YEAR 1277. 1277. 1277. 1277. 1277. 1277. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 169. 169. 169. 169. 169. 169. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 169. 169. 169. 169. 169. 170. BALANCE AT END OF YEAR 1277. 1277. 1277. 1277. 1277. 1277. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. F0165 1982 1 1989 1091. 14.186 34.0 7.0 12 2015 36.307/$1, 000, 000 BALANCE AT start OF YEAR 1091. _ 1091. 1091. 1091. 1091. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. INTEREST PAYMENTS 155. 153. 155. 155. 155. 155. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 155. 155. 155. 155. 155. 155. BALANCE AT END OF YEAR 1091. 1091. 1091. 10971. 1091. 1091. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. F0170 2 1982 2 1989 7463._ 14.215 34.0 7.0 1 2016 36. 375/$1, 000, 000 BALANCE AT START OF YEAR 7463. 7463. 7463. 7463. = 7463. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. INTEREST PAYMENTS 1061. 1061. 1041. 1061. 1064: 1061. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 1061. 1061. 1061. 1061. 1061. 1061. BALANCE AT END OF YEAR 7463. 7463. 7463. 7463. 7463. 7463. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. F0175 4 1982 4 1989 2410. 13.553 34.0 7.0 3 2016 34.836/$1, 000, 000 BALANCE AT START OF YEAR 2410. 2410. 2410. 2410. 2410. 2410. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 327. 327. 327. 327. 327. 327. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 327. 327. 327. 327. 327. 327. BALANCE AT END OF YEAR 2410. 2410. 2410. 2410. 2410. 2410. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. F0180 4 1982 4 1989 4002. 13.089 34.0 7.0 3 2016 33.765/$1, 000, 000 BALANCE AT START OF YEAR 4002. 4002, 4002. 4002. 4002. 4002. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 524. 524. 524. 524. 324. 524. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 524. 524. 324. 524. 324. 524. BALANCE AT END OF YEAR 4002. 4002. 4002. 4002. 4002. 4002. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 9. 0. 0. 1989 DATE: 21-tay-€3 TIME: 10:17 FILES: CHMGT.D1 GASGT.02 VERSION: FIN. FORE. 1990 1991 1271. 1265. 0. 0. 168. 167. 4. 7. 173. 175. 1265. 1258. 0. 0. 1087. 1083. 0. 0. 154. 153. 4. 5. 158. 158. 1083. 1078. 0. 5 7439. 7409. 0. 0. 1056. 1051. 30. 34. 1086. 1086. 7409. 7374. 0. 0. 2403. 2392. 0. 0. 325. 324. 11. 12. 336. 336. 2392. 2380. 0. 0. 3989. 3970. 0. 0. 521. 519. 19. 22. 541. 341. 3970. 3948. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 120 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:17 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) VERSION: FIN. FORE. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE F0160 12 1981 12 1988 1277. 13.266 34.0 7.0 11 2015 34. 173/$1, 000, 000 BALANCE AT START OF YEAR 1258. 1250. 1240. 1230. 1218. 1204, 1189. 1171. 1151. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 164. 165. 164. 163. 161. 159. 157. 154. 152. PRINCIPAL PAYMENTS 8. 9. 11. 12. 14. 14. 18. 20. 23. TOTAL PAYMENTS 175. 175. 175. 175. 175. 175. 175. 175. 175. BALANCE AT END OF YEAR 1250. 1240. 1230. 1218. 1204. 1189. 1171. 1151. 1128. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. F0165 1 1982 1 1989 1091. 14.186 34.0 7.0 12 2015 36. 307/$1, 000, 000 BALANCE AT START OF YEAR 1078. 1072. 1065. 1057. 1048. 1038. 1026. 1012. 997. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 153. 152. 151. 150. 148. 147. 145. 143. 140. PRINCIPAL PAYMENTS 4. 7. 8. 9. 10. 12. 14. 16. 18. TOTAL PAYMENTS 158. 158. 158. 158. 158. 158. 158. 158. 158. BALANCE AT END OF YEAR 1072. 1045. 1057. 1048. 1038. 1026. 1012. 997. 979. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. F0170 2 1982 2 1989 7463._ 14.215 34.0 7.0 1 2016 36.375/$1, 000, 000 BALANCE AT START OF YEAR 7374. 7335. 7289. 7237. 7176. 7107. 7027. 6936. 6830. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 1046. 1040. 1033. 1026. 1017. 1006. 994, 980. 965. PRINCIPAL PAYMENTS 40. 4%. 32. 60. 69. 80. 92. 105. 121. TOTAL PAYMENTS 1084. 1086. 1086. 1084. 1086. 1086. 1086. 1086. 1084. BALANCE AT END OF YEAR 7335. 7289. 7237. 7176. 7107. 7027. 6936. 6830. 6709. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. a. 0. 0. F0175 4 1982 4 1989 2410. 13.553 34.0 7.0 3 2016 34. 836/$1, 000, 000 BALANCE AT START OF YEAR 2380. 2366. 2350. 2332. 2311. 2287. 2260. 2229. 2193. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 322. 320. 318. 315. 312. 309. 305. 300. 295. PRINCIPAL PAYMENTS 14, 16. 18. 2i. 24. 27. 31. 36. 41. TOTAL PAYMENTS 334. 336. 336. 336. 336. 336. 336. 336. 336. BALANCE AT END OF YEAR 2366. 2350. 2332. 2311. 2287. 2260. 2229. 2193. 2153. INTEREST CHARGEO TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. F0180 4 1982 4 1989 4002. 13.087 34.0 7.0 3 2016 33.765/$1, 000, 000 BALANCE AT START OF YEAR 39748. 3922. 3894, 3862. 3825. 3783. 3735. 3681. 3619. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 515. 512. 508. 504. 499. 493. 486. 479. 470. PRINCIPAL PAYMENTS 25. 28. 32. 37. 42. 48. 34. 62. 70. TOTAL PAYMENTS 541. 541. 541. 541. 341. 341. 541. 341. 341. BALANCE AT END OF YEAR 3922. 3894. 3862. 3825. 3783. 3735. 3681. 3619. 3549. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. CHUGACH, PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE F0160 12 1981 12 1988 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0165 1 1982 1 1989 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0170 2 1982 2 1989 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT Fo175 4 1982 4 1989 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0180 4 1982 4 1989 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT le —s ae | we BURNS & MCDONNELL ENGINEERING COMPANY HOMER & MATANUSKA ELEC. ASSOCIATIONS 2001 POWER SUPPLY PROGRAN AMOUNT APR 1277. 13. 1 148: 175. 1102. 0. 14. ed 138. 21. 158. 958. 0. 14. 6709. 0. 946. 139. 1086. 6570. 0. 1091. 7463. 2410. 13. 2153. 266 186 215 353 TABLE 10 LONG-TERM DEBT - EXISTING ($1, 000) 2002 2003 2004 TERN DEFR MAT DATE 34.0 7.0 11 2015 _ a. —_ 12 141. 136. 34. 175. 175. 173, 1072. 1038. 999. 0. 0. 0. 34.0 7.0 12 2015 958. 935. 907. 0. 0. 0. 135. 131. 127. 24. 27. 31. 158. 158. 158. 935. 907. 876. 0. 0. 0. 34.0 7.0 1 2016 6570. 6410. 6225. 0. 0. 0. 926. 902. 874, 160. 184. 212. 1084. 1086. 1084. 6410. 6225. 6013. 0. 0. 0. 34.0 7.0 3 2016 2106. 2053. 1993. 0. 0. 0. 283. 275. 267. 53. 61. 69. 336. 336. 334. 2053. 1993. 1924. 9. oO. 0. 34.0 7.0 3 2016 3470. 3379. 3276. 0. 0. 0. 450. 437. 423. 91. 103. 117. 341. 341. 341. 3379. 3276. 3158. 0. 0. 9. 2005 2006 QTLY AMORT RATE 34. 173/$1, 000, 000 999. 955. 0. 0. =. 124. 50. 175. 175. 955. 905. 0. 0. 36.307/$1, 000, 000 876. 840. 0. 0. 122. 117. 34. 4i. 158. 158. 840. 798. 0. 0. 36. 375/$1, 000, 000 6013. 5770. 0. 0. 842. 806. 244. 280. 1086. 1086. Tr 7 34. 836/$1, 000, 000 1924. 1845. 0. 0. 257. 246. 79. 90. 334. 334. 1845. 1754. 0. 0. 33. 765/$1, 000, 000 3158. 3025. 0. 0. 407. 389. 133. 152. 541. 341. 3025. 2873. 0. 0. 2007 173. PAGE: 121 DATE: 21-May-83 TIME: 10:17 FILES: CHNGT.D1 GASGT.D2 VERSION: FIN. FORE. 2008 2009 847. 782. 0. 0. 109. 100. 65. 74. 175. 175. 782. 707. 0. 0. 751. 696. 0. 0. 104. 95. 55. 63. 158. 158. 694. 633. 0. 0. 5167. 4797. 0. 0. 715. 660. 371. 426. 1086. 1086. 4797. 4371. 0. 0. 1651. 1533. 0. 0. 218. 201. 118. 135. 334. 336. 1533. 1399. 0. 0. 2700. 2504. 0. 0. 344. 317. 196. 223. 541. 541. 2504. 2280. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSHISSION COOP. PLAN: GAS(8Z, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE F0160 12 1981 12 1988 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0165 1 1982 1 1989 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0170 2 1982 2 1989 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0175 4 1982 4 1989 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0180 4 1982 4 1989 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 2010 AMOUNT APR 1277. _13.266 707. 0. 90. 85. 175. 623. 0. 1091. 14.186 633. 0. 86. 72. 158. 361. 0. 7463. 14.215 4371. o. 594. 490. 1084. 3881. 0. 2410. 13.553 1399. 0. 182. 154. 336. 1245. 0. 4002. 13.089 2280. 0. 286. 254. 541. 2026. 0. TABLE 10 LONG-TERM DEBT - EXISTING ($1, 000) 2011 2012 2013 TERM DEFR MAT DATE 34.0 7.0 11 2015 623. 526. 416. 0. 0. 0. 78. 64. 49. 97. 110. 125. 175. 175. 175. 326. 416. 271. 0. 0. 0. 34.0 7.0 12 2015 361. 477. 382. 0. 0. 0. 73. 63. 48. 83. 96. 110. 158. 158. 158. 477. 382. 272. 0. 0. 0. 34.0 7.0 1 2016 3881. 3317. 2670. 0. 0. 0. 522. 438. 341. 543. 648. 745. 1086. 1086. 1084. 3317. 2670. 1925. 0. 0. 0. 34.0 7.0 3 2016 1245. 1049. 848. 0. 0. 0. 160. 135. 106. 176. 201. 229. 3364. 334. 336. 1069. 848. 639. 0. 0. 0. 34.0 7.0 3 2016 2026. 1737. 1408. 0. 0. 0. 251. 212. 1664. 289. 329. 374. 341. 341. 541. 1737. 1408. 1034. 0. 0. 0. 2014 2015 QTLY AMORT RATE 34. 173/$1, 000, 000 271. 148. 0. 0. 32. 12. 143. 148. 175. 159. 148. 0. 0. 0. 36. 307/$1, 000, 000 272. 145. 0. 0. 32. 13. 126. 145. 158. 158. 145. 0. 0. 0. 36. 375/$1, 000, 000 1925. 1068. 0. 0. 229. 101. 857. 985. 1086. 1084. 1068. 83. 0. 0. 34. 836/$1, 000, 000 639. 377. 0. 0. 74. 36. 262. 300. 336. 336. 377. 77. 0. 0. 33.765/$1, 000, 000 1034. 609. 0. 0. 115. 57. 425. 484. 541. 541. 609. 125. 0. 0. PAGE: 122 DATE: 21-May-83 TINE: 10:17 FILES: CHNGT.D1 GASGT.D2 VERSION: FIN. FORE. a BURNS & MCDONNELL ENGINEERING COMPANY CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, Z0YR) CONTRACT YEAR LOAN EXE DATE BAS DATE FO185 S 1982 5S 1989 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0190 7 (1982 7 1989 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT FO19S 7 1982 7 1989 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0200 7 1982 7 1989 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0205 9 1982 9 1989 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT POWER SUPPLY PROGRAM ee TABLE 10 LONG-TERM DEBT - EXISTING ($1, 000) 1983 1984 1985 1986 1987 1988 AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE 5008. 13.874 34.0 7.0 4 2016 35.580/$1, 000, 000 5008. 3008. 5008. 3008. 5008. 5008. 0. 0. 0. 0. 0. 0. 695. 695. 695. 695. 695. 695. 0. * 0. 0. 0. 0. 0. 695. 695. 695. 695. 695. 695. 5008. 5008. 3008. 3008. 5008. 3008. 0. 0. 0. 0. 0. 0. 1276. 14.135 34.0 7.0 6 2016 36. 188/$1, 000, 000 1276. 1276. 1276. 1276. 1276. 1276. 0. 0. 0. 0. 0. 0. 180. 180. 180. 180. 180. 180. 0. 0. 0. 0. 0. 0. 180. 180. 180. 180. 180. 180. 1276. 1276. 1276. 1276. 1276. 1276. 0. 0. 0. 0. 0. 0. 58. 12.984 34.0 7.0 6 2016 33.524/$1, 000, 000 58. 58. 58. 58. 38. 58. 0. 0. 0. 0. 0. 0. 8. 8. 8. 8. 8. 8. 0. 0. 0. 0. 0. 0. 8. 8. 8. 8. 8. 8. 58. 58. 38. 58. 38. 58. 0. 0. 0. 0. 0. 0. 752. 12.984 34.0 7.0 6 2016 33.524/$1, 000, 000 752. 732. 752. 752. 752. 752. 0. 0. 0. 0. 0. 0. 98. 98. 98. 98. 98. 98. 0. 0. 0. 0. 0. 0. 98. 98. 98. 98. 98. 98. 732. 732. 732. 732. 752. 752. 0. 0. 0. 0. 0. 0. 1806. 12.247 34.0 7.0 8 2016 31.843/$1, 000, 000 1806. 1806. 1806. 1806. 1806. 1806. 0. 0. 0. 0. 0. 0. 221. 221. 221. 221. 221. 221. 0. 0. 0. 0. 0. 0. 221. 221. 221. 221. 221. 221. 1806. 18064. 1804. 1806. 1806. 1806. 0. 0. 0. 0. 0. 0. 1989 PAGE: 123 DATE: 21-May-83 TIME: 10:17 FILES: CHMGT.D1 GASGT.D2 VERSION: FIN. FORE. 1990 1803. 10. 1793. 0. 1991 101. 1793. 0. 219. 11. 230. 1782. 0. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 124 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TINE: 10:17 PROJECT: @2-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) VERSION: FIN. FORE. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR NAT DATE QTLY ANMORT RATE FO185 5 1982 35 1989 5008. 13.874 34.0 7.0 4 2016 35.580/$1, 000, 000 BALANCE AT START OF YEAR 4951. 4924. 4892. 4857. 4816. 4769. 4715. 4653. 4582. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 686. 682. 677. 672. 666. 659. 651. 642. 632. PRINCIPAL PAYMENTS 27. 31. 34. 41. 7. 34. 62. 71. 81. TOTAL PAYMENTS 713. 713. 713. 713. 713. 713. 713. 713. 713. BALANCE AT END OF YEAR 49724. 4892. 4857. 4816. 4769. 4715. 4653. 4582. 4501. INTEREST CHARGEO TO CONSTR-CREDIT oO. 0. 0. 0. 0. 0. 0. 0. 0. F0190 7 (1982 7 1989 1276. 14.135 34.0 7.0 & 2016 36. 188/$1, 000, 000 BALANCE AT START OF YEAR 1263. 1257. 1249. 1241. 1231. 1219. 1206. 1192. 1174. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 178. 177. 176. 175. 173. 172. 170. 168. 165. PRINCIPAL PAYMENTS 6. 7. 9. 10. il. 13. 15. 17. 20. TOTAL PAYMENTS 185. 185. 185. 185. 185. 185. 185. 185. 185. BALANCE AT END OF YEAR 1257. 1247. 1241. 1231. 1219. 1206. 1192. 1174. 1155. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. ‘0. 0. 0. 0. 0. 0. FO195 7 (1982 7 1989 38. 12.984 34.0 7.0 6 2016 33.524/$1, 000, 000 BALANCE AT START OF YEAR 57. 57. 57. 54. 56. 55. 34. 53. 33. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. oO. INTEREST PAYMENTS 7. 7. 7. 7. 7. 7. 7. 7. 7. PRINCIPAL PAYMENTS 0. 0. o. 1. 1. 1. 1. 1. 1. TOTAL PAYMENTS 8. 8. 8. 8. 8. 8. 8. 8. 8. BALANCE AT END OF YEAR 57. 57. 34. 34. 55. 54. 33. 33. 52. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. Oo. 0. 0. 0. 0. 0. 0. F0200 7. 1982 7 1989 732. 12.984 34.0 7.0 6 2016 33.524/$1, 000, 000 BALANCE AT START OF YEAR 743. 738. 733. 727. 720. 712. 703. 693. 682. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 96. 96. 95. 94. 93. 92. 91. 90. 88. PRINCIPAL PAYMENTS 5. 5. 6. 7. 8. 9. 10. 11. 13. TOTAL PAYMENTS 101. 101. 101. 101. 101. 101. 101. 101. 101. BALANCE AT END OF YEAR 738. 733. 727. 720. 712. 703. 693. 682. 669. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. F0205 9 1982 9 1989 1806. 12.247 34.0 7.0 8 2016 31.843/$1, 000, 000 BALANCE AT START OF YEAR 1782. 1770. 1756. 1740. 1723. 1703. 1680. 1655. 1626. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 218. 216. 214, 212. 210. 208. 205. 201. 198. PRINCIPAL PAYMENTS 12. 14. 16. 18. 20. 22. 25. 29. 32. TOTAL PAYMENTS 230. 230. 230. 230. 230. 230. 230. 230. 230. BALANCE AT END OF YEAR 1770. 1756. 1740. 1723. 1703. 14680. 1655. 1626. 1594. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. . . a ee ee re CHUGACH, PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE Foi8s 5 1982 3 1989 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0190 1982 7 1989 BALANCE AT Start OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT Fo195 7 1982 7 1989 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0200 7 1982 7 1989 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT F0205 9 1982 9 1989 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM HOMER & MATANUSKA ELEC. ASSOCIATIONS ee TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) 2001 2002 2003 2004 2005 2006 AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE 5008. 13.874 34.0 7.0 4 2016 35.580/$1, 000, 000 4501. 4408. 4302. 4180. 404. ° 0. 0. 0. 0. 0. 0. 620. 606. 571. 373. 332. 329. 93. 104. 122. 140. 160. 184. 713. 713. 713. 713. 713. 713. 4408. 4302. 4180. 4040. 3880. 3696. 0. o. 0. 0. 0. 0. 1276. 14.135 34.0 7.0 & 2016 36. 188/$1, 000, 000 1155. 1132. 1106. 1076. 1042. 1002. 0. 0. 1 0. 0. 0. 0. 162. 159. 155. 150. 14. 139. 23. 26. 30. 34. 4. g. 185. 185. 185. 185. 185. 185. 1132. 1106. 1076. 1042. 1002. 957. 0. 0. 0. 0. 0. 0. 58. 12.984 34.0 7.0 & 2016 33.524/$1, 000, 000 32. 50. 4. 48. 4%. 44. 0. 0. 0. 0. 0. 0. 7. 6. 6. 6. 6. 6. 1. 1. 1. 2. 2. 2. 8. 8. 8. 8. 8. 8. 50. 4. 48. 4%. a. 42. 0. 0. 0. 0. 0. 0. 752. 12.984 34.0 7.0 & 2016 33.524/$1, 000, 000 669. 655. 638. 619. 598. 573. 0. 0. 0. 0. 0. 0. 86. 84. 82. 79. 76. 73. 15. 17. 19. 21. 24. 28. 101. 101. 101. 101. 101. 101. 655. 638. 619. 398. 573. 345. 0. 0. 0. 0. 0. 0. 1806. 12.247 34.0 7.0 8 2016 31.843/$1, 000, 000 1594. 1558. 1517. 1470. 1418. 1359. 0. 0. 0. 0. 0. 0. 194, 189. 184. 178. 171. 143. 34. 41. 46. 52. 39. 67. 230. 230. 230. 230. 230. 230. 1558. 1517. 1470. 1418. 1359. 1292. 0. a. 0. 0. 0. 0. poms - 2007 3696. 0. 211. 713. 0. DATE: 21-May-89 TINE: 10:17 FILES: CHMGT.D1 GASGT.D2 VERSION: FIN. FORE. 2008 2009 3485. 3244. 0. 0. 471. 436. 241. 277. 713. 713. 3244, 2967. 0. 0. 905. 845. 0. 0. 125. 116. 60. 69. 185. 185. 845. 776. 0. 0. x. 37. 0. 0. 3. 5. 3. 3. 8. 8. 37. 34, 0. 0. 514. 478. 0. 0. 65. 60. 36. 4i. 101. 101. 478. 437. 0. 0. 1217. 1132. 0. 0. 145. 134. 85. 96. 230. 230. 1132. 1037. 0. 0. es BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 126 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TINE: 10:17 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) VERSION: FIN. FORE. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) CONTRACT YEAR 2010 2011 2012 2013 2014 2015 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE F0185 5 1982 3S 1989 5008. 13.874 34.0 7.0 4 2016 35.580/$1, 000, 000 BALANCE AT START OF YEAR 2967. 2650. 2287. 1870. 1393. 845. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 396. 349. 296. 235. 166. 86. PRINCIPAL PAYMENTS 317. 363. 417. 477. 547. 627. TOTAL PAYMENTS 713. 713. 713. 713. 713. 713. BALANCE AT END OF YEAR 2650. 2287. 1870. 1393. 845. 218. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. F0190 7 (1982 7 1989 1276. 14.135 34.0 7.0 & 2016 36. 188/$1, 000, 000 BALANCE AT START OF YEAR 776. 697. 606. 501. 381. 243. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 106. 94. 80. 65. 7. 26. PRINCIPAL PAYMENTS 79. v1. 104. 120. 138. 158. TOTAL PAYMENTS 185. 185. 185. 185. 185. 185. BALANCE AT END OF YEAR 697. 606. 501. 381. 243. 85. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. "0. 0. 0. FO19S 7 1982 7 1989 538. 12.984 34.0 7.0 6 2016 33.524/$1, 000, 000 BALANCE AT START OF YEAR 34. 30. 26. 22. 16. 10. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 4. 4. 3. 3. 2. 1. PRINCIPAL PAYMENTS . 4. 4. 5. 5. 6. 7. TOTAL PAYMENTS 8. 8. 8. 8. 8. 8. BALANCE AT END OF YEAR 30. 26. 22. 16. 10. 4. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. F0200 7 1982 7 1989 732. 12.984 34.0 7.0 6 2016 33.524/$1, 000, 000 BALANCE AT START OF YEAR 437. 391. 339. 279. 2il. 134. ADVANCES DURING THE YEAR o. 0. 0. 0. 0. 0. INTEREST PAYMENTS 55. 48. 41. 33. 24. 13. PRINCIPAL PAYMENTS 4. 53. 60. 68. 77. 88. TOTAL PAYMENTS 101. 101. 101. 101. 101. 101. BALANCE AT END OF YEAR 391. 339. 279. 211. 134. 47. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. F0205 9 1982 9 1989 1806. 12.247 34.0 7.0 8 2016 31. 843/$1, 000, 000 BALANCE AT START OF YEAR 1037. 929. 807. 669. 514. 340. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 122. 108. 93. 73. 35. 33. PRINCIPAL PAYMENTS 108. 122. 137. 155. 175. 197. TOTAL PAYMENTS 230. 230. 230. 230. 230. 230. BALANCE AT END OF YEAR 929. 807. 649. 514. 340. 142. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) CONTRACT YEAR 1983 1984 1985 1986 1987 1988 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE 4030 2 1950 2 1959 204. 2.000 39.0 9.0 1 1989 11.102/$1, 000, 000 BALANCE AT START OF YEAR 32. 44. 36. 27. 19. 10. ADVANCES DURING THE YEAR 0. 0. 0. 0. o. 0. INTEREST PAYMENTS 1. 1. 1. 0. 0. 0. PRINCIPAL PAYMENTS 8. 8. 8. 9. 9. 9. TOTAL PAYMENTS 9. 9. 9. 9. 9. 9. BALANCE AT END OF YEAR 44. 34. 27. 19. 10. 1. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 4040 2 1950 2 1959 3246. 2.000 37.0 9.0 1 1989 11.102/$1, 000, 000 BALANCE AT START OF YEAR 818. 689. 557. 423. 287. 147. ADVANCES DURING THE YEAR 0. 0. ' 0. 0. 0. 0. INTEREST PAYMENTS 15. 13. 10. 7. 3. 2. PRINCIPAL PAYMENTS 129. 131. 134. 137. 139. 142. TOTAL PAYMENTS 144, 144, 144, 144. 144, 144. BALANCE AT END OF YEAR 689. 557. 423. 287. 147. 3. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 4080 11 1954 11 1959 2457. 2.000 35.0 5.0 10 1989 11. 102/$1, 000, 000 BALANCE AT START OF YEAR 683. 587. 489. 387. 287. 182. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 13. 11. 9. 7. 5. 3. PRINCIPAL PAYMENTS 96. 98. 100. 102. 104, 106. TOTAL PAYMENTS 109. 109. 109. 109. 109. 109. BALANCE AT END OF YEAR 387. 489. 389. 287. 182. 76. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 4100 7 1958 7 1967 1000. 2.000 39.0 9.0 6 1997 11.102/$1, 000, 000 BALANCE AT START OF YEAR 558. 324. 490. 455. 420. 383. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 11. 10. 10. 9. 8. 7. PRINCIPAL PAYMENTS 34. 34. 35. 34. 36. 37. TOTAL PAYMENTS 44, 44. 44. 44. 44, 44. BALANCE AT END OF YEAR 524. 470. 455. 420. 383. 346. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 4110 6 1959 & 1968 4000. 2.000 39.0 9.0 3 1998 11.102/$1, 000, 000 BALANCE AT START OF YEAR 2361. 2229. 2095. 1959. 1819. 1677. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 44. 44. 4i. 38. 35. 32. PRINCIPAL PAYMENTS 131. 134. 137. 140. 142. 145. TOTAL PAYMENTS 178. 178. 178. 178. 178. 178. BALANCE. AT END OF YEAR 2229. 2095. 1959. 1819. 1677. 1532. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. PAGE: 127 DATE: 21-May-83 TIME: 10:17 FILES: CHMGT.D1 GASGT.D2 VERSION: FIN. FORE. 1989 1990 1. 0. 0. 0. 0. 0. 1. 0. 1. 0. 0. 0. 0. 0. 5. 0. 0. 0. 0. 0. 5. 0. 5. 0. 0. 0. 0. 0. 76. 0. 0. 0. 1. 0. 76. 0. 77. 0. 0. 0. 0. 0. 346. 308. 0. 0. 7. 6. 38. 39. 44. 44. 308. 270. 0. 0. 1532. 1383. 0. 0. 30. 27. 148. 151. 178. 178. 1383. 1232. 0. 0. 1991 231. 1232. 23. 154. 178. 1078. 0. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 128 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:17 PROJECT: 82-113-4-000 FILES: CHNMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) VERSION: FIN. FORE. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE Q@TLY AMORT RATE 4030 2 1950 2 1959 204. 2.000 39.0 9.0 1 1989 11. 102/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 9. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 4040 2 1950 2 1959 3246. 2.000 37.0 7.0 1 1989 11.102/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 4080 11 1954 11 (1959 2457. 2.000 35.0 5.0 10 1989 11. 102/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 4100 7 (1958 7 1967 1000. 2.000 37.0 9.0 & 1997 11.102/$1, 000, 000 BALANCE AT START OF YEAR 231. 191. 150. 108. 65. 22. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 4. 4. 3. 2. 1. 0. 0. 0. 0. PRINCIPAL PAYMENTS 40. 41. 42. 43. 43. 22. 0. 0. 0. TOTAL PAYMENTS 44. 44. 44. 44. 44. 22. 0. 0. 0. BALANCE AT END OF YEAR 191. 150. 108. 65. 22. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 4110 & 1959 6 1968 4000. 2.000 39.0 9.0 5 1998 11.102/$1, 000, 000 BALANCE AT START OF YEAR 1078. 921. 761. 597. 430. 260. 84. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 20. 17. 14. 11. 7. 4. 1. 0. 0. PRINCIPAL PAYMENTS 157. 160. 164. 167. 170. 174. 84. 0. 0. TOTAL PAYMENTS 178. 178. 178. 178. 178. 178. 87. 0. 0. BALANCE AT END OF YEAR 921. 761. 597. 430. 260. 84. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 9. 0. 0. 0. 0. 0. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 129 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOFER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:17 PROJECT: 82-113-4-000 FILES: CHNGT.01 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) VERSION: FIN. FORE. TABLE 10 LONG-TERM DEBT ~- EXISTING ($1, 000) CONTRACT YEAR 2001 2002 2003 2004 2005 2006 2007 2008 2009 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE 4030 2 1950 2 1959 204. 2.000 39.0 9.0 1 1989 11. 102/61, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS o. o. 0. 0. 0. 0. 0. 0. 0. TOTAL, PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. o. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 4040 2 1950 2 1959 324. 2.000 37.0 9.0 1 1989 11.102/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 1 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 4080 11 1954 11 1959 2459. 2.000 35.0 5.0 10 1989 11.102/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. o. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 4100 7. 1958 7 1967 1000. 2.000 39.0 9.0 & 1997 11. 102/61, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 4110 6 1959 & 1968 4000. 2.000 39.0 9.0 3S 1998 11.102/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 130 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:17 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) VERSION: FIN. FORE. TABLE 10 LONG-TERM DEBT ~ EXISTING ($1,000) CONTRACT YEAR 2010 2011 2012 2013 2014 2015 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE 4030 2 1950 2 1959 204. 2.000 39.0 9.0 1 1989 11. 102/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 4040 2 1950 2 1959 3246. 2.000 37.0 9.0 1 1989 11. 102/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 4080 11 1954 11 1959 2459. 2.000 35.0 5.0 10 1989 11. 102/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 4100 7 1958 7 1967 1000. 2.000 397.0 9.0 6 1997 11. 102/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. BALANCE. AT END OF_ YEAR 0. 0. 0. 0. o. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 4110 6 1959 & 1968 4000. 2.000 39.0 9.0 3S 1998 11.102/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. INTEREST CHARGEO TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. * Ly . enn - wee eee oe ——~ ed ted) - CHUGACH, PROJECT: @82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) CONTRACT YEAR LOAN EXE DATE 4ii1 & 1959 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 4112 6 1959 6 1968 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 4120 3 1960 3 1965 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 4130 S 1961 5 1968 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 4140 6 1962 & 1969 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT BAS DATE 6 1968 —— = = BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM HOMER & MATANUSKA ELEC. ASSOCIATIONS AMOUNT 4000. 2.000 TABLE 10 LONG-TERM DEBT - EXISTING ($1, 000) 1984 1985 1986 TERN DEFR MAT DATE 39.0 9.0 3 1998 2229. 2095. 1959. 0. 0. 0. 44, 41. 38. 134. 137. 140. 178. 178. 178. 2095. 1959. 1819. 0. 0. 0. 37.0 9.0 3 1998 1628. 1530. 1431. 0. 1 0. 0. 32. 30. 28. 98. 100. 102. 130. 130. 130. 1530. 1431. 1329. 0. 0. 0. 9.0 5.0 2 1999 314. 485. 456. 0. 0. 0. 10. 9. 9. 29. 30. 30. 39. 39. 39. 485. 454. 425. 0. 0. 0. 397.0 7.0 4 2000 165. 156. 147. 0. 0. 0. 3. 3. 3. 9. 9. 9. 12. 12. 12. 156. 147. 138. 0. 0. 0. 397.0 7.0 3 2001 1545. 1470. 1394. 0. 0. 0. 30. 29. 27. 73. 76. 78. 105. 105. 105. 1470. 1394, 1317. 0. 0. 9. 1987 1988 QTLY AMORT RATE 11.102/$1, 000, 000 1819. 1677. 0. 0. 35. 32. 142. 145. 178. 178. 1677. 1532. 0. 0. 11. 102/61, 000, 000 1329. 1225. 0. 0. 26. 24. 104. 106. 130. 130. 1225. 1119. 0. 0. 10. 152/$1, 000, 000 425. 394. 0. 0. 8. 8. 31. 32. 39. 39. 394. 343. 0. 0. 10.596/$1, 000, 000 138. 129. 0. 0. 3. 3. 9. 9. 12. 12. 129. 120. 0. 0. 10.596/$1, 000, 000 1317. 1237. 0. 0. 26. 24. 79. 81. 105. 105. 1237. 1157. 0. 0. eos wom 1989 1074, DATE: 2i-tta TIME: 10: 18s FILES: CHMGT.01 GASGT.D2 VERSION: FIN. FORE. 1990 1991 1383. 1232. 0. 0. 27. 23. 151. 154. 178. 178. 1232. 1078. 0. 0. 1011. 900. 0. 0. 19. 17. 110. 113. 130. 130. 900. 788. 0. 0. 330. 298. 0. 0. 6. 4. 33. 34. 39. 39. 298. 264. 0. 0. 111. 101. 0. 0. 2. 2. 10. 10. 12. 12. 101. a1. 0. 0. 1074. 990. 0. 0. 21. 19. 84. 84. 105. 105. 990. 905. 0. 0. _s BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 132 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:17 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) VERSION: FIN. FORE. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE 4111 & 1959 & 1968 4000. 2.000 37.0 7.0 3 1998 11.102/$1, 000, 000 BALANCE AT START OF YEAR 1078. 921. 761. 597. 430. 260. 86. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 20. 17. 14. 11. 7. 4. 1. 0. 0. PRINCIPAL PAYMENTS 157. 160. 164. 167. 170. 174. 84. 0. 0. TOTAL PAYMENTS 178. 178. 178. 178. 178. 178. 87. 0. 0. BALANCE AT END OF YEAR 921. 761. 597. 430. 260. 84. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 4112 6 1959 & 1968 2722. 2.000 37.0 7.0 3 1998 11. 102/$1, 000, 000 BALANCE AT START OF YEAR 788. 673. 5336. 436. 314. 190. 63. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 15. 13. 10. 8. 5. 3. 0. 0. 0. PRINCIPAL PAYMENTS 115. 117. 120. 122. 124, 127. 63. 0. 0. TOTAL PAYMENTS 130. 130. 130. 130. 130. 130. 63. 0. 0. BALANCE AT END OF YEAR 673. 554. 434. 314. 190. 63. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 4120 3 1960 3 1965 966. 2.000 397.0 5.0 2 1999 10. 152/61, 000, 000 BALANCE AT START OF YEAR 264. 230. 195. 159. 123. 86. 48. 10. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 5. 4. 4. 3. 2. 1. 1. 0. 0. PRINCIPAL PAYMENTS 34. 35. 36. 36. 37. 38. 39. 10. 0. TOTAL PAYMENTS 39. 39. 39. 39. 39. 39. 39. 10. 0. BALANCE AT END OF YEAR 230. 195. 159. 123. 86. 48. 10. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. Oo. 0. 0. 4130 3 1961 3 1968 277. 2.000 37.0 7.0 4 2000 10.596/$1, 000, 000 BALANCE AT START OF YEAR a1. 61. 71. 61. 50. 39. 28. 17. 6. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 2. 2. 1. 1. 1. 1. 0. 0. 0. PRINCIPAL PAYMENTS 10. 10. 10. 11. 11. 11. 11. 11. 6. TOTAL PAYMENTS 12. 12. 12. 12. 12. 12. 12. 12. 6. BALANCE AT END OF YEAR 81. 71. 61. 50. 39. 28. 17. 6. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. oe 0. 0. 0. 0. 0. 4140 & 1962 & 1969 2474. 2.000 37.0 7.0 3 2001 10.596/$1, 000, 000 BALANCE AT START OF YEAR 905. 817. 728. 637. 344. 450. 353. 254. 154. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 17. 16. 14. 12. 10. 8. 6. 4. 2. PRINCIPAL PAYMENTS 87. 89. 91. 93. 95. 97. 99. 101. 103. TOTAL PAYMENTS 105. 105. 105. 105. 105. 105. 105. 105. 105. BALANCE AT END OF YEAR 817. 728. 637. 344. 450. 353. 254. 154. 51. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 133 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:17 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) VERSION: FIN. FORE. TABLE 10 LONG-TERM DEBT - EXISTING ($1, 000) CONTRACT YEAR 2001 2002 2003 2004 2005 2006 2007 2008 2009 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE 4111 6 1959 & 1968 4000. 2.000 37.0 9.0 3 1998 11.102/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. oO. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. o. Oo. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 4112 6 1959 & 1968 2922. 2.000 37.0 9.0 3 1998 11. 102/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 1 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 4120 3 1960 3 1965 966. 2.000 37.0 5.0 2 1999 10. 152/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS oO. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 4130 3 1961 5 1968 277. 2.000 37.0 7.0 4 2000 10.596/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 4140 & 1962 & 1969 2474. 2.000 39.0 7.0 3 2001 10.596/$1, 000, 000 BALANCE AT START OF YEAR 51. 0. 0. 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 9. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 51. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 32. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. Oo. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. o 0. 0. 0. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) CONTRACT YEAR LOAN EXE DATE 4111 6 1959 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 4112 6 1959 & 1968 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 4120 3 1960 3 1965 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 3 1968 BAS DATE & 1968 4130 3 1961 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 4140 & 1962 & 1969 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT Leerd Bsmt ems ee = TABLE 10 LONG-TERM DEBT - EXISTING ($1, 000) 2010 2011 2012 2013 2014 2015 AMOUNT APR TERM DEFR MAT DATE — @TLY AMORT RATE 4000. 2.000 37.0 9.0 5 1998 11.102/$1,000, 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. 2922. 2.000 37.0 9.0 5 1998 11.102/$1,000, 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. 966. 2.000 37.0 5.0 2 1999 10.152/$1,000, 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. 277. 2.000 39.0 7.0 4 2000 10.594/$1,000, 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. 2474. 2.000 39.0 7.0 5 2001 —10.596/$1,000, 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. PAGE: 134 DATE: 21-May-83 TIME: 10:17 FILES: CHNGT.D1 GASGT: D2 VERSION: FIN. FORE. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%Z, 20YR) CONTRACT YEAR LOAN EXE DATE 4170 4 1964 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 4200 7 1965 7 1970 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 4210 11 1965 11 1970 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 4220 2 1966 2 1971 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 4230 11 1965 11 1968 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT BAS DATE 4 1969 TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) 1983 1984 1985 1986 1987 1988 AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE 3000. 2.000 35.0 5.0 3 1999 11.102/$1, 000, 000 1845. 1748. 1649. 1548. 1445. 1340. 0. 0. 0. 0. 0. 0. 34. 34. 32. 30. 28. 26. 97. 99. 101. 103. 105. 107. 133. 133. 133. 133. 133. 133. 1748. 1649. 1548. 1445. 1340. 1232. 0. 0. 0. 0. 0. 0. 995. 2.000 35.0 5.0 6 2000 11. 102/$1, 000, 000 651. 620. 588. 555. 522. 488. 0. 0. 1 0. 0. 0. 0. 13. 12. 12. 11. 10. 9. 31. 32. 33. 33. 34. 35. 44, 44. 44, 44. 44. 44. 620. 588. 355. 322. 488. 453. 0. 0. 0. 0. 0. 0. 156. 2.000 35.0 5.0 10 2000 11. 102/$1, 000, 000 103. 98. 93. 88. 83. 78. 0. 0. 0. 0. 0. 0. 2. 2. 2. 2. 2. 2. 5. 5. 5. 5. 3. 3. 7. 7. 7. 7. 7. 7. 98. 93. 88. 83. 78. 72. 0. 0. 0. 0. 0. 0. 3000, 2.000 35.0 5.0 1 2001 11.102/$1, 000, 000 “2010. 1916. 1821. 1723. 1624, 1522. 0. 0. 0. 0. 0. 0. 40. 38. 36. 34. 32. 30. 94. 9. 98. 100. 102. 104. 133. 133. 133. 133. 133. 133. 1916. 1821. 1723. 1624. 1522. 1419. 0. 0. 0. 0. 0. 0. 1685. 2.000 35.0 3.0 10 2000 10.596/$1, 000, 000 1077. 1026. 975. 923. 870. 815. 0. 0. 0. 0. 0. 0. 21. 20. 19. 18. 17. 16. 50. 51. 52. 53. 34. 36. 71. 71. 71. 71. 71. 71. 1026. 975. 923. 870. 815. 760. 0. o 0. O 0. 0. 1989 DATE: 2icfay-83 TIME: 10:17 FILES: CHNGT.D1 GASGT. D2 VERSION: FIN. FORE. 1990 1991 1123. 1011. 0. 0. 22. 19. 112. 114. 133. 133. 1011. 897. 0. 0. 418. 381. 0. 0. 8. 7. 36. 37. 44. 44. 381. 345. 0. 0. 67. 61. 0. 0. 1. 1. 6. é. 7. 7. 61. 54. 0. 0. 1313. 1205. 0. 0. 25. 23. 108. 110. 133. 133. 1205. 1095. 0. 0. 703. 645. 0. 0. 14. 12. 58. 59. 71. 71. 645. 584. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE 4170 4 1964 4 1969 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 4200 7 (1965 7 1970 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 4210 11 1965 11 1970 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 4220 2 1966 2 1971 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 4230 111965 11 1968 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 1992 3000. 2.000 897. 0. 17. 116. 133. 781. 0. 345. 7. 38. 44, 307. 0. 156. 2.000 56. 0. 1. 6. 7. 50. 0. 3000. 2.000 1095. 21. 112. 133. 983. 0. 1685. 2.000 586. 0. 11. 60. 71. 526. 0. TABLE 10 LONG-TERM DEBT - EXISTING ($1, 000) 1993 1994 1995 TERM DEFR MAT _~DATE 35.0 5.0 3 1999 781. 663. 542. 0. 0. 0. 15. 12. 10. 118. 121. 123. 133. 133. 133. 663. 542. 419. 0. 0. 0. 35.0 5.0 6 2000 307. 269. 230. 0. 0. 0. é. 5. 4. 38. 39. 40. 249. 230. 190. 0. 0. 0. 35.0 5.0 10 2000 50. 44. 38. 0. 0. 0. 1. 1. 1. é. é. é. 7. 7. 7. 44. 38. 31. 0. 0. 0. 35.0 5.0 1 2001 983. 869. 752. 0. 0. 0. 19. 17. 14. 114. 117. 119. 133. 133. 133. 869. 752. 633. 0. 0. 0. 35.0 3.0 10 2000 526, 465. 402. 0. 0. 0. 10. 9. 8. 41. 63. 64. 71. 71. 71. 465. 402. 338. 0. 0. 0. 1996 1997 QTLY AMORT RATE 11.102/$1, 000, 000 419. 293. 0. 0. 7. 5. 126. 128. 133. 133. 293. 165. 0. 0. 11.102/$1, 000, 000 190. 149. 0. 0. 3. 3. 41. 42. 44. 44. 149. 108. 0. 0. 11. 102/$1, 000, 000 31. 25. 0. 0. 1. 0. 6. 6. 7. 7. 3. 19. 0. 0. 11.102/$1, 000, 000 633. 511. 0. 0. 12. 9. 121. 124. 133. 133. S11. 387. 0. 0. 10.596/$1, 000, 000 338. 273. 0. 0. 6. 5. 65. 64. 71. 71. 273. 207. 0. 0. 1998 126. 133. 261. 0. 207. 0. 68. 71. 139. PAGE: 136 DATE: 21-Nay-83 TIME: 10:17 FILES: CHMGT.D1 GASGT.D2 VERSION: FIN. FORE. 1999 2000 34. 0. 0. 0. 0. 0. 34. 0. 34. 0. 0. 0. 0. 0. 65. 22. 0. 0. 1. 0. 43. 22. 44. 22. 22. 0. 0. 0. 12. 5. 0. 0. 0. 0. 7. 5. 7. 5. 5. 0. 0. 0. 261. 132. 0. 0. 4. 2. 129. 132. 133. 133. 132. 0. 0. 0. 139. 70. 0. 0. 2. 1. 69. 70. 71. 71. 70. 0. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 137 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:17 PROJECT: 82-113-4-000 FILES: CHMNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) VERSION: FIN. FORE. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) CONTRACT YEAR 2001 2002 2003 2004 2005 2006 2007 2008 2009 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE 4170 4 1964 4 1969 3000. 42.000 35.0 5.0 3 1999 11. 102/61, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. Oo. 0. 0. 0. o. 0. 0. o. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. Oo. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 4200 7 (1965 7 1970 995. 2.000 35.0 5.0 6 2000 11. 102/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 1 On 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 4210 11 1965 11 1970 156. 2.000 35.0 5.0 10 2000 11.102/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. oO. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. o. 0. 0. 0. 0. 0. 0. 4220 2 1966 2 1971 3000. 2.000 35.0 5.0 1 2001 11. 102/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 4230 11. 1965 11 1968 14685. 2.000 35.0 3.0 10 2000 10.596/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 5 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 9. 0. 0. 0. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 138 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:17 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) VERSION: FIN. FORE. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) CONTRACT YEAR 2010 2011 2012 2013 2014 2015 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY ANORT RATE 4170 4 1964 4 1969 3000. 2.000 35.0 5.0 3 1999 11.102/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 4200 7 (1965 7 1970 995. 2.000 35.0 5.0 6 2000 11. 102/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. a. 0. 0. 0. 4210 11 1965 11 1970 156. 2.000 35.0 5.0 10 2000 11.102/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 4220 2 1966 2 1971 3000. 2.000 35.0 5.0 1 2001 11. 102/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR a. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 4230 11. 1965 11 1968 1685. 2.000 35.0 3.0 10 2000 10.596/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. toe, ae oo) [ae enw? — ee a ee - - ~ - - “ - * BURNS & MCOONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) CONTRACT YEAR 1983 1984 1985 1986 1987 1988 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR NAT DATE QTLY AMORT RATE 4260 3. 1967 3 1972 4000. 32.000 35.0 5.0 2 2002 11.102/$1, 000, 000 BALANCE AT START OF YEAR 2802. 2680. 2555. 2428. 2297. 2165. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 35. 53. 50. 48. 5. 42. PRINCIPAL PAYMENTS 122. 125. 127. 130. 133. 135. TOTAL PAYMENTS 178. 178. 178. 178. 178. 178. BALANCE AT END OF YEAR 2680. 2555. 2428. 2297. 2165. 2029. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 4270 & 1967 & 1972 3443. 2.000 35.0 5.0 5 2002 11.102/$1, 000, 000 BALANCE AT START OF YEAR 2438. 2333. 2226. 2117. 2006. 1892. ADVANCES DURING THE YEAR 0. 0. 1 0. 0. 0. 0. INTEREST PAYMENTS 48. 4%. 44. 42. 39. 37. PRINCIPAL PAYMENTS 105. 107. 109. 111. 114, 116. TOTAL PAYMENTS 153. 153. 153. 153. 153. 153. BALANCE AT END OF YEAR 2333. 2226. 2117. 2006. 1892. 1776. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 4280 6 1967 6 1970 2151. 2.000 35.0 3.0 3 2002 10.596/$1, 000, 000 BALANCE AT START OF YEAR 1469. 1406. 1343. 1278. 1212. 1145. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 29. 28. 26. 25. 24. 22. PRINCIPAL PAYMENTS 62. 64. 65. 664. 67. 69. TOTAL PAYMENTS 91. 91. 91. 91. 91. 91. BALANCE AT END OF YEAR 1404. 1343. 1278. 1212. 1145. 1074. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 4300 12 1969 12 1974 4460. 2.000 35.0 5.0 11 2004 11. 102/$1, 000, 000 BALANCE AT START OF YEAR 3518. 3389. 3258. 3124. 2988. 2848. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 69. 67. 64. 61. 39. 36. PRINCIPAL PAYMENTS 129. 131. 134. 137. 139. 142. TOTAL PAYMENTS 198. 198. 198. 198. 198. 198. BALANCE AT END OF YEAR 3389. 3258. 3124. 2988. 2848. 2706. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 4310 9 1970 9 1975 3000. 2.000 35.0 5.0 8 2005 11. 102/$1, 000, 000 BALANCE AT START OF YEAR 2409. 2324. 2236. 2147. 2056. 1943. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 48. 4. 44. 42. 4%. 39. PRINCIPAL PAYMENTS 84. 87. 89. 91. 93. 95. TOTAL PAYMENTS 133. 133. 133. 133. 133. 133. BALANCE AT END OF YEAR 2324. 2236. 2147. 2056. 1963. 1849. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 9. 0. oO oO. 1989 178. 1891. 0. 1776. 0. 118. 153. 1658. 0. 1076. 0. 2i. 70. 91. 1004. 0. 2706. 0. 33. 145. 198. 2541. 0. 1869. 0. 97. 133. 1772. 0. PAGE: 139 DATE: 21-May-83 TIME: 10:17 FILES: CHNGT.D1 GASGT.D2 VERSION: FIN. FORE. 1990 1991 18971. 1751. 0. 0. 37. 34. 141. 144. 176. 178. 1751. 1607. 0. 0. 1658. 1537. 0. 0. 32. 30. 121. 123. 153. 153. 1537. 1414, 0. 0. 1006. 934. 0. 0. 20. 18. 72. 73. 91. 91. 934. 841. 0. 0. 2561. 2413. 0. 0. 50. 7. 148. 151. 198. 198. 2413. 2262. 0. 0. 1772. 1674. 0. 0. 35. 33. 99. 101. 133. 133. 1674. 1573. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 140 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:17 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) VERSION: FIN. FORE. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR HAT DATE QTLY AMORT RATE 4260 3 1967 3 1972 4000. 2.000 35.0 5.0 2 2002 11. 102/$1, 000, 000 BALANCE AT START OF YEAR 1607. 1440. 1311. 1158. 1002. 844, 682. 317. 348. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 31. 28. 25. 22. 19. 16. 12. 9. 6. PRINCIPAL PAYMENTS 147. 150. 153. 154. 159. 142. 165. 169. 172. TOTAL PAYMENTS 178. 178. 178. 178. 178. 178. 178. 178. 178. BALANCE AT END OF YEAR 1460. 1311. 1158. 1002. 844, 682. 317. 348. 176. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 4270 & 1967 6 1972 3443. 2.000 35.0 5.0 3 2002 11.102/$1, 000, 000 BALANCE AT START OF YEAR 1414. 1289. 1161. 1030. 897. 761. 622. 480. 3364. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 27. 2. 22. 20. 17. 14. 11. 9. 6. PRINCIPAL PAYMENTS 126. 128. 131. 133. 136. 139. 142, 144, 147. TOTAL PAYMENTS 153. 153. 153. 153. 153. 153. 153. 153. 153. BALANCE AT END OF YEAR 1289. 1161. 1030. 897. 761. 622. 480. 336. 189. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 4280 & 1967 6 1970 2151. 2.000 35.0 3.0 3 2002 10.596/$1, 000, 000 BALANCE AT START OF YEAR 861. 786. 710. 633. 554. 473. 391. 307. 221. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 17. 15. 14. 12. 10. 9. 7. 5. 4. PRINCIPAL PAYMENTS 75. 76. 78. 79. 81. 82. 84. 86. 87. TOTAL PAYMENTS 91. 91. 91. 91. 91. 91. 91. 91. 91. BALANCE AT END OF YEAR 786. 710. 633. 534. 473. 371. 307. 221. 134. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 4300 12 1969 12 1974 4460. 2.000 35.0 5.0 11 2004 11. 102/$1, 000, 000 BALANCE AT START OF YEAR 2262. 2109. 1951. 1791. 1628. 14641. 1291. 1118. 941. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 44. 4i. 38. 35. 31. 28. 25. 21. 17. PRINCIPAL PAYMENTS 154. 157. 160. 163. 167. 170. 174, 177. 181. TOTAL PAYMENTS 198. 198. 198. 198. 198. 198. 198. 198. 198. BALANCE AT END OF YEAR 2109. 1951. 1791. 1628. 1461. 1291. 1118. 941. 760. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 4310 9 1970 9 1975 3000. 2.000 35.0 5.0 8 2005 11. 102/$1, 000, 000 BALANCE AT START OF YEAR 1573. 1470. 1366. 1259. 1150. 1039. 926. 810. 693. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 31. 29. 27. 24. 22. 20. 18. 15. 13. PRINCIPAL PAYMENTS 103. 105. 107. 109. 111. 113. 116. 118. 120. TOTAL PAYMENTS 133. 133. 133. 133. 133. 133. 133. 133. 133. BALANCE AT END OF YEAR 1470. 1344. 1259. 1150. 1039. 926. 810. 693. 572. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(82, 20YR) TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) CONTRACT YEAR 2001 2002 2003 2004 2005 2006 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE 4260 3 1967 3 1972 4000. 2.000 35.0 5.0 2 2002 11.102/$1, 000, 000 BALANCE AT START OF YEAR 176. 1. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 2. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 175. 1. 0. 0. 0. 0. TOTAL PAYMENTS 178. 1. 0. 0. 0. 0. BALANCE AT END OF YEAR 1. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 4270 6 1967 6 1972 3443. 2.000 35.0 5.0 3 2002 11. 102/$1, 000, 000 BALANCE AT START OF YEAR 189. 39. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 3. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 150. 39. 0. 0. 0. 0. TOTAL PAYMENTS 153. 39. 0. 0. 0. 0. BALANCE AT END OF YEAR 39. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 4280 & 1967 & 1970 2151. 2.000 35.0 3.0 5 2002 10.596/$1, 000, 000 BALANCE AT START OF YEAR 134. s. 0. 0. 0. 5 ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 2. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 89. 5. 0. 0. 0. 0. TOTAL PAYMENTS 91. 5. 0. 0. 0. 0. BALANCE AT END OF YEAR %. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 4300 12 1969 12 1974 4460. 2.000 35.0 5.0 11 2004 11. 102/61, 000, 000 BALANCE AT START OF YEAR 760. 576. 388. 196. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 14. 10. 6. 2. 0. 0. PRINCIPAL PAYMENTS 184, 188. 192. 196. 0. 0. TOTAL PAYMENTS 198. 198. 198. 198. 0. 0. BALANCE AT END OF YEAR 576. 388. 196. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 4310 9 1970 9 1975 3000. 2.000 35.0 5.0 8 2005 11.102/$1, 000, 000 BALANCE AT START OF YEAR 372. 450. 324. 197. 66. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 11. 8. 6. 3. 1. 0. PRINCIPAL PAYMENTS 123. 125. 128. 130. 66. 0. TOTAL PAYMENTS 133. 133. 133. 133. 67. 0. BALANCE AT END OF YEAR 450. 324. 197. 64. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 2007 PAGE: 141 DATE: 21-May-83 TIME: 10:17 FILES: CHNGT.D1 GASGT.D2 VERSION: FIN. FORE. 2008 2009 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 142 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:17 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(B8Z, 20YR) VERSION: FIN. FORE. TABLE 10 LONG-TERM DEBT - EXISTING ($1, 000) CONTRACT YEAR 2010 2011 2012 2013 2014 2015 LOAN EXE DATE BAS DATE AMOUNT APR TERN DEFR MAT DATE QTLY AMORT RATE 4260 3. 1967 3 1972 4000. 2.000 35.0 5.0 2 2002 11. 102/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 4270 6 1967 6 1972 3443. 2.000 35.0 5.0 3 2002 11. 102/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 4280 & 1967 & 1970 2151. 2.000 35.0 3.0 3 2002 10.596/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 5 ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. o. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 4300 _12. 1969 12 1974 4460. 2.000 35.0 5.0 11 2004 11.102/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 4310 9 1970 9 1975 3000. 2.000 35.0 5.0 8 2005 11.102/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. CHUGACH, PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE 4320 10 1970 10 1973 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 4330 1 1972 1 1977 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 4340 5 1972 3 1977 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 4350 1 1973 1 1978 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 1B380 4 1974 4 1977 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT - BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM HOMER & MATANUSKA ELEC. ASSOCIATIONS 1983 APR 2.000 3166. 0. 62, i111. 174. 3055. 0. 4096, 4992. 2. 4218. 83. 138. 222. 0. 2.000 1449. 0. 29. 47. 76. 1402. 0. 1702. 1626. 2.000 1418. 28. 44. 72. 1373. 0. 11446. 5.000 10477. 0. 520. 199. 719. 10278. 0. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) 1984 1985 1986 TERM DEFR MAT DATE 35.0 3.0 9 2005 3055. 2942. 2826. 0. 0. 0. 60. 38. 56. 113. 116. 118. 174, 174. 174. 2942. 2826. 2708. 0. 0. 0. 35.0 5.0 12 2006 4080. 3938. 3795. 0. ' 0. 0. 81. 78. 73. 141. 144. 147. 222. 222. 222. 3938. 3795. 3648. 0. 0. 0. 35.0 5.0 4 2007 1402. 1354. 1306. 0. 0. 0. 28. 27. 26. 48. 49. 50. 76. 76. 76. 1354. 1306. 1256. 0. 0. 0. 35.0 5.0 12 2007 1373. 1328. 1282. 0. 0. 0. 27. 26. 25. 45. 4%. 47. 72. 72. 72. 1328. 1282. 1235. 0. 0. 0. 35.0 3.0 3 2009 10278. 10070. 9850. 0. 0. 0. 510. 499. 488. 209. 219. 231. 719. 719. 719. TC 9850. —— 1987 1988 QTLY AMORT RATE 10.596/$1, 000, 000 2708. 2588. 0. 0. 33. 31. 120. 123. 174, 174, 2588. 2465. 0. 0. 11. 102/61, 000, 000 3648. 3498. 0. 0. 72. 69. 150. 153. 222. 222. 3498. 3345. 0. Oo. 11. 102/61, 000, 000 1256. 1205. 0. 0. 25. 24. si. 52. 76. 76. 1205. 1153. 0. 0. 11.102/$1, 000, 000 1235. 1188. 0. 0. 24. 23. 48. 49. 72. 72. 1188. 1139. 0. 0. 15.702/$1, 000, 000 9619. 9377. 0. 0. 476. 464. 242. 255. 719. 719. 9377. 9122. 0. 0. 1989 PAGE: 143 DATE: 21-May-83 TIME: 10:17 FILES: CHMGT.D1 GASGT..D2 VERSION: FIN. FORE. 1990 1991 2340. 2212. 0. 0. 4%. 43. 128. 130. 174, 174, 2212. 2082. 0. 0. 3189. 3030. 0. 0. 63. 39. 159. 162. 222. 222. 3030. 2868. 0. 0. 1100. 1044. 0. 0. 22. 21. 34. 55. 76. 76. 1044. 991. 0. 0. 1089. 1038. 0. 0. 21. 20. 51. 52. 72. 72. 1038. 986. 0. 0. 8854. 8573. 0. 0. 437. 423. 281. 296. 719. 719. 8573. 9277. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 144 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TINE: 10:17 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) VERSION: FIN. FORE. TABLE 10 LONG-TERM DEBT - EXISTING ($1, 000) CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE 4320 10 1970 10 1973 4076. 32.000 35.0 3.0 9 2005 10.596/$1, 000, 000 BALANCE AT START OF YEAR 2082. 1949. 1813. 1675. 1534. 1390. 1243. 1093. 940. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 41. 38. 35. 32. 30. 27. 24. 21. 18. PRINCIPAL PAYMENTS 133. 134. 138. 141. 144. 147. 150. 153. 154. TOTAL PAYMENTS 174, 174. 174. 174, 174. 174, 174. 174, 174. BALANCE AT END OF YEAR 1949. 1813. 1675. 1534. 1390. 1243. 1093. 940. 784. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 4330 1 1972 1 1977 4992. 2.000 35.0 5.0 12 2006 11.102/$1, 000, 000 BALANCE AT START OF YEAR 2868. 2702. 2533. 2361. 2185. 2006. 1823. 1636. 1446. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 36. 53. 49. 46. 42. 39. 35. 31. 27. PRINCIPAL PAYMENTS 166. 169. 172. 176. 179. 183. 187. 190. 194. TOTAL PAYMENTS 222. 222. 222. 222. 222. 222. 222. 222. 222. BALANCE AT END OF YEAR 2702. 2533. 2361. 2185. 2006. 1823. 1636. 1446. 1251. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 4340 5 1972 3 1977 1702. 2.000 35.0 5.0 4 2007 11.102/$1, 000, 000 BALANCE AT START OF YEAR 971. 935. 878. 819. 760. 699. 637. 573. 509. ADVANCES DURING THE YEAR 0. o. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 19. 18. 17. 16. 15. 14. 12. 11. 10. PRINCIPAL PAYMENTS 36. 37. 38. 60. 61. 62. 63. 65. 64. TOTAL PAYMENTS 76. 7b. 76. 76. 76. 76. 76. 76. 76. BALANCE AT END OF YEAR 935. 878. 819. 760. 699. 637. 573. 509. 443. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 4350 1 1973 1 1978 1626. 2.000 35.0 5.0 12 2007 11.102/$1, 000, 000 BALANCE AT START OF YEAR 986. 934. 880. 825. 769. 711. 653. 593. 533. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 19. 18. 17. 16. 15. 14. 13. 11. 10. PRINCIPAL PAYMENTS 33. 54. 55. 36. 57. 58. 60. 61. 62. TOTAL PAYMENTS 72. 72. 72. 72. 72. 72. 72. 72. 72. BALANCE AT END OF YEAR 934. 880. 825. 769. 711. 653. 593. 533. 471. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 1B380 4 1974 4 1977 11446. 5.000 35.0 3.0 3 2009 15.702/$1, 000, 000 BALANCE AT START OF YEAR 8277. 7966. 7640. 7297. 6936. 6557. 6158. 5739. 5299. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 408. 392. 376. 358. 340. 320. 300. 279. 256. PRINCIPAL PAYMENTS 311. 327. 343. 361. 379. 398. 419. 440. 463. TOTAL PAYMENTS 719. 719. 719. 719. 719. 719. 719. 719. 719. BALANCE AT END OF YEAR 7966. 7640. 7297. 6936. 6557. 6158. 5739. 3299. 4837. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. ‘ f i = = MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE 4320 10 1970 10 1973 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 4330 1 1972 1 1977 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 4340 3 1972 3 1977 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 4350 1 1973 1 1978 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 1B380 4 1974 4 1977 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 2001 AMOUNT APR 4096. _ 2.000 -_ 14. 159. 174, 625. 0. 4992. 2.000 1251. 24. 198. 1053. 0. 1702. 2.000 67. 76. 376. 0. 2.000 471. 9. 63. 72. 407. 0. 11444. 5.000 4837. 0. 233. 484. 719. 4351. 1626. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) 2002 2003 2004 2005 2006 TERM DEFR MAT DATE QTLY AMORT RATE 3.0 3.0 9 2005 10.596/$1, 000, 000 625. 462. 297. 128. 0. 0. 0. 0. 0. 0. 11. 8. 3. 1. 0. 162. 164. 169. 128. 0. 174. 174. 174, 129. 0. 462. 297. 128. 0. 0. 0. 0. 0. 0. 0. 35.0 5.0 12 2006 11. 102/$1, 000, 000 1053. 851. 645. 435. 220. 0. 1 QO. 0. 0. 0. 20. 15. 11. 7. 3. 202. 206. 210. 215. 219. 222. 222. 222. 222. 222. 851. 645. 435. 220. 1. 0. 0. 0. 0. 0. 3.0 5.0 4 2007 11. 102/$1, 000, 000 376. 307. 237. 166. 93. 0. 0. 0. 0. 0. 7. 6. 4. 3. 1. 69. 70. 71. 73. 74. 76. 76. 76. 76. 76. 307. 237. 166. 93. 19. 0. 0. 0. 0. 0. 3.0 5.0 12 2007 11.102/$1, 000, 000 407. 343. 277. 210. 141. 0. 0. 0. 0. 0. 8. 6. 5. 4. 2. 65. 64. 67. 69. 70. 72. 72. 72. 72. 72. 343. 277. 210. 141. 71. 0. 0. 0. 0. 0. 35.0 3.0 3 2009 15.702/$1, 000, 000 4331. 3840. 3303. 2739. 2146. 0. 0. 0. 0. 0. 208. 182. 155. 126. 96. S11. 537. 564. 593. 623. 719. 719. 719. 719. 719. 3840. 3303. 2739. 2146. 1523. 0. 0. 0. 0. 0. 2007 1523. 719. 848. 0. PAGE: 145 DATE: 21-May-83 TIME: 10:17 FILES: CHNGT.D1 GASGT.D2 VERSION: FIN. FORE. 2008 2009 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 868. 179. 0. 0. 31. 2. 688. 179. 719. 182. 179. 0. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: €2-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE 4320 10 1970 10 1973 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 4330 1 1972 1 1977 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 4340 3 1972 3 1977 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 4350 1 1973 1 1978 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 1B380 4 1974 4 1977 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 1702. 1626. 11446. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) 2011 2012 2013 TERM DEFR MAT DATE 35.0 3.0 9 2005 0. 0. 0. 0. 0. 0: 0. 0: 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 35.0 5.0 12 2006 0. 0. 0. 0. 0. 0. 0. 0. 0: 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0: 35.0 5.0 4 2007 0. 0. 0. 0. 0. 0: 0. 0: 0. 0. 0. 0: 0. 0. 0. 0. 0: 0: 0. 0. 0. 35.0 5.0 12 2007 0. 0. 0. 0: 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 35.0 3.0 3 2009 0. 0. 0. 0: 0. 0. 0. 0. 0: 0: 0: 0. 0. 0. 0: 0. 0. 0. 0. 0. 0. 2014 2015 QTLY AMORT RATE 10.596/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 11. 102/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 11.102/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. ii. — 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 15.702/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. PAGE: 144 DATE: 21-May-83 TIME: 10:17 FILES: CHNGT.D1 GASGT.D2 VERSION: FIN. FORE. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE 1B382 4 1974 4 1977 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 18390 8 1976 8 1979 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 1B392 8 1976 8 1979 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 14400 3 1977 3 1982 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 18410 6 1977 & 1980 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT TABLE 10 LONG-TERM DEBT ~ EXISTING ($1, 000) 1983 1984 1985 1986 1987 1988 AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE 11133. 5.000 35.0 3.0 3 2009 15.702/$1, 000, 000 10191. 9998. 9795. 9581. 9357. 9121. 0. 0. 0. 0. 0. 0. 306. 496. 486. 475. 463. 1. 193. 203. 213. 224. 236. 248. 699. 699. 699. 699. 699. 699. 9998. 9795. 9581. 9357. 9121. 8873. 0. 0. 0. 0. 0. 0. 10462. 5.000 35.0 3.0 7 2011 15.702/$1, 000, 000 9953. 9791. 9620. 9441. 9252. 9054. 0. 0. 1 0. 0. 0. 0. 495. 486. 478. 469. 459. 449. 162. 171. 179. 189. 198. 208. 657. 657. 657. 657. 657. 657. 9791. 9620. 9441. 9252. 9054. 8846. 0. 0. 0. 0. 0. 0. 7015. 5.000 35.0 3.0 7 2011 15.702/$1, 000, 000 6674. 6565. 6451. 6330. 6204. 6071. 0. 0. 0. 0. 0. 0. 332. 326. 320. 314. 308. 301. 109. 114. 120. 126. 133. 140. 44. 441. 441. 441. 441. 441. 6565. 6451. 6330. 6204. 6071. 5931. 0. 0. 0. 0. 0. 0. 12655. 5.000 35.0 5.0 4 2012 16. 133/$1, 000, 000 12515. 12321. 12116. 11902. 11676. 11439. 0. 0. 0. 0. 0. 0. 622. 612. 602. 591. 579. 347. 195. 204. 215. 226. 297. 249. 817. 817. 817. 817. 817. 817. 12321. 12114. 11902. 11676. 11439. 11189. 0. 0. 0. 0. 0. 0. 2614. 5.000 35.0 3.0 3 2012 15.702/$1, 000, 000 2516. 2477. 2436. 2393. 2347. 2300. 0. 0. 0. 0. 0. 0. 125. 123. 121. 119. 116. 114. 39. 41. 43. 5. 48. 50. 164. 164. 164. 164. 164. 164. 2477. 2436. 2393. 2347. 2300. 2250. 0. 0. 0. 0. 0. 0. 1989 8873. 0. 260. 699. 8613. 0. 8846. 219. 657. 84627. 0. 5931. 2197. PAGE: 147 DATE: 21-May-83 TIME: 10:17 FILES: CHMGT.D1 GASGT.D2 VERSION: FIN. FORE. 1990 1991 8613. 8339. 0. 0. 426. 412. 274. 288. 699. 699. 8339. 8052. 0. 0. 8627. 8397. 0. 0. 427. 415. 230. 242. 657. 657. 8397. 8155. 0. 0. 5785. 3630. 0. 0. 286. 279. 154. 162. 441. 441. 3630. 3448. 0. 0. 10927. 10652. 0. 0. 341. 527. 275. 289. 817. 817. 10652. 10362. 0. 0. 2197. 2141. 0. 0. 109. 106. 35. 38. 164. 164. 2141. 2083. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 148 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TINE: 10:17 PROJECT: 82-113-4-000 FILES: CHNGT.D1i BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) VERSION: FIN. FORE. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE 18382 4 1974 4 1977 11133. 5.000 35.0 3.0 3 2009 15.702/$1, 000, 000 BALANCE AT START OF YEAR 8052. 7749. 7432. 7098. 6747. 6378. 5991. 3584. 5156. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 397. 382. 365. 348. 331. 312. 292. 271. 249. PRINCIPAL PAYMENTS 302. 318. 334. 351. 369. 388. 407. 428. 450. TOTAL PAYMENTS 699. 699. 699. 699. 699. 699. 699. 699. 699. BALANCE AT END OF YEAR 7749. 7432. 7098. 6747. 6378. 5991. 5584. 5156. 4706. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 1B390 8 1976 8 1979 10462. 5.000 35.0 3.0 7 2011 15.702/$1, 000, 000 BALANCE AT START OF YEAR 8155. 7901. 7634. 7354. 7059. 6749. 6423. 6081. 5721. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 403. 390. 377. 362. 347. 331. 315. 297. 279. PRINCIPAL PAYMENTS 254. 267. 281. 295. 310. 326. 342. 360. 378. TOTAL PAYMENTS 657. 657. 657. 657. 657. 657. 657. 657. 657. BALANCE AT END OF YEAR 7901. 7634. 7354. 7059. 6749. 6423. 6081. 5721. 3343. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 1B392 8 1976 8 1979 7015. 5.000 35.0 3.0 7 2011 15.702/$1, 000, 000 BALANCE AT START OF YEAR 3468. 5298. 5119. 4931. 4733. 4525. 4307. 4077. 3836. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 270. 262. 252. 243. 233. 222. 211. 199. 187. PRINCIPAL PAYMENTS 170. 179. 188. 198. 208. 218. 230. 241. 233. TOTAL PAYMENTS 441. 441. 441. A441. 441. 441. 441. 441. 441. BALANCE AT END OF YEAR 5298. 5119. 4931. 4733. 4525. 4307. 4077. 3836. 3583. INTEREST CHARGEO TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 14400 5 1977 5S 1982 12655. 5.000 35.0 5.0 4 2012 16. 133/$1, 000, 000 BALANCE AT START OF YEAR 10362. 10058. 9738. 9402. 9049. 8678. 8288. 7878. 7447. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 312. 497. 481. 464. 446. 427. 47. 386. 364. PRINCIPAL PAYMENTS 304. 320. 336. 353. 371. 390. 410. 431. 453. TOTAL PAYMENTS 817. 817. 817. 817. 817. 817. 817. 817. 817. BALANCE AT END OF YEAR 10058. 9738. 9402. 9049. 8678. 8288. 7878. 7447. 6995. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 1B410 6 1977 6 1980 2614. 5.000 35.0 3.0 3 2012 15.702/$1, 000, 000 BALANCE AT START OF YEAR 2083. 2022. 1958. 1890. 1819. 1745. 1664. 1584. 1497. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 103. 100. 97. 93. 90. 84. 82. 78. 73. PRINCIPAL PAYMENTS 61. 64. 68. 71. 73. 78. 82. 87. 91. TOTAL PAYMENTS 164. 164. 164. 164. 164. 164. 164. 164. 164. BALANCE AT END OF YEAR 2022. 1958. 1890. 1819. 1745. 1666. 1584. 1497. 1404. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. CHUGACH, HOMER & MATANUSKA ELEC. ‘ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE 1B382 4 1974 4 1977 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 1B390 8 1976 8 1979 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 1B392 8 1976 8 1979 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 14400 3 1977 3 1982 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 1B410 6 1977 6 1980 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYNENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) 2001 2002 2003 2004 2005 2006 AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE 11133. 5.000 35.0 3.0 3 2009 15. 702/$1, 000, 000 4706. 4233. 3736. 3214. 2665. 2089. 0. 0. 0. 0. 0. 0. 227. 202. 177. 151. 123. 93. 473. 497. 522. 349. 577. 606. 699. 699. 699. 699. 699. 699. 4233. 3736. 3214. 2665. 2089. 1483. 0. 0. 0. 0. 0. 0. 10462. 5.000 35.0 3.0 7 2011 15.702/$1, 000, 000 5343. 4946. 4528. 4089. 3628. 3143. 0. 0. 1 O. 0. 0. 0. 260. ‘ 240. 218. 194. 172. 148. 397. 418. 439. 441. 485. 509. 657. 657. 657. 657. 657. 657. 4946. 4528. 4089. 3628. 3143. 2634. 0. 0. 0. 0. 0. 0. 7015. 5.000 35.0 3.0 7 2011 15.702/$1, 000, 000 3583. 3316. 3036. 2742. 2433. 2108. 0. 0. 0. 0. 0. 0. 174. 161. 146. 131. 116. 99. 266. 280. 294, 309. 325. 342. 441. 441. 441. 441. 441. 441. 3316. 3036. 2742. 2433. 2108. 1766. 0. 0. 0. 0. 0. 0. 12655. 5.000 35.0 5.0 4 2012 16. 133/$1, 000, 000 6995. 6519. 6019. 5494. 4741. 4361. 0. 0. 0. 0. 0. 0. 341. 317. 271. 264. 236. 207. 476. 500. 325. 352. 580. 610. 817. 817. 817. 817. 817. 817. 6519. 6019. 3494. 49741. 4361. 3751. 0. 0. 0. 0. 0. 0. 2614. 5.000 35.0 3.0 3 2012 15.702/$1, 000, 000 1406. 1311. 1210. 1104. 993. 877. 0. 0. 0. 0. 0. 0. 69. 64. 59. 33. 48. 42. 9. 101. 104. 111. 117. 123. 164. 164. 164. 164. 164. 164. 1311. 1210. 1104. 993. 877. 734. 0. Ou 0. 0. 0. 0. 2007 1483. 1766. 1407. 3751. 176. 641. 817. 3110. 0. 734. 0. 129. 164. 625. 0. PAGE: 149 DATE: 21-May-83 TIME: 10:17 FILES: CHNGT.D1 GASGT.D2 VERSION: FIN. FORE. 2008 2009 846. 177. 0. 0. 30. 2. 669. 177. 699. 179. 177. 0. 0. 0. 2099. 1536. 0. 0. 95. 66. 343. 591. 657. 657. 1536. 945. 0. 0. 1407. 1030. 0. 0. 63. 44, 377. 396. 441. 441. 1030. 634. 0. 0. 3110. 2436. 0. 0. 143. 109. 674. 708. 817. 817. 2436. 1728. 0. 0. 625. 490. 0. 0. 29. 22. 135. 142. 164. 164, 490. 348. 0. 0. CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE 1B382 4 1974 4 1977 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 18390 8 1976 8 1979 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 1B392 8 1976 8 1979 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 14400 Lora 3 1982 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 1B410 6 1977 & 1980 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN 2010 AMOUNT = APR 11133. 10462. 7015. 12655. 2614, 5.000 0. 0. 0. 0. 0. 0. 0. 5.000 945. 0. 36. 621. 657. 324. 0. 5.000 634. 0. 24. 417. 441. 217. 0. 3.000 1728. 0. 73. 744. 817. 984. 0. 5.000 348. 0. 15. 150. 164. 198. 0. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) 2011 2012 2013 TERM DEFR ‘MAT DATE 35.0 3.0 3 2009 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0: 0. 0. 0: 0. 0. 0. 0. 0. 0. 35.0 3.0 7 2011 324, 0. 0. 0. 0. 0. é 0. 0. 324. 0. 0: 330. 0. 0. 0: 0. 0. 0. 0. 0. 35.0 3.0 7 2011 2i7. 0. 0. 0. 0. 0: 4. 0. 0: 217. 0. 0. 221. 0. 0. 0. 0. 0: 0. 0. 0. 35.0 5.0 4 2012 984. 202. 0. 0. 0. 0. 35. 3. 0. 782. 202. 0. B17. 205. 0. 202. 0. 0. 0. 0. 0. 35.0 3.0 5 2012 198. 41. 0. 0. 0. 0. 7: 1. 0. 157. 41. 0. 144. 41. 0. At: 0. 0. 0. 0. 0. 2014 2015 QTLY AMORT RATE 15.702/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 15.702/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 15.702/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 16. 133/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 15.702/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. PAGE: 150 DATE: 21-May-83 TIME: 10:17 FILES: CHNGT.D1 GASGT.D2 VERSION: FIN. FORE. CHUGACH, PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE 1B420 11 1978 11 1981 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT ARR 4 1960 4 1960 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT M 4070 & 1958 & 1961 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT $ 4100 & 1962 6 1965 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT Y 4160 2 1968 2 1971 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM HOMER & MATANUSKA ELEC. ASSOCIATIONS TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) 1983 “1984 1985 1986 AMOUNT APR TERM DEFR MAT DATE 11192. 5.000 35.0 3.0 10 2013 11009. 10854. 10690. 10519. 0. 0. 0. 0. 348. 340. 331. 523. 155. 163. 172. 180. 703. 703. 703. 703. 10854. 10690. 10519. 10338. 0. 0. 0. 0. 1351. 2.500 25.0 0.0 3 1985 107. 36. 0. 0. 0. 0. 0. 0. 2. 0. 0. 0. 71. 34. 0. 0. 73. 34. 0. 0. 36. 0. 0. 0. 0. 0. 0. 0. 955. 2.000 35.0 3.0 3 1993 383. 350. 316. 281. 0. 0. 0. 0. 7. 7. 6. 5. 33. 34. J. 35. 40. 4. 40. 40. 350. 316. 281. 246. 0. 0. 0. 0. 375. 2.000 35.0 3.0 3 1997 200. 188. 176. 163. 0. 0. 0. 0. 4. 4. 3. 3. 12. 12. 12. 13. 14. 16. 16. 16. 188. 176. 143. 150. 0. 0. 0. 0. 2628. 2.000 35.0 3.0 1 2003 1851. 1776. 1699. 1621. 0. 0. 0. 0. 34. 33. 33. 32. 73. 76. 78. 80. 111. 111. 111. 111. 1776. 1699. 1621. 1542. 0. %. 0. 0. 1987 1988 QTLY AMORT RATE 15. 702/$1, 000, 000 10338. 10149. 0. 0. 513. 504. 190. 199. 703. 703. 10149. 9950. 0. 0. 13. 479/61, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 10.596/$1, 000, 000 2%. 210. 0. 0. 5. 4. 34. 37. 4. 4. 210. 174. 0. 0. 10.596/$1, 000, 000 150. 137. 0. 0. 3. 3. 13. 13. 14. 16. 137. 124. 0. 0. 10. 596/$1, 000, 000 1542. 1441. 0. 0. 30. 29. 81. 83. 111. i111. 1441. 1378. 0. 0. PAGE: 151 DATE: 21-May-83 TIME: 10:17 FILES: CHMGT.D1 GASGT..D2 VERSION: FIN. FORE. 1989 1990 1991 9950. 9740. 9520. 0. 0. 0. 494, 483. 472. 209. 220. 231. 703. 703. 703. 97%. 9520. 9289. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. Oo. 0. 0. 0. 0. 0. Oo. 0. 0. 0. 174. 137. 99. 0. 0. 0. 3. 2. 2. 37. 38. 39. 4. x. 4. 137. 99. 60. 0. 0. 0. 124. 111. 97. 0. 0. 0. 2. 2. 2. 14. 14. 14. 16. 16. 16. 111. 97. 83. o. 0. 0. 1378. 1293. 1207. 0. 0. 0. 27. 2. 23. 84. 84. 88. 111. 111. 111. 1293. 1207. 1119. 0. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 152 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:17 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) VERSION: FIN. FORE. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR NAT DATE QTLY AMORT RATE 1B420 11 1978 11 1981 11192. 5.000 35.0 3.0 10 2013 15.702/$1, 000, 000 BALANCE AT START OF YEAR 9289. 9044. 8791. 8522. 8240. 7944. 7632. 7HS. 6961. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 460. 448. 435. 421. 47. 3971. 376. 359. 341. PRINCIPAL PAYMENTS 243. 255. 268. 282. 296. 312. 327. 344. 362. TOTAL PAYMENTS 703. 703. 703. 703. 703. 703. 703. 703. 703. BALANCE AT END OF YEAR 9046. 8791. 8522. 8240. 7944. 7632. 7305. 6961. 6599. INTEREST CHARGED TO CONSTR-CREDIT 0. oO. 0. 0. 0. 0. 0. 0. 0. ARR 4 1960 4 1960 1351. 2.500 25.0 0.0 3 1985 13. 479/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. nN 4070 6 1958 & 1961 955. 2.000 35.0 3.0 3 1993 10.596/$1, 000, 000 BALANCE AT START OF YEAR 60. 20. 0. 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 1. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 4. 20. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 40. 20. 0. 0. 0. 0. 0. 0. 0. BALANCE. AT END OF YEAR 20. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. S$ 4100 & 1962 6 1965 375. 2.000 35.0 3.0 3 1997 10.596/$1, 000, 000 BALANCE AT START OF YEAR 83. 68. 34. 39. 23. 8. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 2. 1. 1. 1. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 14. 15. 15. 15. 16. 8. 0. 0. 0. TOTAL PAYMENTS 16. 16. 16. 14. 16. 8. 0. 0. 0. BALANCE AT END OF YEAR 68. 54. 37. 23. 8. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. Y 4160 2 1968 2 1971 2628. 2.000 35.0 3.0 1 2003 10.596/$1, 000, 000 BALANCE AT START OF YEAR 1119. 1030. 938. 845. 750. 653. 554. 453. 350. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 22. 20. 18. 16. 14. 12. 10. 8. 4. PRINCIPAL PAYMENTS 90. 91. 93. 95. 97. 99. 101. 103. 105. TOTAL PAYMENTS 111. 111. 111. 111. 111. 111. 111. 111. 111. BALANCE AT END OF YEAR 1030. 938. 845. 750. 653. 554. 453. 350. 244, INTEREST CHARGEO TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. Saree asain au oy) feanorome feed temas a ewer tems A i Ls ae BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(&X, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE 18420 11 1978 11 1981 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT ARR 4 1960 4 1960 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT fH 4070 & 1958 & 1961 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT § 4100 & 1962 & 1965 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGEO TO CONSTR-CREDIT Y 4160 2 1968 2 1971 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 2001 AMOUNT APR 11192. 1351. 955. 375. 2628. 5.000 6599. 323. 380. 703. 6219. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) 2002 2003 2004 TERM DEFR MAT DATE 35.0 3.0 10 2013 6219. 5820. 3400. 0. 0. 0. 304. 283. 262. 399. 420. 441. 703. 703. 703. 3820. 5400. 4959. 0. 0. 0. 3.0 0.0 3 1985 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. a. 0. 0. 0. 0. 0. 35.0 3.0 3 1993 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 35.0 3.0 5 1997 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 35.0 3.0 1 2003 137. 28. 0. 0. 0. 0. 2. 0. 0. 109. 28. 0. 111. 28. 0. 28. 0. 0. 0. 0. 0. 2005 2006 Q@TLY AMORT RATE 15.702/$1, 000, 000 4959. 4496. 0. 0. 239. 216. 464. 487. 703. 703. 4496. 4008. 0. 0. 13. 479/61, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 10.596/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 10.596/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 10.596/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 2007 4008. 191. 512. PAGE: 153 DATE: 21-May-83 TINE: 10:17 FILES: CHMGT.01 GASGT.02 VERSION: FIN. FORE. 2008 2009 3496. 2958. 0. 0. 165. 137. 338. 5446. 703. 703. 2958. 2393. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 154 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TINE: 10:17 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) VERSION: FIN. FORE. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) CONTRACT YEAR 2010 2011 2012 2013 2014 2015 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR NAT DATE QTLY AMORT RATE 18420 11 1978 11° 1981 11192. 5.000 35.0 3.0 10 2013 15.702/$1, 000, 000 BALANCE AT START OF YEAR 2393. 1798. 1174. 517. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 109. 78. a. 13. 0. 0. PRINCIPAL PAYMENTS 594. 625. 656. 517. 0. 0. TOTAL PAYMENTS 703. 703. 703. 530. 0. 0. BALANCE AT END OF YEAR 1798. 1174, 517. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. ARR 4 1960 4 1960 1351. 2.500 25.0 0.0 3 1985 13. 479/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. nM 4070 6 1958 6 1961 955. 2.000 35.0 3.0 3 1993 10.596/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. S$ 4100 6 1962 & 1965 375. 2.000 35.0 3.0 3 1997 10.596/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. Y 4160 2 1968 2 1971 2628. 2.000 35.0 3.0 1 2003 10.596/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 155 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:17 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSHISSION COOP. PLAN: GAS(8Z, 20YR) VERSION: FIN. FORE. TABLE 10 LONG-TERM DEBT - EXISTING (41, 000) CONTRACT YEAR 1983 1984 1985 1986 1987 1988 1989 1990 1991 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE AB6 4180 3 1974 3 1977 495. 5.000 35.0 3.0 2 2009 15.702/$1, 000, 000 BALANCE AT START OF YEAR 453. 444. 435. 426. 416. 5. 394. 383. 371. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 22. 22. 22. 21. ai. 20. 19. 19. 18. PRINCIPAL PAYMENTS 9. 9. 9. 10. 10. 11. 12. 12. 13. TOTAL PAYMENTS 31. 31. 31. 31. 31. 31. 31. 31. 31. BALANCE AT END OF YEAR 444, 435. 426. 416. 05. 394. 383. 371. 358. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. AHS 10242 3 1978 3 1981 762. 5.000 35.0 3.0 2 2013 15.702/$1, 000, 000 BALANCE AT START OF YEAR 744. 733. 722. 710. 697. 684. 670. 655. 640. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 37. 36. 36. 35. 35. 34. 33. 32. 32. PRINCIPAL PAYMENTS 11. 11. 12. 13. 13. 14. 15. 15. 16. TOTAL PAYMENTS 48. 48. 4B. 48. 48. 48. 48. 48. 48. BALANCE AT END OF YEAR 733. 722. 710. 697. 684. 670. 655. 640. 624. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. AK6 18250 3 1978 3S 1981 845. 5.000 35.0 3.0 4 2013 15.702/$1, 000, 000 BALANCE AT START OF YEAR 828. 814. 804. 791. 777. 763. 747. 731. 714. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 41. 41. 4%. 39. 39. 38. 37. 34. 35. PRINCIPAL PAYMENTS 12. 12. 13. 14. 14. 15. 16. 17. 18. TOTAL PAYMENTS 53. 33. 53. 33. 53. 53. 33. 53. 33. BALANCE AT END OF YEAR 816. 804. 791. 777. 763. 747. 731. 714. 697. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. Y 4220 10 1969 10 1972 12. 2.000 35.0 3.0 9 2004 10.596/$1, 000, 000 BALANCE AT START OF YEAR 9 9. 8. 8. 8. 7. 7. 4. 6. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. oO. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. o. 0. 0. BALANCE AT END OF YEAR 9. 8. 8. 8. 7. 7. 6. 6. é. INTEREST CHARGED TO CONSTR-CREDIT o. 0. 0. 0. 0. 0. 0. 0. Oo. 2ACS B262 12 1974 12 1977 332. 5.000 35.0 3.0 11 2009 15.702/$1, 000, 000 BALANCE AT START OF YEAR 308. ~ 303. 297. 2a. 284. 278. 271. 263. 255. ADVANCES OURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 15. 15. 15. 14. 14. 14. 13. 13. 13. PRINCIPAL PAYMENTS 6. 6. 6. 6. 7. 7. 7. 8. 8. TOTAL PAYMENTS 21. 21. 21. 2i. 21. 21. 21. 21. 21. BALANCE AT END OF YEAR 303. 297. 271. 284. 278. 271. 263. 255. 247. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 9. 0. 0. 0. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 156 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TINE: 10:17 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT. D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(82, 20YR) VERSION: FIN. FORE. TABLE 10 LONG-TERM DEBT - EXISTING ($1, 000) CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE ABé 4180 3 1974 3 1977 475. 5.000 35.0 3.0 2 2009 15.702/$1, 000, 000 BALANCE AT START OF YEAR 358. 344. 330. 315. 300. 283. 266. 248. 229. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 18. 17. 16. 15. 15. 14. 13. 12. 11. PRINCIPAL PAYMENTS 13. 14, 15. 16. 16. 17. 18. 19. 20. TOTAL PAYMENTS 31. 31. 31. 31. 31. 31. 31. 31. 31. BALANCE AT END OF YEAR 344. 330. 315. 300. 283. 266. 248. 229. 209. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. oO. AHS 1A242 3 1978 3 1981 762. 5.000 35.0 3.0 2 2013 15.702/$1, 000, 000 BALANCE AT START OF YEAR 624. 607. 589. 370. 551. 530. 508. 486. 461. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 31. 30. 29. 26. 27. 26. 23. 24. 23. PRINCIPAL PAYMENTS 17. 18. 19. 20. 21. 22. 23. 24. 2. TOTAL PAYMENTS 48. 48. 48. 48. 4. 4B. 48. 48. 48. BALANCE AT END OF YEAR 607. 589. 570. 551. 530. 508. 486. 461. 436. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. AKS 1B250 3 1978 3 1981 845. 5.000 35.0 3.0 4 2013 15.702/$1, 000, 000 BALANCE AT START OF YEAR 697. 678. 659. 638. 617. 594. 370. 345. 519. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 34. 34. 33. 32. 30. 29. 28. 27. 25. PRINCIPAL PAYMENTS 19. 20. 2i. 22. 23. 24. 23. 26. 28. TOTAL PAYMENTS 53. 53. 33. 53. 53. 53. 33. 53. 53. BALANCE AT END OF YEAR 678. 659. 638. 617. 594. 570. 345. 319. 491. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. Oo. 0. 0. 0. Oo. Y 4220 10 1969 10 1972 12. 2.000 35.0 3.0 9 2004 10.596/$1, 000, 000 BALANCE AT START OF YEAR 4. 5. 3. 4. 4. 4. 3. 3. 2. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 5. 5. 4. 4. 4. 3. 3. 2. 2. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 2AC6 B262 12 1974 12 1977 332. 5.000 35.0 3.0 11 2009 15.702/$1, 000, 000 BALANCE AT START OF YEAR 247. 238. 229. 219. 209. 199. 188. 176. 164. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 12. 12. 11. 11. 10. 10. 9. 9. 8. PRINCIPAL PAYMENTS 9. 9. 10. 10. 11. 11. 12. 12. 13. TOTAL PAYMENTS 21. 2i. 21. 21. 21. 2i. 21. 2i. 21. BALANCE AT END OF YEAR 238. 229. 219. 209. 199. 188. 176. 164. 151. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) CONTRACT YEAR 2001 2002 2003 2004 2005 2006 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE AB6 4180 3 1974 3 1977 495. 5.000 35.0 3.0 2 2009 15. 702/61, 000, 000 BALANCE AT START OF YEAR 209. 188. 166. 143. 118. 93. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 10. 9. 8. 7. 5. 4. PRINCIPAL PAYMENTS 21. 22. 23. 24. 26. 27. TOTAL, PAYMENTS 31. 31. 31. 31. 31. 31. BALANCE AT END OF YEAR 188. 166. 143. 118. 93. 66. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. AH6 1A242 3 1978 3 1981 762. 5.000 35.0 3.0 2 2013 15.702/$1, 000, 000 BALANCE AT START OF YEAR 436. 410. 382. 353. 322. ° ADVANCES DURING THE YEAR 0. 9. 0. 0. 0. 0. INTEREST PAYMENTS 21. 20. 19. 17. 15. 14. PRINCIPAL PAYMENTS 27. 28. 29. 31. 32. 34. TOTAL PAYMENTS 48. 48. 48. 48. 48. 48. BALANCE AT END OF YEAR 410. 382. 353. 322. 289. 255. INTEREST CHARGED TO CONSTR-CREDIT 0. Oo. 0. 0. 0. 0. AK6 18250 3 1978 5 1981 845. 5.000 35.0 3.0 4 2013 15.702/$1, 000, 000 BALANCE AT START OF YEAR 491. 462. 432. 399. 366. 330. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 24. 23. 2i. 19. 18. 16. PRINCIPAL PAYMENTS 29. 31. 32. 34. 35. 37. TOTAL PAYMENTS 53. 33. 53. 53. 53. 53. BALANCE AT END OF YEAR 462. 432. 399. 3664. 330. 293. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. Y 4220 10 1969 10 1972 12. 2.000 35.0 3.0 9 2004 10.596/$1, 000, 000 BALANCE AT START OF YEAR 2. 1. 1. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 1. 1. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 2AC6 B262 12 1974 12 1977 332. 5.000 35.0 3.0 11 2009 15.702/$1, 000, 000 BALANCE AT START OF YEAR 151. 137. 123. 108. 92. 73. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 7. 7. 6. 5. 4. 3. PRINCIPAL PAYMENTS 14. 14. 15. 16. 17. 17. TOTAL PAYMENTS 21. al. ai. 21. 21. 21. BALANCE AT END OF YEAR 137. 123. 108. 92. 730 38. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 6. 0. 0. 0. 2007 254. 0. 0. 0. 0. 0. 38. 0. 18. ai. 4%. 0. PAGE: 157 DATE: 21-May-83 TIME: 10:17 FILES: CHNGT.D1 GASGT.D2 VERSION: FIN. FORE. 2008 2009 37. 8. 0. 0. 1. 0. 30. 8. 31. 8. 8. 0. 0. 0. 220. 182. 0. 0. 10. 8. 38. 39. 48. 48. 182. 143. 0. 0. 254. 213. 0. 0. 12. 10. 41. 43. 53. 53. 213. 169. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. x. 20. 0. 0. 2. 1. 19. 20. 2i. ai. 20. 0. 0. 0. wa BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE AB6 4180 3 1974 3 1977 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT AH6 1A242 3 1978 3 1981 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYHENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT AK6 1B250 3 1978 3 1981 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE. AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT Y 4220 10 1969 10 1972 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYNENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 2AC6 B262 12 1974 12 1977 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 762. 12. 2010 5.000 2013 MAT DATE 0. 0. 0. 0. 0. 0. 0. 2 2013 12. 0. 0. 12. 12. 0. 0. 4 2013 26. 0. 0. 26. 27. 0. 0. 9 2004 0. 0. 0. 0. 0. 0. 0. 11 2009 0. 0. 0. 0. 0. 0. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) 2011 2012 TERM DEFR 35.0 3.0 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 3.0 3.0 101. 38. 0. 0. 4. 2. 44, %. 4B. 48. 58. 12. 0. 0. 3.0 3.0 124, 76. 0. 0. 5. 3. 48. 30. 53. 33. 76. 26. 0. 0. 35.0 3.0 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 35.0 3.0 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 2014 2015 QTLY AMORT RATE 15.702/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 15.702/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 15.702/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 10.596/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 15.702/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. PAGE: 158 DATE: 21-May-83 TIME: 10:17 FILES: CHNCT.D1 GASGT.D2 VERSION: FIN. FORE. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE 2AD6 B270 12 1975 12 1978 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 2AH6-1 ASL 2 1979 2 1982 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 2AH6-2 ASL 2 1979 2 1982 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 1983 AMOUNT APR 1131. 5.000 1067. 0. 53. 18. 71. 1049. 0. 9 5. 98. o. 3. 1. é. 97. 0. 259. 5.000 256. 0. 13. 4. 16. 253. 0. TABLE 10 LONG-TERM DEBT - EXISTING ($1, 000) 1984 1985 1986 TERM DEFR MAT DATE 35.0 3.0 11 2010 1049. 1030. 1010. 0. 0. 0. 52. 1. 50. 19. 20. 21. 71. 71. 71. 1030. 1010. 989. 0. 0. 0. 35.0 3.0 1 2014 97. 95. 94. 0. 0. 0. 5. 5. 5. 1. 1. 2. 6. 6. 6. 9. 94. 92. 0. 0. 0. 35.0 3.0 1 2014 253. 249. 245. 0. 0. 0. 13. 12. 12. 4. 4. 4. 16. 16. 16. 249. 245. 241. 0. 0. 0. 1987 1988 QTLY AMORT RATE 15. 702/61, 000, 000 989. 967. 0. 0. 49. 48. 22. 23. 71. 71. 967. 944. 0. 0. 15. 702/61, 000, 000 92. 91. 0. 0. 3. 4. 2. 2. 6. 4. 71. 89. 0. 0. 15.702/$1, 000, 000 241. 237. 0. 0. 12. 12. 4. 4. 16. 16. 237. 232. 0. 0. 1989 PAGE: 159 DATE: 21-May-83 TIME: 10:17 FILES: CHMGT.D1 GASGT.D2 VERSION: FIN. FORE. 1990 1991 920. 894. 0. 0. 4%. 44. 25. 27. 71. 71. 894. 868. 0. 0. 87. 85. 0. 0. 4. 4. 2. 2. 6. 6. 85. 83. 0. 0. 227. 223. 0. 0. il. 11. 3. 3. 16. 16. 223. 217. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 160 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:17 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) VERSION: FIN. FORE. TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE 2AD6 B270 12 1975 12 1978 1131. 5.000 35.0 3.0 11 2010 15.702/$1, 000, 000 BALANCE AT START OF YEAR 868. 839. 810. 779. 7%. 712. 676. 638. 598. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYNENTS 43. 41. 4. 38. 37. 35. 33. 31. 29. PRINCIPAL PAYMENTS 28. 30. 31. 33. 34. 36. 33. 4. 42. TOTAL PAYMENTS 71. 71. 71. 71. 71. 71. 71. 71. 71. BALANCE AT END OF YEAR 839. 810. 779. 7%. 712. 676. 638. 598. 354. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 2AH6-1 A31 2 1979 2 1982 9. 5.000 35.0 3.0 1 2014 15.702/$1, 000, 000 BALANCE AT START OF YEAR 83. 81. 79. 77. 74. 72. 69. 66. 63. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 4. 4. 4. 4. 4. 4. 3. 3. 3. PRINCIPAL PAYMENTS 2. 2. 2. 2. 3. 3. 3. 3. 3. TOTAL PAYMENTS 6. 6. 6. 4. 6. 6. 6. 6. 4. BALANCE AT END OF YEAR 81. 790 77. 74. 72. 69. 64. 63. 60. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 2AH6-2 ABIL 21979 2 1982 259. 5.000 35.0 3.0 1 2014 15.702/$1, 000, 000 BALANCE AT START OF YEAR 217. 212. 206. 200. 194, 187. 180. 173. 165. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 11. 10. 10. 10. 10. 9 9. 8. 8. PRINCIPAL PAYMENTS 5. 4. 6. 6. 7. 7. 7. 8. 8. TOTAL PAYMENTS 16. 16. 16. 16. 16. 16. 16. 16. 16. BALANCE AT END OF YEAR 212. 206. 200. 194, 187. 180. 173. 165. 157. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE 2AD6 B270 12 1975 12 1978 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 2AH6-1 A31 2 1979 2 1982 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 2AH6-2 AZ1 2 1979 2 1982 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) 2001 2002 2003 2004 2005 2006 AMOUNT APR TERM DEFR MAT DATE 1131. 5.000 35.0 3.0 11 2010 soe QTLY AMORT RATE 556. 512. 466. 417. 2 312. 0. 0. 0. 0. 0. 0. 27. 3. 22. 20. 17. 15. 44. 44. 49. 51. 34. 56. 71. 71. 71. 71. 71. 71. 312. 466. 417. 366. 312. 254. 0. 0. 0. 0. 0. 0. 99. 5.000 35.0 3.0 1 2014 15.702/$1, 000, 000 60. 57. 33. 30. 5 42. 0. 0. 0. 0. 0. 0. 3. 3. 3. 2. 2. 2. 3. 3. 4. 4. 4. 4. 6. 6. 6. 6. 6. 6. 37. 33. 30. %. 42. 38. 0. 0. 0. 0. 0. 0. 259. 5.000 35.0 3.0 1 2014 15.702/$1, 000, 000 157. 148. 139. 130. 120. 109. 0. 9. 0. 0. 0. 0. 8. 7. 7. 6. 6. 3. 9. 9. 9. 10. 10. 11. 16. 16. 16. 14. 16. 16. 148. 139. 130. 120. 109. 98. 0. 0. 0. 0. 0. 0. PAGE: 161 DATE: 21-May-83 TIME: 10:17 FILES: CHMGT.D1 GASGT. D2 VERSION: FIN. FORE. 2008 2009 197. 134, 0. 0. 9. 4. 62. 66. 71. 71. 134. 69. 0. 0. 3. 29. 0. 0. 2. 1. 5. 3. 6. 6. 29. 24. 0. 0. 87. 73. 0. 0. 4. 3. 12. 13. 14. 14. 73. 62. 0. 0. CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE 2AD6 B270 12 1975 12 1978 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 2AH6-1 ASL 2 1979 2 1982 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 2AH6-2 AGL 2 1979 2 1982 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL. PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN 2010 AMOUNT APR 1131. 259. 3.000 TABLE 10 LONG-TERM DEBT - EXISTING ($1,000) 2011 2012 2013 TERN DEFR MAT DATE 35.0 3.0 11 2010 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 35.0 3.0 1 2014 19. 13. 7. 0. 0. 0. 1. 1. 0. 3. 6. 6. 6. 6. 6. 13. 7. 2. 0. 0. 0. 35.0 3.0 1 2014 4B. 34. 20. 0. 0. 0. 2. 1. 1. 14. 15. 16. 16. 16. 14. 34. 20. 4. 0. 0. 0. 2014 2015 QTLY AMORT RATE. a 000, 000 e 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 15.702/$1, 000, 000 2. 0. 0. 0. 0. 0. 2. 0. 2. 0. 0. 0. 0. 0. 15.702/$1, 000, 000 4. 0. 0. 0. 0. 0. 4. 0. 4. 0. 0. 0. 0. 0. PAGE: 162 DATE: 21-May-89 TIME: 10:17 FILES: CHNGT.D1 GASGT.02 VERSION: FIN. FORE. CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE BELUGA 9 1 1984 1 1991 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT BERNICE 5 1 1985 1 1992 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 01 CC 1 2001 1 2008 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 08 CC 1 2008 1 2015 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 13_CC 1 2013 1 2020 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INfEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 1983 AMOUNT APR 25574. 15968. 301500. 1718967. 2525727. om a 8 4 TABLE 11 LONG-TERM DEBT - NEW ($1, 000) 1984 1985 1986 TERM = DEFR MAT DATE 34.0 7.0 12 2017 0. 25574. 25574. 25574. 0. 0. 2813. 2613. 2813. 0. 0. 0. 2813. 2813. 2813. 25574. 25574. 25574. 0. 0. 0. 34.0 7.0 12 2018 0. 0. 15968. 0. 15968. 0. 0. 1756. 1756. 0. 0. 9. 0. 1756. 1756. 0. 15968. 15948. 0. 0. 0. 34.0 7.0 12 2034 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 34.0 7.0 12 2041 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 34.0 7.0 12 2046 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. eee ae BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN 1987 1988 QTLY AMORT RATE 29..051/$1, 000, 000 ay OG: 2813. 2813. 0. 0. 2813. 2813. 25574. 25574. 0. 0. 29.051/$1, 000, 000 15968. 15948. 0. oO. 1756. 1736. 0. 0. 1736. 1736. 15968. 15968. 0. 0. 29.051/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 29.051/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 29..051/$1, 000, 000 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. pra: 1989 25574. 0. 2813. 0. 2813. 25574. 0. oa PAGE: 163 DATE: 21-May-83 TIME: 10:17 FILES: CHMGT.D1 GASGT. D2 VERSION: FIN. FORE. 1990 1991 25574. 25574. 0. 0. 2813. 2807. 0. 165. 2813. 2972. 25574. 25409. 0. 0. 15968. 15968. 0. 0. 1756. 1756. 0. 0. 1734. 1734. 15968. 15968. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. k BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 164 POWER SUPPLY PROGRAN DATE: 21-Hay-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TINE: 10:17 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) VERSION: FIN. FORE. TABLE 11 LONG-TERM DEBT - NEW ($1, 000) CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE BELUGA 9 1 1984 1 1991 25574. 11.000 34.0 7.0 12 2017 29.051/$1, 000, 000 BALANCE AT START OF YEAR 23409. 25225. 25019. 24790. 24535. 24250. 239733. 23580. 23186. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 2788. 2766. 2743. 2717. 2687. 2655. 2618. 2578. 2533. PRINCIPAL PAYMENTS 184. 205. 229. 255. 285. 317. 353. 394. 439. TOTAL PAYMENTS 2972. 2972. 2972. 2972. 2972. 2972. 2972. 2972. 2972. BALANCE AT END OF YEAR 25225. 25019. 24790. 24535. 24250. 23933. 23580. 23186. 22747. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. BERNICE 5 1. 1985 1 1992 15968. 11.000 34.0 7.0 12 2018 297.051/$1, 000, 000 BALANCE AT START OF YEAR 15968. 15865. 15750. 15621. 15478. 15319. 15141. 14943. 14723. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 1752. 174. 1727. 1713. 1696. 1678. 1658. 1635. 1610. PRINCIPAL PAYMENTS 103. 115. 128. 143. 159. 178. 198. 221. 246. TOTAL PAYMENTS 1856. 1854. 1856. 18536. 1856. 1856. 1856. 1856. 1856. BALANCE AT END OF YEAR 15865. 15750. 15621. 15478. 15319. 15141. 14943. 14723. 14477. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 01 CC 1 2001 1 2008 501500. 11.000 34.0 7.0 12 2034 29.051/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 08 CC 1 2008 1 2015 1718967. 11.000 34.0 7.0 12 2041 29.051/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 13 CC 1 2013 1 2020 2525727. 11.000 34.0 7.0 12 2046 29..051/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 9. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 1465 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:17 PROJECT: @2-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) VERSION: FIN. FORE. TABLE 11 LONG-TERM DEBT - NEW ($1,000) CONTRACT YEAR 2001 2002 2003 2004 2005 2006 2007 2008 2009 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE BELUGA 9 1 1984 1 1991 25574. 11.000 34.0 7.0 12 2017 29.051/$1, 000, 000 BALANCE AT START OF YEAR 22747. 22257. 21712. 21104. 20426. 19670. 18828. 17889. 16843. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 2482. 2426. 2364. 2294. 2216. 2130. 2033. 1926. 1806. PRINCIPAL PAYMENTS 489. 546. 608. 678. 756. 842. 939. 1046. 1146. TOTAL PAYMENTS 2972. 2972. 2972. 2972. 2972. 2972. 2972. 2972. 2972. BALANCE AT END OF YEAR 22257. 21712. 21104. 20426. 19670. 18828. 17889. 16843. 15677. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 5 5 0. 0. 0. BERNICE 5 1 1985 1 1992 15968. 11.000 34.0 7.0 12 2018 29.051/$1, 000, 000 BALANCE AT START OF YEAR 14477. 14202. 13897. 13556. 13176. 12753. 12282. 11756. 11170. ADVANCES DURING THE YEAR 0. 9. 0. 0. 0. 5 0. 0. 0. INTEREST PAYMENTS 1581. 1550. 1515. 1476. 1432. 1384. 1330. 1270. 1202. PRINCIPAL PAYMENTS 274. 306. 341. 380. 423. 472. 326. 3864. 653. TOTAL PAYMENTS 1856. 1854. 1854. 1856. 1856. 1854. 1856. 1856. 1856. BALANCE AT END OF YEAR 14202. 13897. 13556. 13176. 12753. 12282. 11756. 11170. 10516. INTEREST CHARGEO TO CONSTR-CREDIT 0. 0. 0. 0. 5 0. 0. 0. 0. 01 CC 1 2001 1 2008 301500. 11.000 34.0 7.0 2034 29.051/$1, 000, 000 BALANCE AT START OF YEAR 0 501500. _— 501500. —— —- 301500. 501500. 498257. ADVANCES DURING THE YEAR 301500. 0. 0. 0. 0. 0. INTEREST PAYNEHTS 55165. 55165. 55165. 55165. 55165. 55165. 55165. 35034. 54663. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. a 0. 3243. 3615. TOTAL, PAYMENTS 55165. 55165. 55165. 55165. 55165. 55165. 55165. 58277. 58277. BALANCE AT END OF YEAR 301500. 501500. 501500. 501500. 501500. 501500. 501500. 498257. 494443. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 08 CC 1 2008 1 2015 1718967. 11.000 34.0 7.0 12 2041 29..051/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 1718967. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 1718967. oO. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 1897086. 189086. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 1897086. 1897086. BALANCE. AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 1718967. 1718967. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 13 CC 1 2013 1 2020 2525727. 11.000 34.0 7.0 12 2046 29.051/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. o 0. 0. 0. 0. 0. 0. CHUGACH, PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE BELUGA 9 1 1984 1 1991 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT BERNICE 5 1 1985 1 1992 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 01 CC 1 2001 1 2008 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 08 CC 1 2008 1 2015 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 13 CC 1 2013 1 2020 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM HOMER. & MATANUSKA ELEC. ASSOCIATIONS 2013 MAT DATE 12 2017 11313. 0. 1172. 1800. 2972. 9513. 0. 12 2018 8072. 0. 847. 1008. 1856. 7064. 0. 12 2034 4811 eS 52698. 5579. 58277. 47' aaa 12 2041 1718967. 187086. 189086. 1718967. 0. 12 2046 0. 2525727. 277830. 277830. 2525727. TABLE 11 LONG-TERM DEBT - NEW ($1, 000) 2010 2011 2012 AMOUNT APR TERM DEFR 25574. 11.000 34.0 7.0 15677. 14377. 12928. 0. 0. 0. 1672. 1523. 1357. 1300. 1449. 1415. 2972. 2972. 2972. 14377. 12928. 11313. 0. 0. 0. 15968, 11.000 34.0 7.0 10516. 9788. 8977. 0. 0. 0. 1127. 1044. 951. 728. 812. 905. 1856. 1856. 1856. 9788. 8977. 8072. 0. 0. 0. 501500. 11.000 34.0 7.0 a7a6mz. a706i4. 986123. 54248. 59786. 53272. 4029. 4491. 5005. 58277. 58277. 58277. 490614. 486123. 481117. 0. 0. 0. 1718967. 11.000 34.0 7.0 1719967. 1718967. 1718967. 189086. 187086. 109086. 199086. 189086. 189086. 1718967. 1718967. 1718967. 0. 0. 0. 2525727. 11.000 34.0 7.0 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. ve roo —— en 2014 2015 QTLY AMORT RATE 29.051/$1, 000, 000 9513. 7307. 0. 0. 966. 736. 2006. 2236. 2972. 2972. 7507. 5271. 0. 0. 29.051/$1, 000, 000 7064. 5940. 0. 0. 732. 603. 1124, 1253. 1856. 1856. 5940. 4687. 0. 0. 29..051/$1, 000, 000 a — 52058. 51346. 6219. 6931. 58277. 58277. 469320. 462388. 0. 0. 29.051/$1, 000, 000 “a salar 189086. 188638. 0. 11116. 189086. 199754. iter vores 29.051/$1, 000, 000 2525727. 2525727. 277830. 277830. 277830. _ 277830. 2525727. 2525727. PAGE: 164 DATE: 21-May-83 TINE: 10:17 FILES: CHNGT.D1 GASGT.D2 VERSION: FIN. FORE. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) TABLE 11 LONG-TERM DEBT - NEW ($1, 000) CONTRACT YEAR 1983 1984 1985 1986 1987 1988 LOAN EXE. DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE 83 XMSN 1 1983 1 1990 20960. 11.000 34.0 7.0 12 2016 29.051/$1, 000, 000 BALANCE AT START OF YEAR 0. 20960. 20960. 20960. 20960. 20960. ADVANCES DURING THE YEAR 20960. 0. 0. 0. 0. 0. INTEREST PAYMENTS 2306. 2306. 2306. 2306. 2306. 2306. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 2304. 2306. 2306. 2306. 2306. 2306. BALANCE. AT END OF YEAR 20960. 20960. 20960. 20960. 20960. 20960. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 85. XtrSN 1. 1985 i 1992 91707. 11.000 34.0 7.0 12 2018 29.051/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 91707. 91707. 91707. ADVANCES DURING THE YEAR 0. 0. 91707. 0. 0. 0. INTEREST PAYMENTS 0. 0. 10088. 10088. 10088. 10088. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 10088. 10088. 10088. 10088. BALANCE AT END OF YEAR 0. 0. 91707. 91707. 91707. 91707. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 88 XNSN 1 1988 1 1995 41721. 11.000 34.0 7.0 12 2021 29.051/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 41721. INTEREST PAYMENTS 0. 0. 0. 0. 0. 4589. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 4589. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 41721. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 95_XMSN 1 1995 1 2002 21213. 11.000 34.0 7.0 12 2028 29.051/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 96 XMSN 1 19% 1 2003 22910. 11.000 34.0 7.0 12 2029 29.051/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. On 0. 0. 0. 0. 1989 20960. 0. 2306. 0. 2306. ~ 91707. PAGE: 167 DATE: 21-May-83 TIME: 10:17 FILES: CHNGT.D1 GASGT.D2 VERSION: FIN. FORE. 1990 1991 20960. 20824. 0. 0. 2300. 2285. 136. 151. 2436. 2436. _T ae —_ ade 10088. 10088. 0. 5 10088. 10088. 91707. 91707. 0. 0. 41721. 41721. 0. 0. 4589. 4589. 0. 0. 4589. 4589. 41721. 41721. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 168 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TINE: 10:17 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) VERSION: FIN. FORE. TABLE 11 LONG-TERM DEBT — NEW ($1,000) CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 LOAN EXE DATE BAS DATE AMOUNT APR TERN DEFR NAT DATE QTLY AMORT RATE 83_XNSN 1 1983 1 1990 20960. 11.000 34.0 7.0 12 2016 29.051/$1, 000, 000 BALANCE AT START OF YEAR 20673. 20505. 20317. 20108. 19875. 19615. 19325. 19002. 18643. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 2267. 2248. 2226. 2202. 2176. 2146. 2113. 2076. 2035. PRINCIPAL PAYMENTS 148. 188. 209. 233. 260. 290. 323. 3460. 401. TOTAL PAYMENTS 2436. 2434. 2436. 2436. 2436. 2434. 2436. 2436. 2436. BALANCE AT END OF YEAR 20505. 20317. 20108. 19875. 19615. 19325. 19002. 18643. 18241. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 85_XNSN 1 1985 1 1992 91707. 11.000 34.0 7.0 12 2018 29.051/$1, 000, 000 BALANCE AT START OF YEAR 91707. 91114, 90453. 89716. 88895. 87980. 86959. 85822. 84555. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 10064. 9996. 9920. 9836. 9742. 9637. 9520. 9389. 9244. PRINCIPAL PAYMENTS 593. 661. 737. 821. 915. 1020. 1137. 1268. 1413. TOTAL PAYMENTS 10657. 10657. 10657. 10657. 10657. 10657. 10657. 10657. 10657. BALANCE AT END OF YEAR 91114. 90453. 89716. 888975. 87980. 86959. 85822. 84555. 83142. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 88 XHSN 1 1988 1 1995 41721. 11.000 34.0 7.0 12 2021 29.051/$1, 000, 000 BALANCE AT START OF YEAR 41721. 41721. 41721. 41721. 41451. 41151. 40815. 40442. 40025. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 4589. 4589. 4589. 4578. 4548. 4313. 4475. 4432. 4384. PRINCIPAL PAYMENTS 0. 0. 0. 270. 301. 335. 374, 414. 464. TOTAL PAYMENTS 4589. 4589. 4589. 4848. 4348. 4848. 4848. 4348. 4848. BALANCE AT END OF YEAR 41721. 41721. 41721. 41451. 41151. 40815. 442. 40025. 39561. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 95_XtiSN 1 1995 1 2002 21213. 11.000 34.0 7.0 12 2028 29..051/$1, 000, 000 ' BALANCE AT START OF YEAR 0. 0. 0. 0. 21213. 21213. 21213. 21213. 21213. ADVANCES DURING THE YEAR 0. 0. 0. 21213. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 2333. 2333. 2333. 2333. 2333. 2333. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 2333. 2333. 2333. 2333. 2333. 2333. BALANCE AT END OF YEAR 0. 0. 0. 21213. 21213. 21213. 21213. 21213. 21213. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 96 XNSN 1 1996 1 2003 22710. 11.000 34.0 7.0 12 2029 29.051/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. o. 22910. 22910. 22910. 22910. ADVANCES DURING THE YEAR 0. 0. 0. 0. 22910. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 2520. 2520. 2520. 2520. 2520. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL, PAYMENTS 0. 0. 0. 0. 2520. 2520. 2520. 2520. 2520. BALANCE AT END OF YEAR 0. 0. 0. 0. 22910. 22910. 22910. 22910. 22910. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. CHUGACH, PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE 83 _XNSN 1 1983 1 1990 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 85_XMSN 1 1985 1 1992 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 88 XNSN 1 1988 1 1995 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 95_XMSN 1 1995 1 2002 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 96 XHSN 1 1996 1 2003 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT BURNS & MCDOMNELL ENGINEERING COMPANY HOMER & MATANUSKA ELEC. ASSOCIATIONS POWER SUPPLY PROGRAN TABLE 11 LONG-TERM DEBT - NEW ($1, 000) 2001 2002 2003 2004 AMOUNT APR TERM DEFR HAT DATE 20960. 11.000 34.0 7.0 12 2016 ie2ats 17794, "17296. 16740. 1989. 1937. 1gg0- 1816. 447. 498. 419. 2436. 2436. 2ane. 2436. 17794. 17296. 1674. 16121. 0. 0. 0. 0. 91707. 11.000 34.0 7.0 12 2018 aa1az. 81567, “79812. 77856. 9082. 8902. 8700. Bare. 1575. 1755. 1956. 2181. 10657. 10657. 10657. «10657. 81567. 79812. 77856. 75675. 0. 0. 0. re 41721. 11.000 34.0 7.0 12 2021 Sy561. 39044, "38467, 97824. 4331. 4272. 4205. 4132. 517. 577. 643. 716. 4348. 4843. 4848. 4848. 39044. 38467. 37824. 37108. 0. 0. 0. 0. 21213. 11.000 34.0 7.0 _ 12 2028 ai2ig. 21213, “21074. "20923. 2333. 2328. 2312. 2295. 0. 137. 153. 170. 2333. 2465. 2465. 2465. 21213. 21074. 20923. «20753. 0. 0. 0. 22910. 11.000 34.0 7.0 12 2029 22910. 22710. “22910. 22762. 2520. 2520. 2514. 2497. 0. 0. 148. 145. 2520. 2520. 2662. 2662. 22910. 22910. 22762. 22597. 2005 2006 @TLY AMORT RATE 29..051/$1, 000, 000 16121. 15431. 0. 0. 1745. 1666. 490. 769. 2436. 2436. 15431. 14662. 0. 0. 29.051/$1, 000, 000 73673. 73244. 8224. 7948. 2431. 2709. 10657, 10457. 73244. 70535. 0. 0. 29..051/$1, 000, 000 37108. “36310. 4050. 3958. 799. 890. 4848. 4848. 36310. 35419. 0. 0. 29.051/$1, 000, 000 20753. "20543. 2275. 2253. 190. 212. 2465. 2445. 20563. 20351. 0. 0. 29..051/$1, 000, 000 32597. 22413. 2478. 2457. 184. 205. 2662. 2662. zaaia. 22208. 2007 13804. 21979. pg PAGE: 169 DATE: 21-May-83 TINE: 10:17 FILES: CHNGT.01 GASGT.D2 VERSION: FIN. FORE. 2008 2009 13804. 12848. 0. 0. 1480. 1370. 956. 1065. 2436. 2436. 12848. 11783. 0. 0. — sks 7291 6905. 3366. 3752. 10657. 10657. 64149. 60398. 0. 0. 34427. 33322. 0. 0. 3742. 3616. 1104. 1233. 4848. 4848. 33322. 32089. 0. 0. 20115. 19852. 0. 0. 2202. 2172. 263. 293. 2465. 2465. ee 19559. 0. 21979. 21724. 0. 0. 2407. 2378. 255. 284, 2662. 2662. ee eee BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE 83_XNSN 1 1983 1 1990 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 85 _XNMSN 1 1985 1 1992 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 88 XMSN 1 1988 1 1995 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 95_XMSN 1 1995 1 2002 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 96 _XMSN 1 1996 1 2003 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT TABLE 11 LONG-TERM DEBT - NEW ($1,000) 2010 2011 2012 AMOUNT APR TERM DEFR MAT 20960. 11.000 34.0 7.0 12 11783. 10596. 9272. 0. 0. 0. 1248, 1112. 960. 1187. 1324. 1475. 2436. 2436. 2436. 10596. 9272. 7797. 0. 0. 0. 91707. 11.000 34.0 7.0 12 Boag. 36216. “51555. 6475. 5996. 5462. 4182. 4661. 5195. 10657. 10657. 10657. 56216. 51555. 46360. 0. 0. 0. 41721. 11.000 34.0 7.0 12 32087. 30713. "29184. 3474. 3317. 3141. 1374. 1531. 1707. 4948. 4848. 4848. 30715. 29184. 27477. 0. 0. 0. 21213, 11.000 34.0 7.0 12 igss9. 19232. "18868. 2138. 2101. 2059. 327. 364. 406. 2465. 2465. 2465. 19232, 18868. 18442. 0. 0. 0. 22910. 11.000 34.0 7.0 12 2144. 21123, “20779, 2346. 2309. 2269. 317. 353. 393. 2662. 2662. 2662. 2123. 20770. 20377. 2013 DATE 2016 77974 0. 791. 1644. 2434. 6153. 0. 2018 46360. 0. 4866. 5791. 10657. ee 2021 27477. 0. 2946. 1902. 4848. ove 2028 18462. 0. 2013. 453. 2465. san 4 2029 20377. 0. 2224, 438. 2662. aes 2014 2015 QTLY ANMORT RATE 29.051/$1, 000, 000 6153. 4320. 0. 0. 603. 393. 1833. 2043. 2434. 2436. 4320. 2277. 0. 0. 29.051/$1, 000, 000 mere 341 - 4202. 3463. 6455. 7194. 10657. 10657. 34114. 26920. 0. 0. 29.051/$1, 000, 000 ead oe 2728. 2485. 2120. 2364. 4848. 4848. 23454. 21091. 0. 0. 29.051/$1, 000, 000 eae te 1961. 1903. 504. 562. 2465. 2465. 17505. 16942. 0. 0. 29.051/$1, 000, 000 19938. 19450. 0. 0. 2174. 2118. 499. 345. 2662. 2662. ara tia: PAGE: 170 DATE: 21-May-83 TIME: 10:17 FILES: CHNGT.D1 GASGT.D2 VERSION: FIN. FORE. ° . - ~ - - mera eee eo — = —- ria ae em meson mc se wm F 4 i i . 3 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 171 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:17 PROJECT: 82-113-4-000 FILES: CHMGT.01 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) VERSION: FIN. FORE. TABLE 11 LONG-TERM DEBT - NEW ($1, 000) CONTRACT YEAR 1983 1984 1985 1986 1987 1988 1989 1990 1991 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE 99 _XNSN 1 1999 1 2006 28860. 11.000 34.0 7.0 12 2032 29.051/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 01 XMSN 1 2001 1 2008 33662. 11.000 34.0 7.0 12 2034 29.051/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE. AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. HQTRS BLDG 1 1984 1 1991 3800. 11.000 34.0 7.0 12 2017 29.051/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 3800. 3800. 3800. 3800. 3800. 3800. 3800. ADVANCES DURING THE YEAR 0. 3800. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 418. 418. 418. 418. 418. 418. 418. 417. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 25. TOTAL PAYMENTS 0. 418. 418. 418. 418. 418. 418. 418. 442. BALANCE AT END OF YEAR 0. 3800. 3800. 3800. 3800. 3800. 3800. 3800. 3775. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. BURNS & HMCDONNELL ENGINEERING COMPANY PAGE: 172 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:17 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) VERSION: FIN. FORE. TABLE 11 LONG-TERM DEBT - NEW ($1, 000) CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 LOAN EXE DATE BAS DATE AMOUNT APR TERM DEFR MAT DATE QTLY AMORT RATE 99_XHSN 1 1999 1 2006 28860. 11.000 34.0 7.0 12 2032 29.051/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 28860. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 28860. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 3175. 3175. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 3175. 3175. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 28860. 28860. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. 01 _XMSN 1 2001 1 2008 33662. 11.000 34.0 7.0 12 2034 29.051/$1, 000, 000 BALANCE AT START OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. TOTAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. HQTRS BLDG 1 1984 1 1991 3800. 11.000 34.0 7.0 12 2017 29.051/$1, 000, 000 BALANCE AT START OF YEAR 3775. 3748. 3718. 3683. 3646. 3603. 3556. 3504. 3445. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 414. 411. 408. 404. 399. 394. 389. 383. 376. PRINCIPAL PAYMENTS 27. 31. 34. 38. 42. 47. 33. 59. 65. TOTAL PAYMENTS 442. 442. 442. 442. 442. 442. 442. 442. 442. BALANCE AT END OF YEAR 3748. 3718. 3683. 3646. 34603. 3554. 3504. 3445. 3380. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. ae wae te we ea —m os ae BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) CONTRACT YEAR LOAN EXE DATE BAS DATE 99 XMSN 1 1999 1 2006 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE. AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 01 XMSN 2001 1 2008 BALANCE AT start OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL. PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT H@TRS BLDG 1 1984 1 1991 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT os TABLE 11 LONG-TERM DEBT - NEW ($1,000) 2001 2002 2003 2004 2005 2006 AMOUNT APR TERM DEFR MAT DATE —@TLY AMORT RATE 28860. 11.000 34.0 7.0 12 2032 29.051/$1,000, 000 0. 0. 0. 0. 0. 0. 3175. 3175. 3175. 3175. 3175. 3167. 0. 0 0. 0: 0. 187. 3175. 3175. 3175. 3175. 3175. 3354. 28860. 28040. 28060. 28860. 28860. 28473. 0. 0. 0. 0. 0. 0. 33662. 11.000 34.0 7.0 12 2034 29.051/$1,000, 000 0. 33642. 33662. 33442. 33462. 33462. 33662. 0. 0. 0. 0. 0. 3703. 3703. «3703. 3703. 3703. 3703. 0. 0. 0. 0. 0. 0. 3703. 3703. 3703. 3703. 3703. 3703. ~~ Sse eel 3800. 11.000 34.0 7.0 12 2017 29.051/$1, 000, 000 30 2923, 3380. 3307. 3226. 3136. 0. 0. 0. 369. 3461. 351. 341. 73. 81. 90. 101. 442. 442. 442. 442. 3307. 3226. 3136. 3035. 0. 0. 0. 0. 329. 112. 442, 2923. 0. 0. 316. 125. 442. 2798. 0. 2007 3703. 2798. 0. 139. 2658. 0. PAGE: 173 DATE: 21-May-83 TIME: 10:17 FILES: CHMGT.Di GASGT.D2 VERSION: FIN. FORE. 2008 3122. 232. 28234. 0. 33662. 3494. 218. 3912. 93444. 2658. 0. 155. 2503. 0. 2009 20234. 3095. 258. 3354. 27975. 33444. 3669. 243. 3912. 33202. 2503. 0. 268. 173. 442, 2329. 0. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, Z0YR) CONTRACT YEAR LOAN EXE DATE BAS DATE 99 _XMSN 1 1999 1 2006 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT 01 _XNSN 1 2001 1 2008 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT H@TRS BLDG 1 1984 1 19971 BALANCE AT START OF YEAR ADVANCES DURING THE YEAR INTEREST PAYMENTS PRINCIPAL PAYMENTS TOTAL PAYMENTS BALANCE AT END OF YEAR INTEREST CHARGED TO CONSTR-CREDIT TABLE 11 LONG-TERM DEBT - NEW ($1, 000) 2010 2011 2012 AMOUNT APR TERM DEFR . MAT 28860. 11.000 34.0 7.0 12 a7973. 27687. 27366. 3066. 3033. 2996. “288. 321. 358. 3354. 3354. 3354. 27687. 27366. 27008. 0. 0. 0. 33662, 11.000 34.0 7.0 12 $3202. 92731. "32690. 3641. 3610. 3576. 270. 301. 336. 3912. 3912. 3912. 32931. 32630. 32294. 0. 0. 0. 3800. 11.000 34.0 7.0 12 2329. 2134. 1921. 0. 0. 0. 248. 226. 202. 193. 215. 240. 442. 442. 442. 2136. 1921. 1681. 0. 0. 0. 2013 2014 2015 DATE — @TLY AMORT RATE 2032. —-29..051/$1,,000, 000 27008. “26607. 26165. 2955. 2909. 2858. 399. 45. - » 496. 3354. 3354, 3354. 26609. 26165. 25669. 0. 0. 0. 2034 —-:29..051/$1, 000, 000 32274, "31919. 31502. 3537. 3494. 3444. 374, 417. 465. 3912. 3912. 3912. 31919. 31502. 31037. 0. 0. 0. 2017 :29..051/$1, 000, 000 1681. 1414, 1115. 0. 0. 0. 174, 143. 109. 267. 298. 332. 442. 442. 442. 1414. 1115. 783. 0. 0. 0. PAGE: 174 DATE: 21-May-83 TIME: 10:17 FILES: CHNGT.D1 GASGT.D2 VERSION: FIN. FORE. . . - feo et - - - = oe eae oem we egezy. — a cm Py ers ~ pilin pallid A 3 ’ ' t z BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 175 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:17 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) VERSION: FIN. FORE. TABLE 12 LONG-TERM DEBT - SUMMARY ($1, 000) CONTRACT YEAR 1983 1984 1985 1986 1987 1988 1989 1990 1991 LONG-TERM DEBT - EXISTING BALANCE AT START OF YEAR 232255. 229094. 225873. 222584. a. 215261. 211102. 206804. 202357. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 19231. 19133. 19033. 18925. 18799. 18644, 184460. 18253. 18029. PRINCIPAL PAYMENTS 3160. - 3222. 3284. 3486. 3839. 4159. 4298. 4447. 4671. TOTAL PAYMENTS 22372. 22355. 22319. 22411, 22639. 22802. 22758. 22700. 22700. BALANCE AT END OF YEAR 229094. 225873. 2225846. 219100. 215261. 211102. 206804. 202357. 197686. LONG-TERM DEBT — NEW BALANCE AT START OF YEAR 0. 20960. 50334. 158009. 158009. 158009. 199730. 199730. all ADVANCES DURING THE YEAR 20960. 29374. 107675. 0. 0. 41721. 0. 0. INTEREST PAYMENTS 2304. 5537. 17381. 17381. 17381. 21970. 21970. 21965. 21942. PRINCIPAL PAYMENTS 0. 0. 0. 0. 0. 0. 0. 136. 341. TOTAL PAYMENTS 2306. 5537. 17381. 17381. 17381. 21970. 21970. 22100. 22283. BALANCE AT END OF YEAR 20960. 50334. 158009. 158009. 158009. 199730. 199730. 199595. 199254. TOTAL LONG-TERM DEBT BALANCE AT START OF YEAR 232255. 250054. 276207. 380596. 377109. 373270. 410832. 406534. 401952. ADVANCES DURING THE YEAR 20960. 29374. 107675. 0. 0. 41721. 0. 0. 0. INTEREST PAYMENTS 21537. 24670. 36414. 36306. 36180. 40614. 40430. 40218. 39970. PRINCIPAL PAYMENTS 3160. 3222. 3286. 3486. 3839. 4159. 4298. 4582. 3012. TOTAL PAYMENTS 24697. 27892. 39700. 39793. 40020. 44773. 44728. 44800. 44982. BALANCE AT END OF YEAR 250054. 276207. 380596. 377109. 373270. 410832. 406534. 401952. 396940. INTEREST ON LONG-TERM DEBT 21537. 24670. 36414. 36306. 36180. 40614. 40430. 40218. 39970. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. 0. 0. 0. 0. NET INTEREST EXPENSE 21537. 24670. 36414. 36306. 36180. 40614. 40430. 40218. 39970. INTEREST PAYMENTS 21537. 24670. 36414. 36306. 36180. 40614. 40430. 40218. 39970. PRINCIPAL PAYMENTS 3160. 3222. 3286. 3486. 3839. 4159. 4298. 4582. 5012. LOAN PAYMENTS 24697. 27892. 39700. 39793. 40020. 44773. 44728. 44800. 44982. oe BURNS & MCOONNELL ENGINEERING COMPANY © PAGE: 176 i POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:17 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSHISSION COOP. PLAN: GAS(8Z, 20YR) VERSION: FIN. FORE. TABLE 12 LONG-TERM DEBT — SUMMARY ($1, 000) CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 LONG-TERM DEBT - EXISTING BALANCE AT START OF YEAR 197686. 192774. 187620. 182205. 176483. 170430. 164045. 157547. 150993. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. INTEREST PAYMENTS 17787. 17526. 17244. 16938. 16606. 16244. 15852. 15431. 14975. PRINCIPAL PAYMENTS 4913. 5154. 3415. 3721. 6053. 6385. 6498. 6554. 6936. TOTAL PAYMENTS 22700. 22679. 22659. 22659. 22659. 22629. 22350. 21985. 21911. BALANCE AT END OF YEAR 192774. 187620. 182205. 176483. 170430. 164045. 157547. 150993. 144057. LONG-TERM DEBT - NEW BALANCE AT START OF YEAR 199254. 198177. 196978. 195640. 215093. 236041. 233854. 231416. 257559. ADVANCES DURING THE YEAR 0. 0. 0. 21213. 22910. 0. 0. 28860. 0. INTEREST PAYMENTS 21875. 21751. 21614. 23783. 26101. 25876. 23626. 28521. 28209. PRINCIPAL PAYMENTS 1076. 1200. 1337. 1740. 1962. 2187. 2438. 2717. 3029. TOTAL PAYMENTS 22951. 22951. 22951. 255343. 28063. 28063. 28063. 31238. 31238. BALANCE AT END OF YEAR 198177. 196978. 195640. 215093. 236041. 233854. 231416. 257559. 254531. TOTAL LONG-TERM DEBT BALANCE AT START OF YEAR 396940. 390951. 384598. 377845. 391577. 406471. 397899. 388963. 408553. ADVANCES DURING THE YEAR 0. 0. 0. 21213. 229710. 0. 0. 28860. 0. INTEREST PAYMENTS 39662. 39277. 38857. 40721. 42707. 42121. 41477. 43952. 43184. PRINCIPAL PAYMENTS 5989. 6353. 6753. 7482. 8016. 8572. 8936. 9271. 9965. TOTAL PAYMENTS 45651. 45630. 45610. 48202. 50722. 30692. 30414, 33223. 53149. BALANCE AT END OF YEAR 390951. 384598. 377845. 391577. 406471. 397899. 388963. 408553. 3978588. INTEREST ON LONG-TERM DEBT 39662. 39277. 38857. 40721. 42707. 42121. 41477. 43952. 43184. INTEREST CHARGED TO CONSTR-CREDIT 0. 9. 0. 0. 0. 0. 0. 0. 0. NET INTEREST EXPENSE 39662. 39277. 38857. 40721. 42707. 42121. 41477. 43952. 43184. INTEREST PAYMENTS 39662. 39277. 38857. 40721. 42707. 42121. 41477. 43952. 43184. PRINCIPAL PAYMENTS 5989. 6353. 6753. 7482. 8016. 8572. 8934. 9271. 9965. LOAN PAYMENTS 45651. 45430. 45610. 48202. 30722. 50692. 30414. 53223. 53149. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) TABLE 12 LONG-TERM DEBT ~ SUMMARY ($1, 000) CONTRACT YEAR 2001 2002 2003 2004 2005 LONG-TERM DEBT — EXISTING BALANCE AT START OF YEAR 144057. 136913. 129616. 121894. sme. ADVANCES DURING THE YEAR 0. 0. 0. 0. JNTEREST PAYMENTS 14477. 139735. 13344, 12693. 11974. PRINCIPAL PAYMENTS 7145. 7297. 7720. 8343. 8752. TOTAL PAYMENTS 21621. 21232. 21064, 21036. 20727. BALANCE AT END OF YEAR 136913. 129616. 121896. 113553. 104801. LONG-TERM DEBT — NEW BALANCE AT START OF YEAR 254531. 786317. 782417. 777922. 772712. ADVANCES DURING THE YEAR 335162. 0. 0. 0. 0. INTEREST PAYMENTS 86730. 84338. 85885. 85369. 84795. PRINCIPAL PAYMENTS 3376. 3900. 4495. 5010. 5584. TOTAL PAYMENTS 90106. 90237. 90380. 90380. 90380. BALANCE AT END OF YEAR 786317. 782417. 777922. 772912. 767328. TOTAL LONG-TERM DEBT BALANCE AT START OF YEAR 398588. 923230. 912033. 897978197. 886465. ADVANCES DURING THE YEAR 335162. 0. 0. 0. 0. INTEREST PAYMENTS 101207. 100273. 99229. 98063. 96770. PRINCIPAL PAYMENTS 10520. 11196. 12215. 13353. 14337. TOTAL PAYMENTS 111727. 1114469. 111443. 111416. 111106. BALANCE AT END OF YEAR 923230. 912033. 899819. 8864466. 872129. INTEREST ON LONG-TERM DEBT — 100273. 99229. 98063. 96770. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. NET INTEREST EXPENSE 101207. 100273. 99229. 98063. 96770. INTEREST PAYMENTS 101207. 100273. 99229. 98063. 96770. PRINCIPAL PAYMENTS 10520. 111964. 12215. 13353. 14337. LOAN PAYMENTS 111727. 111469. 111443. 111416. 111106. 2006 104801. 11184. 9347. 20531. 95454. 767328. 84148. 6411. 760917. 972129. 95331. 15758. 111089. 856371. 95331. 95331. 95331. 15758. 111089. DATE: 21-tay-€3 TIME: 10:17 FILES: CHMGT.D1 GASGT.D2 VERSION: FIN. FORE. 2008 = 2009 e510. 74689. 9341. 8276. 10820. 10804. 201461. 19080. 74689. 63885. 753771. 2461313. 1718967. 0. 271541. 270231. 11426. 12735. 282966. 282964. 2461313. 2448577. 839281. 2536002. 1718967. 0. 280881. 278507. 22246. 23539. 303127. 302044. 2536002. 2512443. 290881. 278507. 20881: 278507. 280881. 278507. 22246. 23539. 303127. 302044. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) TABLE 12 LONG-TERM DEBT — SUMMARY ($1,000) CONTRACT YEAR 2010 2011 2012 2013 2014 LONG-TERM DEBT - EXISTING BALANCE AT START OF YEAR 63885. 52337. 40148. 27883. 15761. ADVANCES DURING THE YEAR 0. 0. 0. 0. 0. INTEREST PAYMENTS 7143. 5883. 4523. 3055. 1664. PRINCIPAL PAYMENTS 11548. 12190. 12265. 12122. 9214. TOTAL PAYMENTS 18691. 18073. 16788. 15177. 10878. BALANCE AT END OF YEAR 52337. 40148. 27883. 15761. 6547. LONG-TERM DEBT - NEW BALANCE AT START OF YEAR 2448577. 2434382. 2418561. 2400925. 4906995. ADVANCES DURING THE YEAR 0. 0. 0. 2525727. 0. INTEREST PAYMENTS 268771. 267144. 265331. 541137. 538886. PRINCIPAL PAYMENTS 14195. 15822. 17635. 19657. 21910. TOTAL PAYMENTS 282966. 282966. 282966. 560796. 560796. BALANCE AT END OF YEAR 2434382. 2418561. 2400925. 4906995. 4885085. TOTAL LONG-TERM DEBT BALANCE AT START OF YEAR 2512463. 2486720. 2458708. 2428808. 4922756. ADVANCES DURING THE YEAR 0. 0. 0. 2525727. 0. INTEREST PAYMENTS 275914. 273028. 269853. 544195. 540550. PRINCIPAL PAYMENTS 25743. 286012. 29900. 31779. 31124. TOTAL PAYMENTS 301657. 301039. 299754. 575974. 571674. BALANCE AT END OF YEAR 2486720. 2458708. 2428808. 4922756. 4891632. INTEREST ON LONG-TERM DEBT 275914. 273028. 269853. 544195. 540550. INTEREST CHARGED TO CONSTR-CREDIT 0. 0. 0. 0. 0. NET INTEREST EXPENSE 275914. 273028. 269853. 544195. 540550. INTEREST PAYMENTS 275914. 273028. 269853. 544195. 540550. PRINCIPAL PAYMENTS 25743. 28012. 29900. 31779. 31124. LOAN PAYMENTS 301657. 301039. 299754. 575974. 571674. fied etme Bes ee (oo se 2015 6547. 0. 349. 5766. 6315. 781. 4885085. 535927. 35537. 571463. 4849549. 4091632. 536476. 41303. 577779. 4850329. 536476. 536476. 536476. 41303. 577779. PAGE: 178 DATE: 21-May-83 TIME: 10:17 FILES: CHMGT.D1 GASGT.D2 VERSION: FIN. FORE. BURNS & NCDONNELL ENGINEERING COMPANY PAGE: 179 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TINE: 10:19 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.02 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) VERSION: FIN. FORE. TABLE 13 ELECTRIC PLANT IN SERVICE ($1,000) CONTRACT YEAR 1983 1984 1985 1986 1987 1988 1989 1990 1991 COMBUSTION TURBINE GROSS PLANT 126413. 126413. 151988. 167956. 167956. 167956. 167956. 167956. 167956. ADDITIONS DURING THE YEAR 0. 25574. 15968. 0. 0. 0. 0. 0. 0. RETIREMENTS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 126413. 151988. 167956. 167956. 167956. 167956. 167956. 167956. 167956. ACCUMULATED DEPRECIATION 22665. 26590. 31234. 36277. 41321. 46365. 51409. 36452. 61496. NET PLANT IN SERVICE 103748. 125398. 136722. 131678. 126634. 121591. 116547. 111503. 106459. DEPRECIATION 3796. 3924. 4644, 5044. 5044. 5044. 5044, 5044. 5044. HYDRO GROSS PLANT 7818. 7818. 7818. 7818. 7818. 7818. 7818. 7818. 7818. ADDITIONS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. RETIREMENTS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 7818. 7818. 7818. 7818. 7818. 7818. 7818. 7818. 7818. ACCUMULATED DEPRECIATION 3526. 3682. 3838. 3995. 4151. 4308. 4464. 4621. 4777. NET PLANT IN SERVICE 4293. 4136. 3980. 3823. 3667. 3511. 3334. 3198. 3041. DEPRECIATION 154. 154. 154. 154. 156. 154. 154. 154. 154. STEAN PRODUCTION GROSS PLANT 7944, 7944, 7944. 7944, 7944. 7944. 7944. 7944. 7944, ADDITIONS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. RETIREMENTS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 7944, 7944, 7944. 7944, 7944. 7944, 7944. 7944. 7944, ACCUMULATED DEPRECIATION 6257. 6504. 6750. 6996. 7242. 7489. 7735. 7944, 7944, NET PLANT IN SERVICE 1687. 1441. 1194. 948. 702. 455. 209. 0. 0. DEPRECIATION 246. 246. 246. 246. 246. 246. 246. 0. 0. COMBINED CYCLE GROSS PLANT 0. 0. 0. 0. 0. 0. 0. 0. 0. ADDITIONS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. RETIREMENTS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. ACCUMULATED DEPRECIATION 0. 0. 0. 0. 0. 0. 0. 0. 0. NET PLANT IN SERVICE 0. 0. 0. 0. 0. 0. 0. 0. 0. DEPRECIATION 0. 0. 0. 0. 0. 0. 0. 0. 0. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 180 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:19 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) VERSION: FIN. FORE. TABLE 13 ELECTRIC PLANT IN SERVICE ($1,000) CONTRACT YEAR 1983 1984 1985 1988 1987 1988 1989 1990 1991 GENERAL PLANT GROSS PLANT 0. 0. 3800. 3800. 3800. 3800. 3800. 3800. 3800. ADDITIONS DURING THE YEAR 0. 3800. 0. 0. 0. 0. 0. 0. 0. RETIREMENTS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 3800. 3800. 3800. 3800. 3800. 3800. 3800. 3800. ACCUMULATED DEPRECIATION 0. 114. 228. 342. 456. 571. 685. 799. 913. NET PLANT IN SERVICE 0. 3686. 3572. 3458. 3344. 3229. 3115. 3001. 2887. DEPRECIATION 0. 114. 114. 114. 114. 114. 114. 114. 114. SUBSTATION/XNISSION GROSS PLANT 1149894. 135854. 147372. 239079. 9 249691. 9 261152. 9352873. 366241. 380478. ADDITIONS DURING THE YEAR 20960. 11518. 91707. 10612. 11461. 91722. 13368. 14437. 155972. RETIREMENTS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 135854. 147372. 237079. 247671. 261152. 352873. 366241. 380678. 376270. ACCUMULATED DEPRECIATION 20733. 24785. 313460. 38227. 45408. 55111. 65181. 73647. 86542. NET PLANT IN SERVICE 115121. 122586. 207718. 211464. 215743. 297762. 301061. 305031. 309729. DEPRECIATION 3736. 4053. 6575. 6867. 7181. 9702. 10070. 10446. 10895. ELECTRIC PLANT IN SERVICE GROSS PLANT 257069. 278029. 318922. 426597. 437209. 448670. 540371. 553757. 568176. ADDITIONS DURING THE YEAR 20960. 40892. 107675. 10612. 11461. 91722. 13368. 14437. 15592. RETIREMENTS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 278029. 318922. 426597. 437209. 448670. 540391. 553759. 568196. 593788. ACCUMULATED DEPRECIATION 53181. 61675. 73411. 85838. 98580. 113843. 129473. 145254. 161462. NET PLANT IN SERVICE 224848. 257247. 353186. 351371. 350090. 426548. 424286. 422943. 422326. DEPRECIATION 7935. 8494. 11736. 12427. 12742. 15263. 15630. 15781. 16209. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 181 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:19 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8X, 20YR) VERSION: FIN. FORE. TABLE 13 ELECTRIC PLANT IN SERVICE ($1,000) CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 COMBUSTION TURBINE GROSS PLANT 167956. 167956. 167956. 167956. 167956. 167956. 167956. 167956. 167956. ADDITIONS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. RETIREMENTS DURING THE YEAR 0. 0. 0. 0. o. 0. 0. 0. 0. BALANCE AT END OF YEAR 167956. 167956. 167956. 167956. 167956. 167956. 167956. 167956. 167956. ACCUMULATED DEPRECIATION 66540. 71583. 76627. 81671. 86715. 91758. 96802. 101846. 1068970. NET PLANT IN SERVICE 101416. 96372. 91328. 86285. 81241. 76197. 71153. 66110. 61066. DEPRECIATION 5044. 5044. 5044. 35044. 5044. 3044, 5044. 3044. 5044. HYDRO GROSS PLANT 7818. 7818. 7818. 7818. 7818. 7818. 7818. 7818. 7818. ADDITIONS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. RETIREMENTS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 7818. 7818. 7818. 7818. 7818. 7818. 7818. 7818. 7818. ACCUMULATED DEPRECIATION 4933. 5090. 3246. 3403. 3539. 9715. 5872. 6028. 6185. NET PLANT IN SERVICE 2885. 2729. 2572. 2416. 2259. 2103. 1947. 1790. 1634. DEPRECIATION 156. 156. 156. 156. 156. 156. 156. 154. 156. STEAM PRODUCTION GROSS PLANT 7944. 7944. 7944. 7944. 7944. 7944. 7944. 7944. 7944, ADDITIONS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. RETIREMENTS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 7944, 7944. 7944, 7944. 7944, 7944. 7944. 7944, 7944, ACCUMULATED DEPRECIATION 7944. 7944. 7944. 7944. 7944. 7944. 7944. 7944, 7944, NET PLANT IN SERVICE 0. 0. 0. 0. 0. 0. 0. 0. 0. DEPRECIATION 0. 0. 0. 0. 0. 0. 0. 0. 0. COMBINED CYCLE GROSS PLANT 0. 0. 0. 0. 0. 0. 0. 0. 0. ADDITIONS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. RETIRENENTS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. ACCUMULATED DEPRECIATION 0. 0. 0. 0. 0. 0. 0. 0. 0. NET PLANT IN SERVICE 0. 0. 0. 0. 0. 0. 0. 0. 0. DEPRECIATION 0. 0. 0. 0. 0. 0. 0. 0. o. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 182 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS . TIME: 10:19 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT. D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) . VERSION: FIN. FORE. TABLE 13 ELECTRIC PLANT IN SERVICE ($1,000) CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 GENERAL PLANT GROSS PLANT 3800. 3800. 3800. 3800. 3800. 3800. 3800. 3800. 3800. ADDITIONS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. RETIREMENTS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 3800. 3800. 3800. 3800. 3800. 3800. 3800. 3800. 3800. ACCUMULATED DEPRECIATION 1027. 1141. 1255. 1369. 1483. 1598. 1712. 1826. 1940. NET PLANT IN SERVICE 2773. 2659. 2545. 2431. 2317. 2202. 2088. 1974. 1860. DEPRECIATION 114. 114. 114. 114. 114, 114, 114. 114, 114. SUBSTATION/XMISSION GROSS PLANT 396270. 413110. 431297. 450939. 472152. 495062. 519805. 5346527. 575388. ADDITIONS DURING THE YEAR 16840. 18187. 19642. 21213. 229710. 24743. 26722. 28860. 31169. RETIRENENTS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 413110. 431297. 4509739. 472152. 4975062. 5197805. 346527. 575388. 606557. ACCUMULATED DEPRECIATION 97899. 109756. 122152. 135132. 148743. 163032. 178056. 193874. 210548. NET PLANT IN SERVICE 315211. 321541. 328787. 337020. 346320. 354773. 368471. 381513. 396008. DEPRECIATION 11357. 11857. 12397. 12980. 13610. 14290. 15024. 15818. 16674. ELECTRIC PLANT IN SERVICE GROSS PLANT 383788. 600628. 618815. 638457. 6597670. 682580. 707323. 734045. 7629705. ADDITIONS DURING THE YEAR 16840. 18187. 19642. alan = a oars a ee RETIREMENTS DURING THE YEAR 0. 0. 0. BALANCE AT END OF YEAR 600628. 618815. 638457. 659670. ea2sa0. 707323. 734043, 762903. 794074. ACCUMULATED DEPRECIATION 178134. 195305. 213016. 231310. 250235. 267837. 290177. 311307. 333297. NET PLANT IN SERVICE 422494. 423510. 425441. 428360. 432346. 437485. 443868. 451597. 460777. DEPRECIATION 16672. 17171. 17711. 18294, 18924, 19604. 20338. 21132. 21988. aa been —— ee od oct eee ~ < 2 - - : . oe ——s os os pay Boe 4 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 183 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:19 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT..D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) VERSION: FIN. FORE. TABLE 13 ELECTRIC PLANT IN SERVICE ($1, 000) CONTRACT YEAR 2001 2002 2003 2004 2005 2004 2007 2008 2009 COMBUSTION TURBINE GROSS PLANT 1679356. 167956. 167956. 167956. 167956. 167956. 167956. 167956. 167956. ADDITIONS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. RETIREMENTS DURING THE YEAR 0. oO. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 167956. 167956. 167956. 167956. 167956. 167956. 167956. 167956. 167956. ACCUMULATED DEPRECIATION 111933. 116977. 122021. 127064. 132108. 137152. 142196. 147237. 152283. NET PLANT IN SERVICE 36022. 50979. 45935. 40891. 35847. 30804. 25760. 20716. 15673. DEPRECIATION 5044. 5044. 3044. 3044. 3044. 3044. 5044. 3044. 3044. HYDRO GROSS PLANT 7818. 7818. 7818. 7818. 7818. 7818. 7818. 7818. 7818. ADDITIONS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. RETIREMENTS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 7818. 7818. 7818. 7818. 7818. 7818. 7818. 7818. 7818. ACCUMULATED DEPRECIATION 6341. 6497. 6654. 6810. 6967. 7123. 7279. 7436. 7392. NET PLANT IN SERVICE 1477. 1321. 1165. 1008. 852. 695. 339. 383. 226. DEPRECIATION 154. 156. 156. 156. 154. 156. 156. 156. 156. STEAM PRODUCTION GROSS PLANT 7944, 7944. 7944. 7944, 7944, 7944. 7944. 7944. 7944. ADDITIONS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. RETIREMENTS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 7944. 7944. 7944. 7944, 7944, 7944, 7944, 7944. 7944. ACCUMULATED DEPRECIATION 7944. 7944. 7944. 7944, 7944. 7944. 7944. 7944, 7944, NET PLANT IN SERVICE 0. 0. 0. 0. 0. 0. 0. 0. 0. DEPRECIATION 0. 0. 0. 0. 0. 0. 0. 0. 0. COMBINED CYCLE GROSS PLANT 0. 501500. 501500. 501500. 501500. 501500. 501500. 501500. 2220468. ADDITIONS DURING THE YEAR 301500. 0. 0. 0. 0. 0. 0. 1718967. 0. RETIREMENTS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 301500. 501500. 501500. 501500. 501500. 501500. 501500. 2220468. 2220468. ACCUMULATED DEPRECIATION 15060. 30120. 45180. 60240. 75300. 90360. 105421. 172101. 238782. NET PLANT IN SERVICE 486440. 471380. 456320. 441260. 426200. 411140. 396080. 2048346. 1981686. DEPRECIATION 15060. 15060. 15060. 15060. 15060 15060. 15040. 66681. 66681. BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 184 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:19 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT. D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) VERSION: FIN. FORE. TABLE 13 ELECTRIC PLANT IN SERVICE ($1,000) CONTRACT YEAR 2001 2002 2003 2004 2005 2006 2007 2008 2009 GENERAL PLANT GROSS PLANT 3800. 3800. 3800. 3800. 3800. 3800. 3800. 3800. 3800. ADDITIONS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. oO. RETIREMENTS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 3800. 3800. 3800. 3800. 3800. 3800. 3800. 3800. 3800. ACCUMULATED DEPRECIATION 2054. 2168. 2262. 2396. 2510. 2625. 2739. 2853. 2967. NET PLANT IN SERVICE 1746. 1632. 1518. 1404. 1289. 1175. 1061. 947. 833. DEPRECIATION 114. 114. 114. 114. 114. 114. 114, 114. 114, SUBSTATION/XNISSION ; GROSS PLANT 606557. 640219. 676574. 715838. 758243. 804040. 853501. 906919. 764611. ADDITIONS DURING THE YEAR 33662. 36355. 39264. 42405. 45797. 47461. 33418. 57692. 62307. RETIREMENTS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 640219. 676574. 715838. 758243. 804040. 853501. 706919. 964611. 10269718. ACCUMULATED DEPRECIATION 228148. 246746. 266424. 287266. 309366. 332826. 357752. 384264. 412487. NET PLANT IN SERVICE 412071. 427828. 449414. 470977. 494674. 520675. 547167. 580347. 614431. DEPRECIATION 17600. 18599. 19677. 20842. 22100. 23459. 24927. 26512. 28223. ELECTRIC PLANT IN SERVICE GROSS PLANT 799074. 1329237. 1365572. 1404856. 1447261. 1493058. 1542519. 1595937. 3372597. ADDITIONS DURING THE YEAR 535163. 36355. 39264. 42405. 45797. 49461. 53418. 1776659. 62307. RETIREMENTS DURING THE YEAR 0. 0. 0. 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 1329237. 1365592. 1404856. 1447261. 1493058. 1542519. 1595937. 3372597. 3434904. ACCUMULATED DEPRECIATION 371271. 410244. 450296. 491512. 533987. 577820. 623121. 721628. 821844. NET PLANT IN SERVICE 957966. 955348. 954561. 955749. 959072. 964699. 972816. 2650969. 2613057. DEPRECIATION 37974. 38973. 40052. 41217. 42475. 43834. 45301. 98507. 100218. Roe ee Cee Po to Lo LL bei een » . . “ . “e . " ~ as - ee me in | rm —" rr pe enaaee oo - = . ae my BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 185 POWER SUPPLY PROGRAN DATE: 21-fay-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:19 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) VERSION: FIN. FORE. TABLE 13 ELECTRIC PLANT IN SERVICE ($1,000) CONTRACT YEAR 2010 2011 2012 2013 2014 2015 COMBUSTION TURBINE GROSS PLANT 167956. 167956. 167956. 167956. 167956. 167956. ADDITIONS DURING THE YEAR 0. 0. 0. 0. 0. 0. RETIREMENTS DURING THE YEAR o. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 167956. 167956. 167956. 167956. 167956. 167956. ACCUMULATED DEPRECIATION 157327. 162370. 167414. 167956. 167956. 167956. NET PLANT IN SERVICE 10629. 3585. S41. 0. 0. 0. DEPRECIATION 5044. 5044. 5044. 0. 0. 0. HYDRO GROSS PLANT 7818. 7818. 7818. 7818. 7818. 7818. ADDITIONS DURING THE YEAR 0. 0. 0. 0. 0. 0. RETIRENENTS DURING THE YEAR 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 7818. 7818. 7818. 7818. 7818. 7818. ACCUMULATED DEPRECIATION 7749. 7818. 7818. 7818. 7818. 7818. NET PLANT IN SERVICE 70. 0. 0. 0. 0. 0. DEPRECIATION 154. 0. 0. 0. 0. 0. STEAM PRODUCTION GROSS PLANT 7944. 7944. 7944. 7944. 7944. 7944, ADDITIONS DURING THE YEAR 0. 0. 0. 0. 0. 0. RETIREMENTS DURING THE YEAR 0. 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 7944. 7944. 7944. 7944. 7944. 7944, ACCUMULATED DEPRECIATION 7944, 7944. 7944. 7944. 7944. 7944, NET PLANT IN SERVICE 0. 0. 0. 0. 0. 0. DEPRECIATION 0. 0. 0. 0. 0. 0. COMBINED CYCLE GROSS PLANT 2220468. 2220468. 2220468. 2220468. 4746195. 4746195. ADDITIONS DURING THE YEAR 0. 0. 0. 2525727. 0. 0. RETIREMENTS DURING THE YEAR 0. 0. 0. 0. 0. 0. BALANCE AT ENO OF YEAR 2220468. 2220468. 2220468. 4746195. 4746195. 4746195. ACCUMULATED DEPRECIATION 303463. 372143. 438824. 581352. 723881. 866409. NET PLANT IN SERVICE 1915005. 1848324. 1781644. 4164842. 4022314. 3879785. DEPRECIATION 66681. 66681. 66681. 142528. 142528. 142528. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) TABLE 13 ELECTRIC PLANT IN SERVICE ($1, 000) CONTRACT YEAR 2010 2011 2012 2013 2014 GENERAL PLANT GROSS PLANT 3800. 3800. 3800. 3800. 3800. ADDITIONS DURING THE YEAR 0. 0. 0. 0. 0. RETIREMENTS DURING THE YEAR 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 3800. 3800. 3800. 3800. 3800. ACCUMULATED DEPRECIATION 3081. 3195. 3309, 3423. 3538. NET PLANT IN SERVICE 719. 605. 491. 377. 262. DEPRECIATION 114. 114, 114. 114, 114. SUBSTATION/XMISSION GROSS PLANT 1026918. 1094209. 1166884. 1245373. 1330141. ADDITIONS DURING THE YEAR 67271. 72675. 78487. 84768. 91549. RETIREMENTS DURING THE YEAR 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 1094209. 1166884. 1245373. 1330141. 1421690. ACCUMULATED DEPRECIATION 442559. 474628. 508853. 545407. 584475. NET PLANT IN SERVICE 651650. 692256. 736520. 784734. 837215. DEPRECIATION 30072. 32069. 34225. 36554. 39069. ELECTRIC PLANT IN SERVICE GROSS PLANT 3434904. 3502195. 3574870. 3653357. 6263854. ADDITIONS DURING THE YEAR 67291. 72675. 78489. 2610495. 91549. RETIREMENTS DURING THE YEAR 0. 0. 0. 0. 0. BALANCE AT END OF YEAR 3502195. 3574870. 3653359. 6263854. 6355403. ACCUMULATED DEPRECIATION 923913. 1027821. 1133884. 1313080. 14947971. NET PLANT IN SERVICE 2578281. 2547049. 2519475. 4950773. 4860611. DEPRECIATION 102067. 103907. 106063. 177196. 161711. 2015 3800. 0. 0. 3800. 3652. 148. 114, 1421490. = 1520543. 626261. 874302. 41785. 6355403. 98873. 6454276. 1679219. 4775057. 184428. PAGE: 186 DATE: 21-May-83 TIME: 10:19 FILES: CHNMGT.D1 GASGT.D2 VERSION: FIN. FORE. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) CONTRACT YEAR 1 EXPENSES: $1,000 2 PRODUCTION O&M-EXCL FUEL 3 = PRODUCTION-FUEL 4 PURCHASED POWER 3S TRANSMISSION O&n & ADMIN & GENERAL-EXCL INSURANCE 7 LONG-TERM LEASES 8 ADDITIONAL G&T STAFF 9 SUSITNA BARGE EXP 10 =G & T ORGANIZATION 11 INSURANCE 12 DEPRECIATION 13 TAXES 14 INTEREST ON LONG-TERM DEBT 15 LESS: INTEREST CHARGED TO CONSTR 16 OTHER DEDUCTIONS 17 TOTAL POWER COST-ACCRUAL 18 LESS POWER SOLD 19 NET POWER COST-ACCRUAL 20 POWER COST-ACCRUAL (HILLS/KWH) 22 REVENUES: $1,000 23 REVENUES RE@D TO MAINTAIN TIER 24 LESS: WNON-OPERATING INCOME 25 LESS: OTHER OPERATING REVENUES 26 LESS: PATRONAGE CAPITAL RETIREMENT 27 REVENUES FROM RATEPAYERS 28 WHOLESALE REVENUES, MILLS/KWH 29 ANNUAL INCREASE % 31 MARGINS: $1,000 32 OPERATING MARGINS 33 NON-OPERATING INCOME = NET PATRONAGE CAPITAL OR MARGINS 36 OPERATING RATIOS: % OF POWER COST 37 =PROD & PURCH POWER EXPENSE 38 TRANSMISSION EXPENSE 39 ADMIN & GENERAL EXPENSE 40 OTHER EXPENSES a OPERATING REVENUE 43 FINANCIAL RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 45 DEBT SERVICE COVERAGE (DSC) 1983 5303. 5126. 1291. 881. 1676. 133. 0. 700. 200. 21. 7935. 4. — 7At: 45547. 45547. 27.14 48778. 320. 315. 0. 48142, 28.69 0.00 29710. 320. 3231. 25.73 1.93 3.73 68.61 107.09 1.15 1.32 1986 7739. 7631. 2220. 2321. 2483. 133. 1097. 440. 0. 241. i 36306. 0. 640. —_ 73684. 39.45 TABLE 14 PROJECTED OPERATING RESULTS 1984 1985 3863. 6921. 6146. 6517. 1252. 2029. 1067. 2060. 1849. 2222. 133. 133. 340. 770. 720. 742. 200. 150. %, 198. 8494. 11736. 4. 4. 24670. 36414. 0. 0. 380. 609. or — 51563. 70504. 29.62 39.17 56497. 77787. 1049. 1165. 315. 315. 0. 0. 33133. 76307. 31.67 42.39 10.38 33.87 3885. 6118. 1049. 1165. 4934. 7283. 25.72 21.94 2.07 2.92 3.68 3.43 68.54 71.71 109.57 110.33 1.20 1.20 1.37 1.40 1987 8421. 9012. 2308. 2604, 2682. 133. 1563. 465. 0. 252. 12742. 4. 36180. 39.72 25.67 3.39 3.82 67.12 109. 41 88 1988 8993. 8195. 28146. 3702. 2897. 133. 2227. 492. 0. 344. 15263. 40614. na 131897. 111497, 35.64 119620. 3385. 315. 0. 115920. 37.84 38.37 4738. 3385. 6123. 40.66 3.32 2.91 33.11 107.29 1989 9789. 9644. 3129. 3174. a 115800; 37.74 123966. 315. 122720. 61.15 3.71 7156. 8086. 41.34 3.51 3.01 52.14 106.98 oe ary Bs PAGE: 187 DATE: 21-May-83 TIME: 10:19 FILES: CHMGT.D1 GASGT. D2 VERSION: FIN. FORE. 1990 1991 10630. 11576. 11364. 62604, 28710. 29003. 4457. 4881. 3378. 3649. 133. 133. 3428. 3702. 553. 588. 0. 0. 371. 386. a — 40218. 39970. 0. 0. 367. 613. — — 119599, 173318. 36.55 77.62 127637. 181312. 1407. 1790. 315. 315. 0. 0. 125914. 179207. 39.53 80.25 2.64 34.80 6636. 6204. 1407. 1790. 8044. 7994. 42.40 59.53 3.73 2.82 3.13 2.33 50.74 35.32 106.73 104. 61 1.20 1.20 1.43 1.43 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BURNS & NCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) CONTRACT YEAR 1 EXPENSES: $1,000 2 PRODUCTION O&M-EXCL FUEL 3 > = PRODUCTION-FUEL 4 PURCHASED POWER 3 TRANSMISSION 08" & ADMIN & GENERAL-EXCL INSURANCE 7 LONG-TERM LEASES 8 ADDITIONAL C&T STAFF 9 SUSITNA BARGE EXP 10 =G & T ORGANIZATION 11 INSURANCE 12 DEPRECIATION 13. TAXES 14 INTEREST ON LONG-TERM DEBT 15 LESS: INTEREST CHARGED TO CONSTR 16 OTHER DEDUCTIONS 17 TOTAL POWER COST-ACCRUAL 18 LESS POWER SOLD 19 NET POWER COST-ACCRUAL 20 POWER COST-ACCRUAL (MILLS/KWH) 22 REVENUES: $1,000 23 REVENUES RE@D TO MAINTAIN TIER 24 LESS: NON-OPERATING INCOME LESS: OTHER OPERATING REVENUES 26 LESS: PATRONAGE CAPITAL RETIREMENT REVENUES FROM RATEPAYERS WHOLESALE REVENUES, MILLS/KWH ANNUAL INCREASE % MARGINS: $1,000 OPERATING MARGINS NON-OPERATING INCOME NET PATRONAGE CAPITAL OR MARGINS OPERATING RATIOS: % OF POWER COST PROD & PURCH POWER EXPENSE TRANSMISSION EXPENSE ADMIN & GENERAL EXPENSE OTHER EXPENSES OPERATING REVENUE FINANCIAL RATIOS: TIMES INTEREST EARNED RATIO (TIER) DEBT SERVICE COVERAGE (DSC) TABLE 14 PROJECTED OPERATING RESULTS 1992 1993 1994 1995 1996 125469. 13708. 14875. 16203. 17657. 73447. 95670. 115312. 217101. 332995. 29501. 30105. 30677. 31910. 33640. 3338. 3832. 6366. 6741. 73580. 3940. 4255. 4596. 4964, 5361. 133. 133. 133. 133. 133. 3998. 4318. 4664, 3037. 3440. 625. 665. 708. 755. 805. 0. 0. 0. 0. 0. 402. 420. 439. 460. 483. leer. a at ae ay 39662. 39277. 38857. 40721. 42707. 0. 0. o. 0. 0. 662. 715. 772. 834. 900. era aa* ate oe ae 188953. 212274. 235115. 343357. 466630. 81.73 88.52 94.54 133.39 174.96 196885. 220127. 242886. 351501. 475171. 2055. 2199. 2240. 2176. 3712. 315. 315. 315. 315. 315. 0. 0. 0. 0. 0. 194515. 217615. 240331. 347010. 471144, 84.13 90.75 96.63 135.59 176.48 4.83 7.88 6.49 40.31 30.29 3878. 5657. 3531. 3968. 4829. 2055. 2199. 2240. 2176. 3712. 7932. 7855. 7771. 8144, 8541. 62.19 65.71 68. 42 77.24 82.35 2.82 2.75 2.71 2.02 1.42 2.30 2.20 2.14 1.58 1.25 32.68 29.34 26.73 19.16 14.77 104.20 103.70 103.31 102.37 101.83 1.20 1.20 1.20 1.20 1.20 1.41 1.41 1.41 1.39 1.38 1997 19128. 335647. 35700. 8289. 3790. 133. 3875. 859. 0. 507. 19604. 4. 42121. 0. 972. ree 674628. 244.08 683053. 3269. 315. 0. 677469. 245.10 38.75 3155. 3269. 8424. 87.53 1.23 0.93 10.31 101.25 1.20 1.38 PAGE: 188 DATE: 21-May-83 TIME: 10:19 FILES: CHNGT.D1 1998 20864. 615126. 39833. 9054. 6254. 133. 6345. 918. 0. 333. a 41477. 0. 1050. danke 761930. 265.85 770225. 4853. 315. 0. 765055. 266.94 8.91 3440. 4855. 8295. 88.70 1.19 0.89 9.22 101.09 i s 88 GASGT. D2 1999 22616. 676881. 49106. 9880. 6754. 133. 6852. 981. 0. 362. 21 iste 43952. 0. 1134. ain . 839987. 283.01 848777. 4332. 315. 0. 844131. 284. 41 6.54 4459. 4332. 8790. 89.12 1.18 0.87 8.83 101.05 1.20 1.39 VERSION: FIN. FORE. 2000 24606. 737600. 75941. 10796. 7294. 133. 7401. 925. 0. 593. aiyee. 43184. 0. 1225. ere 951690. 309. 39 960327. 5984. 315. 0. 954027. 310.15 9.05 2653. 3984. 8437. 90.17 1.13 0.83 7.87 100.91 1.20 1.39 BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(BZ, 20YR) CONTRACT YEAR 1 EXPENSES: $1,000 PRODUCTION O&M-EXCL FUEL PRODUCT ION-FUEL PURCHASED POWER TRANSMISSION O&M ADMIN & GENERAL-EXCL INSURANCE LONG-TERM LEASES ADDITIONAL G&T STAFF SUSITNA BARGE EXP 10 G & T ORGANIZATION 11 INSURANCE 12 DEPRECIATION 13. TAXES 14 INTEREST ON LONG-TERM DEBT 15 LESS: INTEREST CHARGED TO CONSTR 16 OTHER DEDUCTIONS 17 TOTAL POWER COST-ACCRUAL 18 LESS POWER SOLD 19 NET POWER COST-ACCRUAL 20 POWER COST-ACCRUAL (MILLS/KWH) 22 REVENUES: $1,000 23 REVENUES RE@D TO MAINTAIN TIER 24 LESS: NON-OPERATING INCOME SONU DWH 25 LESS: OTHER OPERATING REVENUES 26 LESS: PATRONAGE CAPITAL RETIRENENT 27 REVENUES FROM RATEPAYERS 28 WHOLESALE REVENUES, MILLS/KWH a ANNUAL INCREASE % 31 MARGINS: $1,000 32 OPERATING MARGINS 33 NON-OPERATING INCOME S NET PATRONAGE CAPITAL OR MARGINS 36 OPERATING RATIOS: % OF POWER COST 37 =PROD & PURCH POWER EXPENSE 38 TRANSMISSION EXPENSE 39 ADMIN & GENERAL EXPENSE 40 OTHER EXPENSES 4 OPERATING REVENUE 43 FINANCIAL RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 45 DEBT SERVICE COVERAGE (DSC) 2001 34895. 799893. 40518. 11784. 10354. 133. 7993. 999. 0. 1880. 7 101207. 0. 1323. wr 1048958. 329.03 1069199. 6225. 315. 0. 1062659. 333.33 7.7 14017. 6225. 20241. 2004 2005 44707. 48694. 1117271. 1292021. 93350. 89409. 15339. 16718. 13044. 14088. 133. 133. 10068. 10874. 1258. 1359. 0. 0. 1997. 2042. ai2i7. 42475. 98063. 96770. 0. 0. 1666. 1799. 1440117. “ar 0. s 1440117. 1616385. 405.78 439.71 1459730. 1635739. 11365. 11376. 315. 315. 4934. 7283. 1443116. 1616745. 6.63 439.82 7.93 8.16 8248. 7978. 11365. 11376. 19613. 19354. 87.31 88. 48 TABLE 14 PROJECTED OPERATING RESULTS 2002 2003 37967. 41147. 908485. 1000185. 44322. 64475. 12879. 14061. 11183. 12078. 133. 133. 8632. 9323. 1079. 1165. 0. 0. 1916. 1955. = — 100273. 99229. 0. 0. 1428. 1543. ug y a 1167275. 1285350. 353. 18 375.18 1187327. 1305196. 10044. 10958. 315. 315. 0. 3231. 1176968. 1290692. 356.12 376.73 6.84 3.79 10009. 8888. 10046. 10958. 20055. 19846. 84.88 86.03 1.10 1.09 1.07 1.03 1.12 1.09 1.04 1.00 12.90 11.78 10.58 9.49 101.72 101.54 101.36 101.20 1.20 1.20 1.20 1.20 1.43 1.43 1.43 1.43 2006 32778. 1396249. 194421. 18208. 15215. 133. 11744. 1468. 0. 2071. — 95331. 0. 1943. — 1833418. 480.96 1852485. 10915. 315. 7261. 1833993. 481.11 9.39 8151. 10915. 19066. 89.64 0.99 0.94 8.42 101.04 1.20 1.42 2007 37381. 1617422. 149991. 19816. 16432. 133. 12683. 1585. 0. 2144. —_ 93722. 0. 2099. 20187. > 2018713. 511.20 2037458. 10142. 315. 7236. 2019765. 311.46 6.31 8603. 10142. 18744. 90.39 0.98 0.92 7.70 100.93 1.20 1.42 PAGE: 189 DATE: 21-May-83 TIME: 10:19 FILES: CHMGT.D1 GASGT.D2 VERSION: FIN. FORE. 2008 2009 90121. 97878. 1648459. 1856777. 39160. 72069. 21553. 23430. 26238. 28337. 133. 133. 13698. 14794. 1712. 1849. 0. 0. 6499. 6561. 78507. 100218. aaoeat. 278507. 2267. 2448. 2249233. 2483006. CHUGACH, PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) CONTRACT YEAR 1 EXPENSES: $1,000 2 PRODUCTION O8M-EXCL FUEL 3 = PRODUCTION-FUEL 4 PURCHASED POWER 5 TRANSMISSION 08" & ADMIN & GENERAL-EXCL INSURANCE 7 LONG-TERM LEASES 8 ADDITIONAL G&T STAFF 9 SUSITNA BARGE EXP 10 G & T ORGANIZATION 11 INSURANCE 12 DEPRECIATION 13 TAXES 14 INTEREST ON LONG-TERM DEBT 15 LESS: INTEREST CHARGED TO CONSTR 16 OTHER DEDUCTIONS 17 TOTAL POWER COST-ACCRUAL 18 LESS POWER SOLD 19 NET POWER COST-ACCRUAL 3 POWER COST-ACCRUAL (MILLS/KWH) 22 REVENUES: $1,000 23 REVENUES REQ@D TO MAINTAIN TIER 24 LESS: NON-OPERATING INCOME 25 LESS: OTHER OPERATING REVENUES 26 LESS: PATRONAGE CAPITAL RETIRENENT 27 REVENUES FROM RATEPAYERS WHOLESALE REVENUES, MILLS/KWH ANNUAL INCREASE % MARGINS: $1,000 OPERATING MARGINS NON-OPERATING INCOME NET PATRONAGE CAPITAL OR MARGINS OPERATING RATIOS: % OF POWER COST PROD & PURCH POWER EXPENSE TRANSMISSION EXPENSE ADMIN & GENERAL EXPENSE OTHER EXPENSES OPERATING REVENUE FINANCIAL RATIOS: TIMES INTEREST EARNED RATIO (TIER) DEBT SERVICE COVERAGE (DSC) BPSPSSSBLKALBRLSVS BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM HOMER & MATANUSKA ELEC. ASSOCIATIONS TABLE 14 PROJECTED OPERATING RESULTS 2010 2011 2012 2013 2014 106422. 115104. 125071. 175334. _ 190605. 2110536. 2276932. 2561894. 2798271. 3148837. 99312. 175636. 254049. | 76045. 93440. 25456. 27645. 30009. 32561. 35918. 30605. 33053. 35697. 51031. 55113. 133. 133. 133. 133. 133. 15977. 17256. 18636. 20127. ~—«-21737. 1997. 2157. 2329. 2516. 2717. 0. 0. 0. 0. 0. 6628. 6700. 6778. 13176. 13267. 102067. 103907. 106063. 179196. 181711. 275914. 273028. 249853. 544195. 340550. 2644, 2856. 3084. 3331. 3597. 2777694. 3039410. 3413600. 3895721. 4287030. 2777694, 3034410, 3413600. 3895921, 4287030. 632.01 666.78 723.37 796.71 844.07 2832877. 3087016. 3467571. 4004760. 4395140. 22717. 27170. 31142. 39684. 52872. 315. 315. 315. 315. 315. 8044. 7994. 7932. 7855. 7771. 2801802, 3053537, 3428182. 3956905. 4334181. 637.50 670.96 726.46 809.18 855.37 7.66 5.25 8.27 11.39 5.71 32466. 27435. 22829. 69155. 55238. 22717. 27170. 31142. 39684. 52872. 55183. 54606. 53971. 108839. 108110. 83.39 84.62 86.16 78.28 980.08 0.92 0.91 0.88 0.84 0.82 1.34 1.31 1.24 1.65 1.60 14.35 13.16 11.72 19.24 17.51 101.99 101.80 101.58 102.79 102.52 1.20 1.20 1.20 1.20 1.20 1.44 1.43 1.43 1.44 1.45 I i pate || aan ||. ||| 2015 PRESENT 207179. 3523752. 163910. 38297. 39522. 133. 23476. 2934. 0. 13365. 104428. 536476. 0. 3885. 4737360. 0. 4737360. 906. 34 4864655. 65291. 315. 8144. 4790905. 912. 6. 73 71 42004. 65291. 107295. 81. 0. 1. 15. 102. 1. 1. 87 80 33 79 26 20 43 VALUE (1983$) 4116803. PAGE: 190 DATE: 21-May-83 TIME: 10:19 FILES: CHMGT.D1 GASGT.D2 VERSION: FIN. FORE. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) CONTRACT YEAR CASH REVENUE: $1,000 WHOLESALE REVENUES OTHER OPERATING INCOME NON-OPERATING INCOME TOTAL REVENUE CASH EXPENDITURES: $1, 000 OPERATING EXPENSE LESS DEPRECIATION PRINCIPAL PAYMENTS TOTAL CASH EXPENDITURES ANNUAL MARGINS MARGINS APPLIED TO PLANT INVESTMENT MARGINS APPLIED TO LOAN RETIREMENT PATRONAGE CAPITAL RETIREMENT CUMULATIVE MARGINS © CUM. MARGINS AS % OF PLANT INVESTNENT 2 1983 48142. 315. 48778. 37612. 3160. 40772. 0. 0. 0. 2.9 1986 78187. 315. 2442. 80945. 61256. 3486. 64743. 16202. 10612. 0. 0. 28014. TABLE 15 CASH OPERATING MARGINS ($1, 000) 1984 1985 35133. 76307. 315. 315. 1049. 1165. 36497. 77787. 43069. 58768. 3222. 3286. 46291. 62055. 10206. 15732. 11518. 0. 0. 0. 0. 0. 6693. 22426. 2.1 3.3 6.4 1987 809723. 315. 2887. 84125. 64148. 3839. 67987. 16139. 11441. 0. 0. 32693. 7.3 1988 115920. 315. 3385. 119620. 96234. 4159. 100393. 19227. 50000. 0. 0. 1921. 0.4 1989 122720. 315. 123966. 100249. 104548. 19418. 13368, 0. 0. 7971. 1.4 PAGE: 191 DATE: 21-May-83 TIME: 10:19 FILES: CHMGT.D1 GASGT. D2 VERSION: FIN. FORE. 1990 1991 125914. 179207. 315. 315. 1407. 1790. 127637. 181312. 103813. 157109. 4582. 3012. 108395. 162121. 19242. 19191. 14437. 15592. 0. 0. 0. 0. 12775. 16375. 2.2 2.8 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 192 POWER SUPPLY PROGRAM DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:19 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT. D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, 20YR) VERSION: FIN. FORE. TABLE 15 CASH OPERATING MARGINS ($1, 000) CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 CASH REVENUE: $1,000 WHOLESALE REVENUES 194515. 217615. 240331. 347010. 471144. 677469. 765055. 844131. 954027. OTHER OPERATING INCOME 315. 315. 315. 315. 315. 315. 315. 315. 315. NON-OPERATING INCOME 2055. 2199. 2240. 2176. 3712. 3269. 4855. 4332. 5984. TOTAL REVENUE 196885. 220129. 242886. 351501. 475171. 683053. 770225. 848777. 940327. CASH EXPENDITURES: $1,000 OPERATING EXPENSE LESS DEPRECIATION 172281. 195103. 217404. 325063. 447706. 655024. 741572. 9818855. 929701. PRINCIPAL PAYMENTS 5989. 6353. 6753. 7482. 8016. 8572. 8936. 9271. 9965. TOTAL CASH EXPENDITURES 178270. 201456. 224156. 332544. 455721. 663596. 750528. 9828126. 939666. ANNUAL MARGINS 18615. 18673. 18730. 18957. 19450. 19457. 19698. 20652. 20660. MARGINS APPLIED TO PLANT INVESTMENT 16840. 18187. 19642. 0. 0. 24743. 26722. 0. 31169. MARGINS APPLIED TO LOAN RETIREMENT 0. 0. 0. 0. 0. 0. 0. 0. 0. PATRONAGE CAPITAL RETIREMENT 0. 0. 0. 0. 0. 0. 0. 0. 0. CUMULATIVE MARGINS 18149. 18636. 17723. 36680. 56130. 50844. 43820. 64471. 53962. CUM. MARGINS AS % OF PLANT INVESTMENT 3.0 3.0 2.8 5.6 8.2 7.2 6.0 8.5 6.8 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 193 POWER SUPPLY PROGRAN DATE: 21-May-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 10:19 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT. D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) VERSION: FIN. FORE. TABLE 15 CASH OPERATING MARGINS ($1,000) CONTRACT YEAR 2001 2002 2003 2004 2005 2006 2007 2008 2009 CASH REVENUE: $1,000 WHOLESALE REVENUES 1062659. 1176968. 12970692. 1443116. 1616765. 1833993. 2019765. 2284506. 2512514. OTHER OPERATING INCOME 315. 315. 315. 315. 315. 315. 315. 315. 315. NON-OPERATING INCOME 6225. 10046. 10958. 11365. 11376. 10915. 10142. 12465. 17792. TOTAL REVENUE 1069199. 1187329. 13051946. 1459730. 1635739. 1852485. 2037458. 2305409. 2538707. CASH EXPENDITURES: $1,000 OPERATING EXPENSE LESS DEPRECIATION 1010984. 1128302. 1245298. 1398901. 1573911. 1789585. 1973412. 2150727. 2382788. PRINCIPAL PAYMENTS 10520. 11196. 12215. 13353. 14337. 15758. 17089. 22246. 23539. TOTAL CASH EXPENDITURES 1021504. 1139498. 1257513. 1412254. 1588247. 1805342. 1990501. 2172972. 2406327. ANNUAL MARGINS 47895. 47831. 47683. 47476. 47492. 47142. 46957. 132437. 1932381. MARGINS APPLIED TO PLANT INVESTMENT 0. 36355. 39264. 42405. 45797. 47461. 53418. 37692. 62307. MARGINS APPLIED TO LOAN RETIREMENT 0. 0. 0. 0. 0. 0. 0. 0. 0. PATRONAGE CAPITAL RETIRENENT 0. 0. 3231. 4934. 7283. 7261. 7236. 8123. 8084. CUMULATIVE MARGINS 101658. 113134. 118322. 118459. 112871. 103291. 89594. 156216. 218203. CUM. MARGINS AS % OF PLANT INVESTHENT 7.6 8.3 8.4 8.2 7.6 6.7 5.6 4.6 6.4 BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8Z, 20YR) TABLE 15 CASH OPERATING MARGINS ($1,000) CONTRACT YEAR 2010 2011 2012 2013 2014 CASH REVENUE: $1,000 WHOLESALE REVENUES 2801802. 3059537. 3428182. 37546705. 4334181. OTHER OPERATING INCOME 315. 315. 315. 315. 315. NON-OPERATING INCOME 22717. 27170. 31142. 37684. 52872. TOTAL REVENUE 2832877. 3089016. 3447571. 4004760. 4395140. CASH EXPENDITURES: $1,000 OPERATING EXPENSE LESS DEPRECIATION 2675627. 29730503. 3307537. 3716724. 4105318. PRINCIPAL PAYMENTS 25743. 28012. 27900. 31779. 31124. TOTAL CASH EXPENDITURES 2701370. 2958515. 3337437. 3748503. 4136442. ANNUAL MARGINS 131507. 130501. 130134. 256256. 258697. MARGINS APPLIED TO PLANT INVESTMENT 67291. 72675. 78489. 84768. 91549. MARGINS APPLIED TO LOAN RETIREMENT 0. 0. 0. 0. 0. PATRONAGE CAPITAL RETIREMENT 8044. 7994. 7932. 7855. 7771. CUMULATIVE MARGINS 274376. 324208. 367920. 531553. 6909730. CUM. MARGINS AS % OF PLANT INVESTMENT 7.8 9.1 10.1 8.5 10.9 2015 4790905. 315. 65271. 4864455. 9572932. 41303. 4614235. 250420. 98873. 0. 8144. 834333. 12.9 PAGE: 194 DATE: 21-May-83 TIME: 10:19 FILES: CHNGT.D1 GASGT. D2 VERSION: FIN. FORE. CT te APPENDIX C — PROJECTED OPERATING ~ RESULTS ; wee nme Gas-Fired Expansion Scenario Existing Arrangement 20-Year Capital Credit Rotation BURNS & MCDGNNELL ENGINEERING COMPANY PAGE: 180 POWER SUPPLY PROGRAM DATE: 99-Mar-83 CHUGACIL HGHER & MATAMUSKA ELEC. ASSCCIATIONS TIME: 14:53 PROJECT: 62~11 -000 : FILES: CHM.D1 BRADLEY LAKE “FIRED GENERATION GAS. 02 EXISTING GRGANTZal LOMA STRUCTURE PLAN: GAS(GX, 20YR) VERSION: FIN. FORE. TABLE 14 PROJECTED OPERATING RESULTS CONTRACT YEAR 1983 1984 1985 1986 1987 1988 1989 1990 1991 EXPENSES: $4,000 2 PRODUCTICH Oare-ExOL FUEL 3303. 3863. 6921. 7739. 8421. 8993. 9789. 10630. 11576. 3 PRODUCTION FUEL 5126. 6146. 6517. 7631. 9012. 8195. 9644. 11364. $2604, 4 — PURCHASED POUFR 1291. 1252. 2029. 2220. 2308. 28146. 28477. 28710. 29003. 5 TRAKSHISSION Ox 881. 1047. 2060. 2290. 2540. 3602. 3909. 4241. 4599. & ADMIN & GEHERAL-EXCL INSURANCE 1676. 1849. 2222. 2483. 2682. 2897. 3129. 3378. 3649. 7 ~LOWC-TERM LE 133. 133. 133. 133. 133. 133. 133. 133. 133. 8 HOrER XMS5H I pri 336. 385. 377. 370. 367. 359. 349. 341. 335. 9 SUSTTNA BARGE EXP 700. 720. 742. 440. 465. 492. 322. 333. 388. 10) ATAM XPS LEASE Prt 149. 178. 175. 172. 170. 167. 164. 161. 138. 1100 INSURANCE 21. 46. 198. 241. 252. 343. 356. 370. 385. 12 E SLATION 7773. 8333. 11574. 12265. 12580. 15101. 15468. 15618. 16047. 13° TAXES 4. 4. 4. 4. 4. 4. 4. 4. 4. 14 THTEREST OM LONG-TERM DEBT 21302. 24441. 30199. 30098. 27984. 30083. 29476. 29298. 25908. 15) LESS: INTEREST CHARGED TO CONSTR 0. 0. 0. 0. 0. 0. 0. 0. 0. 16 9 OTHER DEDUCTIONS 741. 580. 609. 640. 324. 486. 325. 367. 613. 17 TOTAL. PQWER COST-ACCRUAL 45937. 50996. $3760. 66727. 67441. 97002. 101945. 105368. 155602. 18 LEGS Pal SOLD 0. 0. 0. 0. 0. 0. 0. 0. 0. 19 KET POWER COST-ACCRUAL 45437. 50996. 63760. 46727. 67441. 97002. 101745. 105368. 155602. | PQWER COST-ACCRUAL (MILLS/KWH) 27.08 29.29 35.42 35.72 34.84 49.40 30.79 49.82 69.68 22 REVENUES: $1, 000 23° REVENUES REGD TO MAINTAIN TIER 48633. 73437. 93959. 96825. 93424. 127085. 131421. 134666. 181510. 24 LESS: HON-OPERATING INCOME 320. 1829. 3644. 2397. 4596. 3093. 2681. 4340. 4255. 235) LESS: OTHER GPERATIHG REVENUES 315. 315. 315. 315. 315. 315. 315. 315. 315. 26 LESS: PATROMAGE CAPITAL RETIREMENT 0. 0. 0. 0. 0. 0. 0. 0. 0. 27 REVENUES FROM RATEPAYERS * 47998. 73293. 970000. 94113. 90513. 123677. 128426. 129811. 176940. 28 WHOLESALE NUES, MILLS/KWH 28.40 42.10 50.00 30.38 46.75 61.72 3.99 61.38 79.24 a ANNUAL THCREASE % 6.00 47.18 18.77 0.76 -7.20 32.00 3.468 -4.08 29.10 31 MARGINS: $1,000 32 OPERATING PIARGINS 2876. 22612. 26556. 27701. 23387. 24991. 26796. 24758. 21653. 33° NOU-GPERATING INCOME 320. 1829. 3644, 2397. 4596. 5093. 2681. 4540. 4255. Ee HET PATRGWAGE CAPITAL OR MARGINS 3195. 24441. 30199. 30098. 27984. 30083. 29476. 29298. 25908. 3 36 OPERATING RAT LOS: 37) PRUD & PURCH POU % OF POWER COST 25.79 26.00 24.26 26.36 29.27 43.79 47.00 48.12 66.31 38 TRANSIT WE E 1.94 2.09 3.23 3.43 3.77 3.64 3.83 4.02 2.96 3? ADITIN & IERAL EXPEHSE 3.73 3.72 3.80 4.08 4.35 3.27 3.42 3.56 2.59 40 OUIER E 68.53 68.19 68.72 66.12 62.461 47.30 45.75 44.30 28.14 2 OPERATING REVENUE 107.03 147.93 147.38 145.11 141.49 130.39 128.91 127.81 116.45 43 FIHANCTAL RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 1.15 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 45 DEBT SERVICE COVERAGE (DSC 1.33 2.08 2.16 2.17 2.18 2.23 2.24 2.23 2.26 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 181 POWER SUPPLY PROGRAM DATE: 9-Mar-83 CHUGACH, HOPER & HATANUSKA ELEC. ASSCCIATIONS TIME: 14:53 PROJECT: 82-113-4-000 FILES: CHN.D1 BRADLEY LAKE, FIRED GENERATION GAS. D2 EXISTING GRCANIZATIONAL STRUCTURE PLAH: GAS(8%, 20YR) . VERSION: FIN. FORE. TABLE 14 PROJECTED OPERATING RESULTS CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 1 EXPENSES: $1,060 2 PRODUCTION O&N-EXCL FUEL 12569. 13708. 14875. 16203. 17657. 19128. 20864. 22616. 244064. 3 PRODUCTIGN-FUEL. 75447. 95670. 115312. 217101. 332795. 535647. 615126. 676881. 757600. 4 PURCHASED POWER 29501. 30105. 30677. 31910. 33640. 35700. 39833. 49106. 75941. 5 TRANSMISSION O&M 4985. 5404. 5855. 6342. 6868. 7454. 8108. 8834. 9643. 6 ADMIN & GEHERAL~EXCL INSURANCE 3940. 4255. 4596. 4964. 5361. 5790. 6254. 6754. 7294. 7 LONG-TERM LEASES 133. 133. 133. 133. 133. 133. 133. 133. 133. 8 HOMER XMSN LEASE Prt 329. 320. 313. 278. 269. 262. 254. 237. 228. 9 SUSITNA BARGE EXP 625. 645. 708. 755. 805. 859. 918. 981. 925. 10 = NATAN XMSN LEASE Prt 155. 151. 148. 145. 142. 137. 131. 127. 122. 11 INSURANCE 401. 419. 438. 459. 482. 507. 533. 342. 373. 12 DEPRECIATION 16509. 17009. 17548. 18131. 187641. 19442, 20177. 20971. 21827. 13° TAXES A 4. 4. 4. 4. 4. 4. 4. 4. 14 INTEREST OH LONG-TERM DEBT 21097. 20864. 20612. 20335. 22545. 24930. 27504. 30290. 29869. 15 LESS: INTEREST CHARGED TO CONSTR 0. 0. 0. 0. 0. 0. 0. 0. 0. 16 OTHER DEDUCTIONS 662. 715. 772. 834. 900. 972. 1050. 1134. 1225. 17 TOTAL POWER COST-ACCRUAL 166359. 189422, «211992. 9317593. 440562. 650965. 740890. 8184630. 930009. 18 LESS POWER SOLD 0. 0. 0. 0. 0. 0. 0. 0. 0. 12? NET POWER COST-ACCRUAL 146359. 187422. 211992. 3175973. 440562. 650965. 740890. 818630. 730009. = PQUER COST-ACCRUAL (MILLS/KWH) 71.95 78.99 85.24 123.39 165.19 235.52 258.51 275.82 302.34 22 REVENUES: $1,000 23) REVENUES REQD TO MAINTAIN TIER 187456. 210286. 232605. 337928. 463107. 675895. 768394. 848920. 959877. 24 > HGN-OPERATING INCOrE 3095. 4398. 5395. 6674. 7724. 10683. 13880. 17348. 20962. 25 : OTHER OPERATING REVENUES 315. 315. 315. 315. 315. 315. 315. 315. 315. 26 LESS: PATROWACE CAPITAL RETIREMENT 0. 0. 0. 0. 0. 0. 0. 0. 0. 27 REVENUES FROM RATEPAYERS 184046. 9205573. 226694. 9330937. 455067. 664897. 754199. 831256. 938600. 28° WHOLESALE REVENUES, MILLS/KWH 79.60 85.73 91.15 128.57 170.63 240.56 263.15 280.07 305.14 2 ANNUAL INCREASE % 0.46 7.69 6.33 41.05 32.71 40.98 9.39 6.43 8.95 31 MARGINS: $1,000 32 OPERATING MARGINS 18002. 16466. 15017. 134641. 14820. 14247. 13624. 12942. 8907. 33 0 NOW-GPERATING INCOPE 3095. 4398. 5595. 4674. 7724. 10483. 13880. 17348. 20962. 34 NET PATRONAGE CAPITAL OR MARGINS 21097. 20844. 20612. 20335. 22545. 24930. 27504. 30290. 29869. 35 36 OPERATING RATIOS: % OF PQWER COST 37 PROD & PURCH POWER EXPENSE 70.64 73.64 73.88 83.51 87.23 90.71 91.22 91.45 92.27 38 SHISS LUN EXPENSE 3.00 2.85 2.76 2.00 1.56 1.15 1.09 1.08 1.04 39 {hi % GEWERAL EXPENSE 2.61 2.47 2.37 1.71 1.33 0.97 0.92 0.89 0.85 40 OIHER EXPE 3 23.73 21.04 18.98 12.79 9.89 7.18 6.77 6.58 5.84 41 QUERATING E 112.48 111.01 109.72 106.40 105.12 103.83 103.71 103.70 103.21 43 FINAHCTAL RATIOS: 44 TIES INTEREST EARNED RATIO (TIER) 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 43 DEBT SERVICE COVERAGE (DSC) 2.29 2.29 2.30 2.27 2.26 2.24 2.24 2.24 2.24 f ; Se a = FP Pe Pee esos BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 182 POWER SUPPLY PROGRAM DATE: 9-Mar-83 CHUGACH, HOMER 2 TATANUSKA ELEC. ASSCCIATIONS TIME: 14:53 PROJECT: 82-:113~-4-000 FILES: CHN.D1 BRADLEY LAKE, GAS-FIREN GENERATION GAS. D2 EXISTING ORGANIZATIONAL STRUCTURE PLAN: GAS(B%, 20YR) VERSION: FIN. FORE. TABLE 14 PROJECTED OPERATING RESULTS CONTRACT YEAR 2001 2002 2003 2004 2005 2006 2007 2008 2007 1 EXPENSES: $1,000 2 PRODUCTION O&M-EXCL FUEL 34895. 37967. 41147. 44707. 48674. 52778. 37381. 90121. 97878. 3 PRODUC TIGN-FUEL 799893. 908485. 1000185. 1117271. 1292021. 1376249. 1617422. 1648459. 1856777. 4 PURCHASED POWER 40518. 44322. 64475. 95350. 89409. 194421. 149991. 39160. 72069. 3 TRANSMISSION O&M 10515. 11458. 12475. 13576. 14763. 16046. 17431. 18926. 20542. 6 ADMIN & GENERAL-EXCL INSURANCE 10354. 11183. 12078. 13044. 14088. 13215. 16432. 26238. 28337. 7 LONG-TERM LEASES 133. 133. 133. 133. 133. 133. 133. 133. 133. 8 HOMER XriSN LEASE PMT 219. 211. 202. 195. 115. 109. 102. 93. 85. 9 SUSITHA BARGE EXP 999. 1079. 1165. 1258. 1359. 1468. 1585. 1712. 1849. 10s MATAN XrSN LEASE PMT 118. 113. 107. 100. 94, 88. 83. 76. 47. 11) INSURANCE 1880. 1916. 1955. 1997. 2042. 20971. 2144. 6499. 6561. 12. DEPRECIATION 37812. 38810. 39889. 41054. 42312. 43671. 43139. 98344. 100054. 13° TAXES 4. 4. 4. 4. 4. 4. 4. 4. 4. 14 INTEREST GN LONG-TERM DEBT 735225. 69980. 68851. 68518. 68129. 67675. 67157. 212657. 211704. 15 LESS: INTEREST CHARGED TO CONSTR 0. 0. 0. 0. 0. 0. 0. 0. 0. 16 = OTHER DEDUCTIONS 1323. 1428. 1543. 16464. 1799. 1943. 2099. 2267. 2448. 17 TOTAL POWER COST-ACCRUAL 1013889. 1127090. 1244210. 1398874. 1574962. 1791891. 1977102. 2164690. 23978510. 18 LESS POWER SOLD 0. 0. 0. 0. 0. 0. 0. 0. 0. 19 HET POWER COST-ACCRUAL 1013889. 1127070. 1244210. 1398874. 1574762. 17918971. 1977102. 2164690. 2378510. a PQUER COST~ACCRUAL. (MILLS/KWH) 318.03 341.03 363.17 394.16 428.44 470.07 500. 66 329.13 3465.29 22 REVENUES: $1,000 23° REVENUES REQO TO MAINTAIN TIER 1089114. 1197070. 1313062. 1467393. 1643091. 18597566. 2044259. 2377346. 2610214. 24 LESS: NON-OPERATING INCOME 24532. 23499. 25317. 29118. 32282. 34737. 36936. 46821. 32806. 25° LESS: OTHER OPERATING REVENUES 315. 315. 315. 315. 315. 315. 315. 315. 315. 26 LESS: PATRONAGE CAPITAL RETIREMENT 0. 0. 3195. 24441. 30199. 30098. 27984. 30083. 29476. 27 REVENUES FROM RATEPAYERS 1064266. 1173256. 1284234. 1413518. 1580294. 1794415. 1979024. 2300127. 2547616. 28 WHOLESALE REVEHUES, MILLS/KWH 333.84 354.99 374.85 398.29 429.90 470.73 301.15 362.24 600. 43 a ANNUAL INCREASE % 9.41 6.34 5.59 6.25 7.94 9.50 6.46 12.19 6.79 31 MARGINS: $1,000 32 OPERATING MARGINS 50493. 45481. 43535. 374400. 35847. 32938. 30221. 165836. 178898. 33 = NOWN-OPERATING TNCOLIE 24532. 23499. 25317. 27118. 32262. 34737. 36936. 46821. 32806. NET PATRONAGE CAPITAL OR MARGINS 75225. 69980. 68851. 68518. 68129. 67675. 67157. 212657. 211704. 34 OPERATING RATIGS: % OF POWER COST 37 PROD & PURCH POWER EXPENSE 86.33 87.91 88.68 89.83 90.80 91.72 92.30 83.05 84.50 38 TRAHSIITSSTUH EXPENSE 1.04 1.02 1.00 0.97 0.94 0.90 0.88 0.87 0.84 39 ADIN & GENERAL EXPENSE 1.21 1.16 1.13 1.08 1.02 0.97 0.94 1.51 1.45 40 OTHER EXPENSES 11.42 9.92 8.99 8.07 7.23 6.42 3.88 14.56 13.19 m4 OPERATING REVENUE 107. 42 106.21 105.53 104. 90 104.33 103.78 103. 40 109.82 108. 83 43 FINANCIAL RATIOS: 44 TINES INTEREST EARNED RATIO (TIER? 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 45 DEBT SERVICE COVERAGE (DSC) 2.30 2.43 2.48 2.48 2.48 2.48 2.49 2.37 2.37 BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSCCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION EXISTING ORGANIZATIONAL STRUCTURE PLAN: GAS(8%, 20YR) CONTRACT YEAR 1 EXPENSES: $1,000 PRODUCTION O&M-EXCL FUEL PRODUCT IGN-FUEL PURCHASED POWER TRANSMISSION O&M ADMIN & GENERAL-EXCL INSURANCE LONG-TERM LEASES HOMER XMSN LEASE Prt SUSITNA BARGE EXP MATAN XMSN LEASE PNT INSURANCE DEPRECIATION TAXES INTEREST ON LONG-TERM DEBT LESS: INTEREST CHARGED TO CONSTR OTHER DEDUCTIONS TOTAL POWER COST-ACCRUAL. LESS POWER SOLD NET POQUER COST-ACCRUAL PQWER COST-ACCRUAL (MILLS/KWH) 22 REVENUES: $1,000 DO et et et et et tt SVONAUDWNRKOMOOUNARU AW nN e 23° REVENUES REQD TO MAINTAIN TIER 24 LESS: NON-OPERATING INCOPE 23 LESS: OTHER OPERATING REVENUES 26 LESS: PATRONAGE CAPITAL RETIRENEHT 27 REVENUES FROM RATEPAYERS 28 WHOLESALE REVENUES, MILLS/KWH 2 ANHUAL INCREASE % 31 MARGINS: $1,000 32 OPERATING MARGINS 33 9 NON-GPERATING INCOME = NET PATRONAGE CAPITAL OR MARGINS 36 OPERATING RATIOS: % OF POUER COST 37 = PROD & PURCH POWER EXPENSE 38 TRANSMISSION EXPENSE 39 = =ADNHIN & GENERAL EXPENSE 40 OTHER EXPENSES - OPERATING REVENUE 43 FIHANCIAL RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 45 DEBT SERVICE COVERAGE (DSC) 2010 106422. 2110536. 99312. 22287. 30605. 133. 79. 1997. 59. 6628. pee 210642. 0. 2644. 2693250. 2693250, 612.80 2703892. 49652. 315. 29298. 2824627. 642.69 7.04 160990. 49652. 210642. 86.00 0.83 1.38 11.79 107.82 2.00 2.37 TABLE 14 PROJECTED OPERATING RESULTS 2011 2012 2013 115104. 125071. 175334. 2276932. 2561894. 2798271. 175436. 254049. 76045. 24171. 26206. 28404. 33053. 35697. 51031. 133. 133. 133. 58. 52. 44. 2157. 2329. 2516. 46. 13. 12. 6700. 6778. 13176. 103743. 105901. 179034. 209458. 208138. 362987. 2856. 3084. 3331. 2750052. 3327349. 3690322. 2950052. 3329349, 3690322. 648.22 705.52 754.67 3159510. 3537487. 4053308. 66081. 82310. 107500. 315. 315. 315. 25908. 21097. 20864. 3067205. 3433764. 3924629. 673.96 727.65 802.58 4.87 7.97 10.30 143377. 125828. 255486. 66081. 82310. 107500. 209458. 208138. 342987. 87.04 8834 82.64 0.82 0.79 0.77 1.35 1.28 1:74 10.79 9.60 14.85 107-10 106.25. 109.84 2.00 2.00 2.00 2.37 2.36 2.40 eee eel eee 2014 190605. 3148837. 93440. 30778. 55113. 133. 44. 2717. 10. 13267. 181549. 4081440. 805. 49 4442787. 32865. 315. 20612. 4368995. 862.24 7.43 308482. 52865. 361347. 84.11 0.75 1.68 13.46 108.85 2.00 2.40 2015 PRESENT 207179. 3523752. 1639710. 33342. 59522. 133. 0. 2934, 10. 13365. pea ida 3885. ave 4551474, 867.11 49710648. 85653. 315. 20335. 4804344, 915.29 6.15 273520. 85653. 359173. 85.57 0.73 1.60 12.09 107.87 2.00 2.34 VALUE (1983$) 4129770. PAGE: 183 DATE: 9-Har-83 TINE: 14:53 FILES: CHN.D1 GAS. D2 VERSION: FIN. FORE. we Perey Coal-Fired Expansion Scenario Existing Arrangement 20-Year Capital Credit Rotation CHUGACH, HOMER & MATANUSKA ELEC. PROJECT: 82-113-4-000 BRADLEY LAKE, EXISTING ORGANIZATIONAL STRUCTURE PLAN: COAL (8%, 20YR) CONTRACT YEAR : NSONAV DWN 35 36 37 38 39 40 4 42 43 44 45 EXPENSES: $1, 000 PRODUCTIGN O8&M-EXCL FUEL PRODUCT TON-FUE!_ PURCHASED POQUER TRANSMISSION 08M ADMIN & GENERAL-EXCL INSURANCE LONG-TERM LEASES HOMER XriSN LEASE PHT SUSITHA BARGE EXP MATAN XMSN LEASE PriT INSURANCE DEPRECIATION TAXES INTEREST OM LONG-TERM DEBT LESS: INTEREST CHARGED TO CONSTR OTHER DEDUCTIONS TOTAL POWER COST-ACCRUAL LESS POWER SOLD NET POWER COST~ACCRUAL PQWER COST-ACCRUAL (MILLS/KWH) REVENUES: $1,000 REVENUES RE@D TO MAINTAIN TIER LESS: NON-OPERATING INCOME LESS: OTHER OPERATING REVENUES LESS: PATRONAGE CAPITAL RETIREMENT REVENUES FROM RATEPAYERS WHOLESALE REVENUES, MILLS/KWH ANHUAL THCREASE % MARGINS: $1,000 OPERATING MARGINS NON-OPERATING IHCOME NET PATRONAGE CAPITAL OR MARGINS OPERATING RATIOS: % UF POWER COST PROD & PURCH POWER EXPENSE TRANSMISSION EXPEHSE ADMIN & GENERAL EXPENSE OTHER EXPENSES OPERATING REVENUE FINANCIAL RATIOS: TINES INTEREST EARNED RATIO (TIER) DEBT SERVICE COVERAGE (DSC) BURNS & MCDONWELL ENGINEERING COrPANY POWER SUPPLY PROGRAM ASSOCIATIONS DEVELOP COAL~FIRED GENERATION 1986 7737. 7631. 2220. 2290. 2483. 133. 370. 440. 172. 241. ae 30098. 0. 640. 66727. 0. 66727. 35.72 96825. 2397. 315. 0. 94113. 30.38 0.76 27701. 23797. 30098. 26.36 3.43 4.08 66.12 145.11 TABLE 14 PROJECTED OPERATING RESULTS 1984 1985 5863. 6921. 6146. 6517. 1252. 2029. 1067. 2060. 1849. 2222. 133. 133. 385. 377. 720. 742. 178. 175. 46. 198. 8333. 11574. 4. 4. 24441. 30199. 0. 0. 580. 609. 50996. 63760. 0. 0. 509796. 63760. 29.29 35.42 73437. 93959. 1829. 3644, 315. 315. 0. 0. 73293. 90000. 42.10 50.00 47.18 18.77 22612. 26556. 1829. 3644, 24441. 30199. 26.00 24.26 2.09 3.23 3.72 3.80 68.19 68.72 147.93 147.36 2.00 2.00 2.08 2.16 1987 8421. 9012. 2308. 2540. 2682. 133. 367. 465. 170. 252. 12580. 27984. 0. 324. 67441. 67441. 34.84 95424. 4596. 315. 90513. 46.75 -7.20 23387. 43576. 27984. 29.27 3.77 4.35 62.61 141.49 2.00 2.18 0. 123677. 61.72 32.00 24991. 5093. 30083. 45.79 3.64 3.27 47.30 130. 39 PAGE: 180 DATE: 99-Mar-83 TIME: 14:54 FILES: CHM.D1 COAL. D2 VERSION: FIN. FORE. 1989 1990 1991 9789. 10630. 11576. 9644. 11364. 62604, 28477. 28710. 29003. 3909. 4241. 4599. 3129. 3378. 3649. 133. 133. 133. 349. 341. 335. 522. 553. 588. 164. 161. 158. 356. 370. 385. ie 7 -— 29476. 29298. 25908. 0. 0. 0. 325. 367. 613. — — a 101745. 105368. 155602. 30.79 49.82 69.68 131421. 134666. 181510. 2681. 4340. 4255. 315. 315. 315. 0. 0. 0. 128426. 127811. 1769740. 63.99 61.38 79.24 3.68 -4.08 29.10 26796. 24758. 21653. 2681. 4540. 4255. 29476. 29298. 259708. 47.00 48.12 66.31 3.83 4.02 2.96 3.42 3.56 2.59 43.75 44.30 28.14 128.91 127.81 116.465 2.00 2.00 2.00 2.24 2.23 2.26 oa CHUGACH, PROJECT: BRADLEY LAKE, HOMER & MATANUSKA ELEC. 82-113-4--000 EXISTING ORGANIZATIONAL STRUCTURE PLAN: COAL(8%, 20YR) CONTRACT YEAR 1 SONRUSDUN at 43 44 45 EXPENSES: $1,000 PRODUCTION O&M-EXCL FUEL PRODUCT ION-FUEL. PURCHASED POWER TRANSMISSION O&M ADMIN & GENERAL-EXCL INSURANCE LONG-TERM LEASES HOMER XMSN LEASE PriT SUSITNA BARGE EXP MATAN XfSN LEASE PrT INSURANCE DEPRECIATION TAXES INTEREST GN LONG-TERM DEBT LESS: INTEREST CHARGED TO CONSTR OTHER DEDUCTIONS TOTAL. POWER COST-ACCRUAL LESS PQWER SOLD NET POWER COST-ACCRUAL. POWER COST-ACCRUAL (MILLS/KWH) REVENUES: $1,000 REVEHUES REGD TO MAINTAIN TIER LESS: NON-OPERATING INCOME LESS: OTHER OPERATING REVENUES LESS: PATRONAGE CAPITAL RETIREMENT REVEHUES FROM RATEPAYERS WHOLESALE REVENUES, MILLS/KWH ANNUAL IHCREASE % MARGINS: $1,000 OPERATING MARGINS NON-QPERATING INCOME NET PATRONACE CAPITAL OR MARGINS OPERATING RATIOS: % OF POWER COST PROD & PURCI] POWER EXPENSE TRANSMISSION EXPENSE ADHIN & GENERAL EXPENSE OTHER EXPENSES OPERATING REVENUE FINANCIAL RATIOS TIMES INTEREST EARNED RATIO (TIER) DEBT SERVICE COVERAGE (DSC) BURNS & MCDGNHELL ENGINEERING COMPAHY POWER SUPPLY PROGRAN ASSCCIATIONS DEVELOP COAI- FIRED GENERATION 1992 12569. 75447. 29501. 4985. 3940. 133. 329. 625. 155. 401. 16509. 166359. 71.95 187456. 3095. 315. 0. 184046. 79.60 0.46 18002. 3095. 21097. 70.64 3.00 2.61 23.75 112.68 1995 16203. 217101. 31910. 6342. 4964. 133. 278. 755. 145. 459. 18131. 834. 317393. 317593. 123.39 337928. 6674, 315. 0. 330939. 128.57 41.05 13661. 6674. 20335. 83.51 2.00 1.71 12.79 106. 40 2.00 TABLE 14 PROJECTED OPERATING RESULTS 1993 1994 13708. 14875. 935670. 115312. 30105. 30677. 3404. 5855. 4255. 4396. 133. 133. 320. 313. 665. 708. 151. 148. 419. 438. 17009. 17548. 4. 4. 20864. 20612. 0. 0. 715. 772. menace aalvaes 189422, 211992. 78.99 85.24 210286. 232605. 4398. 5595. 315. 315. 0. 0. 205573. 226674, 85.73 91.15 7.69 6.33 164466. 15017. 4398. 5595. 20864. 20612. 73.64 75.88 2.85 2.76 2.47 2.37 21.04 18.98 111.01 109.72 2.00 2.00 2.29 2.30 2.2? 1996 17657. 332995. 33640. 6868. 5361. 133. 269. 805. 142. 482. 18761. 900. 440362. 440562. 165.19 463107. 7724. 315. 0. 455067. 170.63 32.71 14820. 7724. 22545. 87.23 1.546 1.33 9.89 105.12 2.00 2.26 1997 19128. 535647. 35700. 7454. 5790. 133. 262. 859. 137. 507. 19442. 972. 650965. 650965. 235.52 673895. 10683. 315. 0. 664897. 240.56 40.98 14247. 10683. 24930. 90.71 1.15 0.97 7.18 103.83 PAGE: 181 DATE: 9-Mar-83 TIME: 14:54 FILES: CHN.D1 COAL.D2 VERSION: FIN. FORE. 1998 1999 2000 20864. 22616. 244606. 615126. 676881. 757600. 39833. 49106. 75941. 8108. 8834. 9643. 6254. 6754. 7294. 133. 133. 133. 254. 237. 228. 918. 981. 925. 131. 127. 122. 533. 562. 573. 20177. 20971. 21827. 4. 4. 4. 27504. 30290. 29869. 0. 0. 0. 1050. 1134. 1225. TmET enone RR) 740870. 818630. 9730009. 258.51 275.82 302.34 768374. 848920. 957877. 13880. 17348. 20962. 315. 315. 315. 0. 0. 0. 754199. 831256. 938600. 263.15 280.07 305.14 9.39 6.43 8.95 13624. 12942. 8907. 13880. 17348. 209762. 27504. 30290. 29869. 91.22 91.45 92.27 1.09 1.08 1.04 0.92 0.89 0.85 6.77 6.58 5.84 103.71 103.70 103.21 2.00 2.00 2.00 2.24 2.24 2.24 BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, DEVELOP COAL~ FIRED GENERATION EXISTING ORGANIZATIONAL STRUCTURE PLAN: COAL (BZ, 20YR) CONTRACT YEAR 1 NMONBUSWN 37 38 39 40 41 42 43 44 45 EXPENSES: $1, 000 PRODUCTION O&M-EXCL FUEL PRODUCTION-FUEL. PURCHASED POWER TRANSHILSSION Oar ADMIN & GENERAL-EXCL INSURANCE LONG-TERM LEASES HOMER XMSN LEASE PMT SUSITHA BARGE EXP MATAN XMSN LEASE PriT INSURANCE DEPRECIATION TAXES INTEREST ON LONG-TERM DEBT LESS: INTEREST CHARGED TO CONSTR OTHER DEDUCTIONS TOTAL POWER COST~ACCRUAL LESS POWER SOLD NET POWER COST-ACCRUAL POWER COST-ACCRUAL (MILLS/KWH) REVENUES: $1,000 REVENUES REGD TO liAINTAIN TIER LESS: NON-OPERATING INCOME LESS: OTHER OPERATING REVENUES LESS: PATROWAGE CAPITAL RETIREMENT REVEHUES FROM RATEPAYERS WHOLESALE REVENUES, MILLS/KWH ANNUAL INCREASE % MARGINS: $1,000 GPERATING MARGINS NOH-GPERATING INCORE NET PATRONAGE CAPITAL OR MARGINS OPERATING RATIOS: % OF POWER COST PROD & PURCH POWER EXPENSE TRANSMISSION EXPENSE GDIIN & GENERAL EXPENSE OTHER EXPENSES OPERATING REVENUE FINANCIAL RATIOS: TIMES INTEREST EARNED RATIO (TIER) DEBT SERVICE COVERAGE (DSC) 2001 48472. 716823. 41685. 10515. 13999. 133. 219. 999. 118. 3160. 34372. 1015933. 1015933, 318. 67 1140243. 27158. 315. 0. 1112770. 349.05 14.39 97152. 27158. 124311. 79. AL 1.04 1.69 17.86 112.24 2004 61798. 1015685. 100626. 13576. 17635. 133. 195. 1258. 100. 3277. 7 117604. 0. 1666. — 1391372. 392.05 1508975. 42246. 315. 24441. 1441973. 406. 30 5.41 73357. 42246. 117604, 84.69 0.98 1.50 12.83 108. 45 2.00 TABLE 14 PROJECTED OPERATING RESULTS 2002 2003 52632. 54976. 820624. 705189. 45953. 67527. 11458. 12475. 15119. 16329. 133. 133. aii. 202. 1079. 1165. 113. 107. 3196. 3235. _—_ a 119065. 117937. 0. 0. 1428. 1543. 1 — er 1126385. 1239272. 340.81 361.73 1243451. 1357209. 26123. 33193. 315. 315. 0. 3195. 1219012. 1320505. 368.84 385.44 5.67 4.50 92942. 84744. 26123. 33193. 119065. = 117937. 81.61 83.09 1.02 1.01 1.63 1.58 15.75 14.33 110.57 109.52 2.00 2.00 2.37 2.42 2.42 2005 2006 67146. 72692. 1184273. 1278120. 94578. 205950. 14763. 16046. 19044. 20570. 133. 133. 115. 109. 1359. 1468. 94. 88. 3322. 3371. 38873. 60232. 4. 4. 117214. =116761. 0. 0. 1799. 1943. 1562720. 1777486. 1562720. 1777486. 425.11 © 466.29 1679934. 1894247. 506462. 38369. 315. 315. 30199. 30098. 1598758. 1805465. 434.92 473.63 7.04 8.90 66553. 38392. 50662. 38369.. 117214. = 116761. 86.13 87.58 0.94 0.90 1.43 1.35 11.49 10.17 107.50 106.57 PAGE: 182 DATE: 9-Mar-83 TIME: 14:54 FILES: CHM.01 COAL. D2 VERSION: FIN. FORE. 2007 2008 78888. 159782. 1494085. 1267028. 159118. 67646. 17431. 18926. 22215. 44976. 133. 133. 102. 93. 1585. 1712. 83. 76. 3424. 12165. 61699. 170824. 4. 4. 116242. 383963. 0. 0. 2099. 2267. 1957, = — 1957108. 2127595. 495.60 320.56 2073350. 2513558. 65819. 87966. 315. 315. 27984. 30083. 1979233. 2395193. 301.20 385. 48 5.82 16.82 30424. 295997. 65819. 87966. 116242. 383963. 88.50 70.18 0.89 0.89 1.31 2.68 9.30 26.25 105.94 118.03 2.00 2.00 2.43 2.38 2009 173130. 1448966. 83644. 20542. 48574. 133. 85. 1849. 67. 12227. 172536. BURNS & MCDGNNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOPER & MATANUSKA ELEC. ASSCCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, DEVELOP COAL-FIRED GENERATION EXISTING ORGANIZATIONAL STRUCTURE PLAN: COAL.(8%, 20YR) CONTRACT YEAR 1 EXPENSES: $1,000 PRODUCTION O&M-EXCL FUEL PRODUCT ION-FUEL. PURCHASED PQUER TRANSMISSION O&M" ADMIN & GENERAL~EXCL INSURANCE LONG-TERM LEASES HOMER XMSN LEASE PHT SUSITHA BARGE EXP 10 =MATAN XrSN LEASE PMT 11 INSURANCE 12 DEPRECIATION WONAU SW 13. TAXES 14 INTEREST ON LONG-TERM DEBT 15 LESS: INTEREST CHARGED TO CONSTR 16 OTHER DEDUCTIONS 17 TOTAL POWER COST~ACCRUAL 18 LESS POWER SOLD 19 4ET POWER COST-ACCRUAL 20 POWER COST-ACCRUAL (MILLS/KWH) 22 REVENUES: $1,000 23 REVENUES REQD TO MAINTAIN TIER 24 LESS: WNON-OPERATING INCOME 23 LESS: OTHER OPERATING REVENUES 26 LESS: PATRONAGE CAPITAL RETIREMENT 27 REVENUES FROM RATEPAYERS 28 WHOLESALE REVENUES, MILLS/KWH 29 ANHUAL INCREASE % 31 MARGINS: $1,000 32 OPERATING MARGINS 33 HON-OPERATING INCOME 34 HET PATRONAGE CAPITAL OR MARGINS % OF POWER COST 35 36 OPERATING RATIOS 37 = PROD & PURCH POWER EXPENSE 38 TRANSMISSION EXPEHS 39 = ADNIN & GENERAL EXPENSE 40 = OTHER EXPENSES ri OPERATING REVERUE 43 FIWAHCTAL RATIOS: 44 TIMES INTEREST EARHED RATIO (TIER) 45 DEBT SERVICE COVERAGE (DSC) TABLE 14 PROJECTED OPERATING RESULTS 2010 2011 2012 2013 2014 187712. 202864. 219842. 343249. 372534. 1677509. 1808634. 2059971. 1986157. 2280143. 117165. 207192. 299372. 95136. 118950. 22287. 24171. 26206. += 28404. +~—=«-30778. 52440. 56657. 61189. 96916. 104669. 133. 133. 133. 133. 133. 79. 58. 52. 44. 4a. 1997. 2157. 2329. 2516. 2717. 59. 46. 13. 12. 10. 12294. 12366. 12444. 25287. 25978. 174383. 176223. 178381. 993678. 936193. 381249. a79654. 977876. 476688. 674480. 2644. 2856. 3084. 3331. 3597. 2629975. 2873016. 3240876. 95971578. 9749630. 2629975. 2873016. 3240876. 3591578. 39497630. 598.40 631.29 686.78 734.47 779.48 3011224, 3252670. 3618772. 4268266. 4624110. 77839. 113395. 148482. 201918. 83136. 315. 315. 315. 315. 315. 29298. 25908. 21097. 20864. 20612. 2903772. 3113051. 3448678. 4045169. 4520047. 660.70 684.04 730.81 827.23 892.04 5.47 3.53 6.84 = 13.19 7.84 303410. 266259. 229194. 474770. + 591344. 77839. 113395. 148682. 201918. 93136. 381249. 379654. 377876. 676668. 674480. 75.38 77.23 79.58 67.51 70.17 0.85 0.84 0.81 0.79 0.78 2.44 2.40 2.27 3.40 3.29 21.31 19.53 17.34 28.30 25.75 114.50 113.21 11164 118.84 = 117.08 2.00 2.00 2.00 2.00 2.00 2.37 2.37 2.36 2.42 2.42 2015 PRESENT 404180. 2585701. 208829. 33342. 113043. 133. 0. 29734. 10. 25476. 338909. 4387828. 835.94 35059210. 152553. 315. 20335. 4886007. 930.85 4.35 518829. 152553. 671382. 72.90 0.76 3.16 23.18 115.30 2.00 2.38 VALUE (1983$) 4190378. PAGE: 183 DATE: 9-Mar-83 TINE: 14:54 FILES: CHM.D1 COAL.D2 VERSION: FIN. FORE. 3 paint £ ery | Ge = on aoe r 1 f ~ wo; Hydroelectric Expansion Scenario Existing Arrangement 20-Year Capital Credit Rotation BURNS & MCDGNHELI. ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSGCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE & SUSITNA PROJECTS EXISTING ORGANIZATIONAL STRUCTURE PLAN: HYDRO (8%, 20YR) CONTRACT YEAR 1 EXPENSES: $1, 000 PRODUCTION O&M-EXCL FUEL PRODUCTION-FUEL PURCHASED POWER TRANSIIISSION O08" ADMIN & GENERAL-EXCL INSURANCE LONG-TERM LEASES HOMER XrSN LEASE PHT SUSITNA BARGE EXP 10 MATAN XISN LEASE PMT 11 INSURANCE 12 DEPRECIATION 13. TAXES 14 INTEREST ON LONG-TERM DEBT 15 LESS: INTEREST CHARGED TO CONSTR 16 OTHER DEDUCTIONS 17 TOTAL PGWER COST-ACCRUAL 18 LESS POWER SOLD 19 =NET POWER COST-ACCRUAL 20 POWER COST-ACCRUAL (MILLS/KWH) 22 REVENUES: $1,000 23° REVENUES REGD TO MAINTAIN TIER 24 LESS: WNON-OPERATING INCOME 23° LESS: OTHER OPERATING REVENUES CON RU SW 26 LESS: PATRONAGE CAPITAL RETIREMENT 27 REVENUES FROM RATEPAYERS 28° WHOLESALE REVENUES, MILLS/KWH 2? ANNUAL INCREASE % 31 MARGINS: $1,000 32 OPERATING MARGINS 33 = WNON-OPERATING INCOME = NET PATRONAGE CAPITAL OR MARGINS 34 OPERATING RATIOS: % OF POWER COST 37 = PROD & PURCH POWER EXPENSE 38 = TRANSPIISSION EXPENSE 39 =ADHIN & GENERAL EXPENSE 40 OTHER EXPENSES eS OPERATING REVENUE 43 FINANCIAL RATIOS: 44 TIVES INTEREST EARNED RATIO (TIER) 45 DEBT SERVICE COVERAGE (DSC) 1983 5303. 5126. 1291. 881. 1674. 133. 336. 700. 149. al. 7775. 4. 21302. 0. 741. 45437. 0. 43437. 27.08 48633. 320. 315. 0 47998. 28. 60 0.00 2876. 320. 3195. 25.79 1.94 3.73 68.53 107.03 1.15 1.33 ot 6a fees 1986 7739. 7631. 2220. 2290. 2483. 133. 370. 440. 172. 241. 12265. 4. 30098. 0. 640. 66727. 0. 66727. 35.72 96825. 2397. 315. 0. 74113. 30.38 0.76 27701. 2397. 30098. 26.36 3.43 4.08 66.12 145.11 2.00 TABLE 14 PROJECTED OPERATING RESULTS 1984 1985 5863. 6921. 6146. 6517. 1252. 2029. 1047. 2060. 1849. 2222. 133. 133. 385. 377. 720. 742. 178. 175. 46. 198. 8333. 11574, 4. 4. 24441. 30199. 0. 0. 580. 609. 50996. 63760. 0. 0. 50976. 63760. 29.29 35.42 73437. 93959. 1829. 3644. 315. 315. 0. 0. 73293. 970000. 42.10 50.00 47.18 18.77 22612. 26556. 1827. 3644, 24441. 30199. 26.00 24.26 2.09 3.23 3.72 3.80 68.19 68.72 147.93 147.38 2.00 2.00 2.08 2.16 2.17 erg 1987 8421. 9012. 2308. 2540. 2682. 133. 367. 465. 170. 252. 12580. 4. 27984. 0. 524. 67441. 0. 67441. 34.84 95424. 4596. 315. 0. 90513. 46.75 -7.20 23387. A596. 27984. 29.27 3.77 4.35 62.61 141.49 2.00 2.18 samy meow 1988 8993. 8195. 28144. 3602. 2897. 133. 359. 492. 167. 343. 15101. 127085. 3093. 315. 0. 123677. 61.72 32.00 24991. 3093, 30083. 45.79 3.64 3.27 47.30 130.39 2.00 2.23 1989 9789. 9644. 28477. 3709. 3129. 133. 349. 322. 164. 356. ae 29476. 0. 325. —_— 101945, 50.79 131421. 2681. 315. 0. 128426. 63.99 3.68 26796. 2681. 29476. 47.00 3.83 3.42 45.75 128.91 2.00 2.24 . es & PAGE: 173 DATE: 9-Mar-83 TIME: 14:52 FILES: CHN.D1 HYDRO. D2 VERSION: FIN. FORE. 1990 1991 10430. 11576. 11364. 62604. 28710. 29003. 4241. 4599. 3378. 3649. 133. 133. 341. 335. 553. 588. 161. 158. 370. 385. 15618. 16047. 4. 4. 29298. 25908. 0. 0. 567. 613. — 1s 105368. 155602. 49.82 69. 68 134666. 181510. 4540. 4255. 315. 315. 0. 0. 127811. 176940. 61.38 79.24 4.08 29.10 24758. 21653. 4540. 4255. 29298. 25908. 48.12 66.31 4.02 2.96 3.56 2.59 44.30 28.14 127.81 116.465 2.00 2.00 2.23 2.26 oat BURNS & TICDONNELL ENGINEERING COMPANY PAGE: 174 POWER SUPPLY PROGRAM DATE: 9-fMar-83 CHUGACH, HOPER & MATANUSKA ELEC. ASSCCIATIONS TIME: 14:52 PROJECT: 82-113-4-000 FILES: CHM.D1 BRADLEY LAKE & SUSITNA PROJECTS HYDRO. D2 EXISTING ORGANIZATIONAL STRUCTURE - PLAN: HYDRO (8%, 20YR) VERSION: FIN. FORE. TABLE 14 PROJECTED OPERATING RESULTS CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 1 EXPENSES: $1,000 2 PRODUCTION O&M-EXCL FUEL 12549. 12442. 12738. 13917. 15197. 14561. 18123. 19649. 21522. 3 PRODUCTIGN-FUEL 75447. 32102. 17063. 43964. 79125. 158614. 198699. 221031. 273175. 4 PURCHASED POWER 29501. 294629. 428587. 430205. 431750. 433461. 435465. 437405. 439540. 3 TRANSMISSION O&M 4985. 3404. 5855. 6342. 6868. 7434. 8108. 8834. 9643. 6 ADMIN & GENERAL-EXCL INSURANCE 3940. 4255. 4596. 4964, 5361. 5790. 6254. 6754. 7294. 7 LONG-TERM LEASES 133. 133. 133. 133. 133. 133. 133. 133. 133. 8 HOMER XPMSN LEASE PriT 329. 320. 313. 278. 269. 262. 254. 237. 228. 9 SUSITNA BARGE EXP 625. 645. 708. 735. 805. 859. 718. 981. 925. 10 MATAN XMSN LEASE PMT 155. 151. 148. 145. 142. 137. 131. 127. 122. 11 INSURANCE 401. 419. 438. 459. 482. 507. 533. 562. 393. 12. DEPRECIATION 16509. 17009. 17548. 18131. 18761. 19442. 20177. 20971. 21827. 13. TAXES 4. 4. 4. 4. 4. 4. 4. 4. 4. 14 INTEREST ON LONG-TERM DEBT 21097. 20864. 20612. 20335. 22545. 24930. 27504. 30290. 29869. 15. LESS: INTEREST CHARGED TO CONSTR 0. 0. o. 0. 0. 0. 0. 0. 0. 16 OTHER DEDUCTIONS 662. 715. 772. 834. 900. 972. 1050. 1134. 1225. 17 TUTAL POWER COST-ACCRUAL 166357. 387113. 509516. 540466. 582342. 6697125. 717353. 748112. 9806099. 18 LESS POUER SOILD 0. 0. 0. 0. 0. 0. 0. 0. 0. 19 ~=NET POWER COST-ACCRUAL 166359. 387113. 509516. 540466. 582342. 667125. 717353. 748112. 806099. - POWER COST-ACCRUAL (MILLS/KWH) 71.95 162.27 204.87 209.97 218.35 242.09 250.30 252.06 262.08 22 REVENUES: $1,000 23° REVENUES REQD TO MAINTAIN TIER 187456. 409977. 530128. 560801. 604887. 6974055. 744858. 778401. 835748. 24 LESS: NON-OPERATING INCOFE 3095. 4398. 5395. 6674. 7724. 10683. 13880. 17348. 20962. 25 LESS: OTHER OPERATING REVENUES 315. 315. 315. 315. 315. 315. 315. 315. 315. 26 LESS: PATRONAGE CAPITAL RETIRENENT 0. 0. 0. 0. 0. 0. 0. 0. 0. 27 REVENUES FROM RATEPAYERS 184046. 405264. 524218. 559811. 596847. 683057. 730662. 760738. 9814471. 28 WHOLESALE REVENUES, MILLS/KWH 79.60 169.00 210.78 215.16 223.79 247.13 254.94 256.31 264. 85 = ANNUAL INCREASE % 0.46 112.30 24.72 2.07 4.01 10. 43 3.16 0.54 3.33 31 MARGINS: $1,060 32 OPERATING MARGINS 18002. 16466. 15017. 13661. 14820. 14247. 13624. 12942. 8907. 33 NON-OPERATING INCOME 3095. 4378. 55975. 6674. 7724. 10683. 13880. 17348. 20962. = HET PATRONAGE CAPITAL OR MARGINS 21097. 20854. 20612, 20335. 22545. 24930. 27504. 30290. 29869. 36 OPERATING RATIOS: % OF POWER COST 37 = PRUD & PURCH POWER EXPENSE 70.64 87.17 89.97 90.31 90.34 90.96 90.93 90.64 91.09 38 TRANSMISSION EXPENSE 3.00 1.39 1.15 1.17 1.18 1.11 1.13 1.18 1.20 39 «ADMIN & CEHERAL EXPENSE 2.61 1.20 0.99 1.00 1.00 0.94 0.95 0.98 0.98 40 OTHER EXPENSES 23.75 10.24 7.90 7.51 7.48 6.99 6.99 7.20 6.74 - OPERATING REVENUE 112. 48 105.34 104.05 103.76 103.87 103.73 103.83 104.05 103.71 43 FINANCIAL RATIGS: 44 TIMES INTEREST EARNED RATIO (TIER) 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 45 DEBT SERVICE COVERAGE (DSC) 2.29 2.29 2.30 2.27 2.26 2.24 2.24 2.24 2.24 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 175 : POWER SUPPLY PROGRAM DATE: 9-Mar-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 14:52 PROJECT: 82-113-4-000 FILES: CHN.D1 BRADLEY LAKE & SUSITHA PROJECTS HYDRO. D2 EXISTING ORGANIZATIONAL STRUCTURE PLAN: HYDRO (8%, 20YR) VERSION: FIN. FORE. TABLE 14 PROJECTED OPERATING RESULTS CONTRACT YEAR 2001 2002 2003 2004 2005 2006 2007 2008 2009 1 EXPENSES: $1,000 2 PRODUCTION O&M-EXCL FUEL 23559. 22535. 24476. 26664. 29507. 32802. 35855. 38539. 42593. 3. PRODUCTION-FUEL 331478. 39912. 47009. 80078. 173787. 307022. 3859708. 375202. 539377. 4 PURCHASED POWER 442024. 724472. 728987. 733193. 737539. 742189. 747452. 752886. 758724. 3 TRANSMISSION O03n" 10515. 11458. 12475. 13607. 14828. 16184. 17648. 19228. 20983. & ADMIN & GENERAL-EXCL INSURANCE 7877. 8507. 9188. 9923. 10717. 11575. 12500. 13500. 14580. 7 LONG-TERM LEASES 133. 133. 133. 133. 133. 133. 133. 133. 133. 8 HOMER XMSM LEASE Prt 219. 211. 202. 195. 115. 109. 102. 93. 85. 9 SUSITNA BARGE EXP 999. 1079. 1165. 1258. 1359. 1448. 1585. 1712. 1849. 10 MATAN XMSN LEASE PriT 118. 113. 107. 100. 94, 88. 83. 76. 67. 11 INSURANCE 626. 662. 702. 744, 789. 838. 871. 949. 1011. 12 DEPRECIATION 22752. 23750. 24830. 25995. 27255. 28614. 30081. 31668. 33380. 13. TAXES 4. 4. 4. 4. 4. 4. 4. 4. 4. 14 INTEREST ON LONG-TERM DEBT 29410. 28914. 32688. 32071. 36411. 35627. 347530. 40129. 39069. 15. LESS: INTEREST CHARGED TO CONSTR 0. . 0. 0. 0. 0. 0. 0. 0. 0. 16 OTHER DEDUCTIONS 1323. 1428. 1543. 1646. 1799. 1943. 2099. 2267. 2448. 17 TOTAL POWER COST-ACCRUAL 871057. 863179. 9703509. 925631. 1034338. 1178576. 1269092. 1276387. 1454303. 18 LESS POWER SOLD 0. 0. 0. 0. 0. 0. 0. 0. 0. 19 =NET POWER COST-ACCRUAL 871057. 843179. 903507. 925631. 1034338. 1178596. 1269092. 1276387. 1454303. - POWER COST-ACCRUAL (HILLS/KWH) 273.23 261.17 263.72 260.81 281.33 309.18 321.37 312.00 342.75 22 REVENUES: $1,000 , 23° REVENUES REQD TO MAINTAIN TIER 900467. 8972093. 936197. 957702. 1070749. 1214223. 1303843. 1316516. 1493373. 24 LESS: HON-OPERATING INCOrE 22097. 23061. 23996. 27744. 26593. 28548. 26586. 24701. 27190. 25° LESS: OTHER OPERATING REVENUES 315. 315. 315. 315. 315. 315. 315. 315. 315. 26 LESS: PATRONAGE CAPITAL RETIREMENT 0. 0. 3195. 24441. 30199. 30098. 27984. 30083. 29476. 27 REVENUES FROM RATEPAYERS 878054. 868716. 708690. 905201. 1013641. 1155242. 1248957. 1261417. 1436392. 28 WHOLESALE REVENUES, MILLS/KWH 275.42 262.85 265.23 255.06 275.75 303.05 316.27 308.34 338.53 s ANNUAL INCREASE % 3.99 4.57 0.91 -3.84 8.11 9.90 4.36 ~2.51 9.79 31 MARGINS: $1,000 32 OPERATING MARGINS 7313. 3853. 8692. 4327. 9818. 7059. 8164. 15429. 11880. 33 =NON-OPERATING INCOME 22097. 23061. 23996. 27744. 26593. 28548. 26586. 24701. 27190. a NET PATRONAGE CAPITAL OR MARGINS 29410. 28914. 32688. 32071. 36411. 354627. 34750. 40129. 39069. 36 OPERATING RATIOS: X OF POWER COST 37 = PROD & PURCH POWER EXPENSE 91.51 91.17 90.81 90.74 90.96 91.81 92.13 91.40 92.19 38 TRANSMISSION EXPENSE 1.21 1.33 1.38 1.47 1.43 1.37 1.39 1.51 1.44 39 ADMIN & GENERAL EXPENSE 0.98 1.06 1.09 1.15 1.11 1.05 1.06 1.13 1.07 40 OTHER EXPENSES 6.31 6.45 6.72 6.64 6.49 5.77 3.42 3.96 3.30 s OPERATING REVENUE 103. 38 103.35 103.42 103. 46 103.52 103.02 102.74 103.14 102.69 43 FINANCIAL RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 45 DEBT SERVICE COVERAGE (DSC) 2.26 2.29 2.25 2.24 2.22 2.22 2.22 2.19 2.23 BURNS & MCDONNELL ENGINEERING COMPANY . PAGE: 176 POWER SUPPLY PROGRAN DATE: 9-Mar~-83 CHUGACH, HOFER & MATANUSKA ELEC. ASSOCIATIONS TIME: 14:52 PROJECT: 82-113-4-000 FILES: CHNM.D1 BRADLEY LAKE & SUSITNA PROJECTS HYDRO. D2 EXISTING ORGANIZATIONAL STRUCTURE PLAN: HYDRO (8%, 20YR) VERSION: FIN. FORE. TABLE 14 PROJECTED OPERATING RESULTS CONTRACT YEAR 2010 2011 2012 2013 2014 2015 ne 1 EXPENSES: $1,000 (1983$) 2 PRODUCTION O&M-EXCL FUEL 46534. 50968. 56585. 61252. 67292. 74667. 3 = PRODUCTION-FUEL 622725. 765482. 1029395. 1118677. 1413644. 1827319. 4 PURCHASED POWER 765347. 772157. 779551. 787835. 796442. 805729. 5 TRANSMISSION O&M 22877. 24977. 27244. 297355. 32467. 35471. 6 ADMIN & GENERAL~EXCL INSURANCE 15747. 17006. 18367. 19836. 21423. 23137. 7 LONG-TERM LEASES 133. 133. 133. 133. 133. 133. 8 HOMER XMSN LEASE PMT 79. 38. 32. 44. 44. 0. 9 SUSITNA BARGE EXP 1997. 2157. 2329. 2516. 2717. 2934, 10 MATAN XMSN LEASE PriT 59. 46. 13. 12. 10. 10. 11 INSURANCE 1078. 1150. 1229. 1313. 1404. 1502. 12. DEPRECIATION 35230. 37070. 39229. 36514. 39032. 41748. 13 TAXES 4. 4. 4. 4. 4. 4. 14 INTEREST ON LONG-TERM DEBT 45337. 44063. 51313. 49791. 58179. 36288. 15. LESS: INTEREST CHARGED TO CONSTR 0. 0. 0. 0. 0. 0. 16 OTHER DEDUCTIONS 2644, 2856. 3084. 3331. 3597. 3883. 17 TOTAL. POWER COST-ACCRUAL 1559791. 1718127. 2008528. 2111013. 2436389. 2874828. 18 LESS POWER SOLD 0. 0. 0. 0. 0. 0. 19 = NET POWER COST-ACCRUAL 1559791. 1718127. 2008528. 2111013. 2436389. 2874828. i POWER COST-ACCRUAL (HILLS/KWH) 354. 90 377.53 425.63 431.70 480.83 347.69 22 REVENUES: $1,000 23> REVENUES REQD TO MAINTAIN TIER 1605129. 1762190. 2059841. 2160804. 2494568. 29731116. 24 LESS: NON-OPERATING INCOME 25053. 28192. 26144. 30441. 28153. 33012. 25 LESS: OTHER OPERATING REVENUES 315. 315. 315. 315. 315. 315. 26 LESS: PATRONAGE CAPITAL RETIREMENT 29298. 25908. 21097. 20864. 20612. 20335. 27 REVENUES FROM RATEPAYERS 1550463. 1707774. 2012285. 2107183. 2445498. 2877455. 3419605. 28 WHOLESALE REVENUES, MILLS/KWH 352.78 375.25 426. 42 431.33 482.63 348.19 - ANNUAL INCREASE % 4.21 6.37 13.64 1.15 11.89 13.58 31 MARGINS: $1,000 32 OPERATING MARGINS 20284. 15870. 25169. 19350. 30026. 23277. 33 NON-OPERATING IHCOME 25053. 28192. 26144, 30441. 28153. 33012. = NET PATRONAGE CAPITAL OR MARGINS 45337. 44063. 51313. 49791. 58179. 56288. 36 OPERATING RATIOS: % OF POWER COST 37 = =PROD & PURCH POWER EXPENSE 91.97 92.46 92.88 93.21 93.47 94.26 38 = TRANSMISSION EXPENSE 1.47 1.45 1.36 1.41 1.33 1.23 39 ADMIN & GENERAL EXPENSE 1.08 1.06 0.98 1.00 0.94 0.86 40 OTHER EXPENSES 5.48 5.03 4.79 4.37 4.26 3.65 a OPERATING REVENUE 102.91 102.56 102.55 102. 36 102.39 101.96 43 FINANCIAL RATIOS: 44 TIMES INTEREST EARMED RATIO (TIER) 2.00 2.00 2.00 2.00 2.00 2.00 45 DEBT SERVICE COVERAGE (DSC) 2.20 2.21 2.20 2.13 2.11 2.10 f b t i Ree ach vue feces beeen! ea oe ee et wrtomee — — nce ps —< wey Gas-Fired Expansion Scenario G&T Cooperative 20-Year Capital Credit Rotation CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: f2e113"4"000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM PLAN: GAS TABLE 14 PROJECTED OPERATING RESULTS CONTRACT YEAR 1983 1984 1985 1986 1 EXPENSES: $1,000 2 PRODUCTION O&M-EXCL FUEL 5303. 3863. 6921. 7739. 3° PRODUCTION-FUEL 5126. 6146. 6517. 7631. 4 PURCHASED POWER 1291. 1252. 2029. 2220. 3 TRANSHISSION O&n 881. 1047. 2060. 2321. & ADMIN & GENERAL-EXCL INSURANCE 1676. 1849. 2222. 2483. 7 LONG-TERM LEASES 133. 133. 133. 133. 8 ADDITIONAL G&T STAFF 0. 340. 770. 1097. 9 SUSITNA BARGE EXP 700. 720. 742. 440. 10 G & T ORGANIZATION 200. 200. 150. 0. 11 INSURANCE 2i. 46. 198. 241. 12 DEPRECIATION 7935. 8494. 11736. 12427. 13. TAXES 4. 4. 4. 4. 14 INTEREST ON LONG-TERM DEBT 21537. 24670. 36414. 36306. 15 LESS: INTEREST CHARGED TO CONSTR 0. 0. 0. 0. 16 OTHER DEDUCTIONS 741. 580. 609. 640. 17 TOTAL POWER COST-ACCRUAL 45547. — 70504. 73684, 18 LESS POWER SOLD 0. 0. 0. 19 NET POWER COST-ACCRUAL 45547. 51563, 70504. 73684. 2 POWER COST-ACCRUAL (MILLS/KWH) 27.14 29.62 39.17 39.45 22 REVENUES: $1,000 23 REVENUES REQD TO MAINTAIN TIER 48778. 56497. 77787. 80945. 24 LESS: NON-OPERATING INCOME 320. 1049. 1165. 2442. 25 LESS: OTHER OPERATING REVENUES ~ 315. 315. “ 26 LESS: PATRONAGE CAPITAL RETIREMENT 0. 0. 27 REVENUES FROM RATEPAYERS 4g142. 55133. 76307. 7a1e7, 28 WHOLESALE REVENUES, MILLS/KWH 28.49 31.67 42.39 41.86 . ANNUAL INCREASE % 0.00 10.38 33.87 -1.27 31 MARGINS: $1,000 32 OPERATING MARGINS 29710. 3885. 6118. 4819. 33 NON-OPERATING INCOME 320. 1049. 1165. 2442, 2 NET PATRONAGE CAPITAL OR MARGINS 3231. 4934. 7283. 7261. 36 OPERATING RATIOS: % OF POWER COST 37 PROD & PURCH POWER EXPENSE 25.73 25.72 21.94 23.87 38 TRANSMISSION EXPENSE 1.93 2.07 2.92 3.15 39 «ADMIN & GENERAL EXPENSE 3.73 3.48 3.43 3.70 40 OTHER EXPENSES 68.61 68.54 71.71 69.28 2 OPERATING REVENUE 107.09 109.57 110.33 109.85 43 FINANCIAL RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 1.15 1.20 1.20 1.20 48 = NERT SFRUTCE CNUFRALF (DSC) 1.29 1.97 1. a 1.41 1988 8993. 8195. 28146. 3702. 2897. 133. 2227. 492. 0. 344. _ 40614. 0. 486. 111497. 0. 111497. 55.64 119620. 3385. 315. 0. 115920. 57.84 38.39 4738. 3383. 8123. 40.446 3.32 2.91 53.11 107.29 1.20 1.43 1989 9789. 9644. 28477. 4065. 3129. 133. 3174. 322. 0. 357. 15430. 4. 40430. 0. 525. eg 115880; 57.74 1239466. 930. 315. 0. 122720. 61.15 5.71 7156. 930. 8084. 41.34 3.51 3.01 52.14 106.98 PAGE: 188 DATE: 9-Mar-83 TINE: 07:28 FILES: CHMGT.D1 GASET.D2 VERSION: FIN. FORE. 1990 1991 10630. 11576. 11364. 62604. 28710. 29003. 4457. 4881. 3378. 3649. 133. 133. 3428. 3702. 553. 588. 0. 0. 371. 384. 15781. 16209. 4. 4. 40218. 39970. 0. 0. 567. 613. rr iow 119593. = 173318. 56.55 77.62 127637. 181312. 1407. 1790. 315. 315. 0. 0. 125914. 179207. 59.53 80.25 -2.64 34.80 6636. 6204. 1407. 1790. 8044. 7994. 42. 40 59.53 3.73 2.82 3.13 2.33 50.74 35.32 106.73 104. 61 1.20 1.20 1.43 1.43 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 189 POWER SUPPLY PROGRAM DATE: 9-Nar-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TINE: 07:28 PROJECT: 82-113-4-000 FILES: CHNGT.01 BRADLEY LAKE, GAS-FIRED GENERATION GASGT..D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS VERSION: FIN. FORE. TABLE 14 PROJECTED OPERATING RESULTS CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 1 EXPENSES: $1,000 2 > ~=PRODUCTION O&M-EXCL FUEL 12569. 13708. 14875. 16203. 17657. 19128. 20864, 22616. 24606. 3° PRODUCTION-FUEL 73447. 95670. 115312. 217101. 332995. 535647. 615126. 676881. 757600. 4 PURCHASED POWER 29501. 30105. 30677. 31910. 33640. 35700. 39833. 49106. 75941. 3 TRANSMISSION O&n 3338. 5832. 6366. 6941. 7580. 8289. 9054. 9880. 10794. & ADMIN & GENERAL-EXCL INSURANCE 39740. 4253. 4596. 4964. 5361. 5790. 6254. 6754. 7294. 7 LONG-TERM LEASES 133. 133. 133. 133. 133. 133. 133. 133. 133. 8 ADDITIONAL G&T STAFF 3998. 4318. 4664. 5037. 5440. 5875. 6345. 6852. 7401. 9 SUSITNA BARGE EXP 625. 665. 708. 755. 805. 859. 918. 981. 925. 10 G & T ORGANIZATION 0. 0. 0. 0. 0. 0. 0. 0. 0. 11 INSURANCE 402. 420. 439. 460. 483. 507. 533. 562. 593. 12 DEPRECIATION 16672. 17171. 17711. 18294. 18924. 19604. 20338. 21132. 21988. 13. TAXES 4. 4. 4. 4. 4. 4. 4. 4. 4. 14 INTEREST ON LONG-TERM DEBT 39662. 39277. 38857. 40721. 42707. 42121. 41477. 43952. 43184. 15 LESS: INTEREST CHARGED TO CONSTR 0. 0. 0. 0. 0. 0. 0. 0. 0. 16 OTHER DEDUCTIONS 662. 715. 772. 834. 900. 972. 1050. 1134. 1225. 17 TOTAL POWER COST-ACCRUAL 188953. 212274. 235115. 343357. 466630. 674628. 761930. 839987. 951690. 18 LESS POWER SOLD 0. 0. 0. 0. 0. 0. 0. 0. 0. 19 MET POWER COST-ACCRUAL 188953. 212274. 235115. 343357. 4664630. 674628. 761930. 839987. 951690. a POWER COST-ACCRUAL (MILLS/KWH) 81.73 88.52 94.54 133.39 174.96 244.08 265.85 283.01 309.39 22 REVENUES: $1,000 23 REVENUES REQD TO MAINTAIN TIER 196885. 220129. 242886. 351501. 475171. 683053. 770225. 848777. 960327. 24 LESS: NON-OPERATING INCOME 2055. 2199. 2240. 2176. 3712. 5269. 4855. 4332. 5984. 25 LESS: OTHER OPERATING REVENUES 315. 315. 315. 315. 315. 315. 315. 315. 315. 26 LESS: PATRONAGE CAPITAL RETIREMENT 0. 0. 0. 0. 0. 0. 0. 0. 0. 27 REVENUES FROM RATEPAYERS 194515. 217615. 9.240331. 347010. 471144. 677469. 765055. 844131. 954027. 28 WHOLESALE REVENUES, MILLS/KWH 84.13 90.75 96.63 135.59 176.66 245.10 266.94 284. 41 310.15 - ANNUAL INCREASE % 4.83 7.86 6.49 40.31 30.29 38.75 8.91 6.54 9.05 31 MARGINS: $1,000 32 OPERATING MARGINS 5878. 5657. 3531. 3968. 4829. 3155. 3440. 4459. 2653. 33 NON-OPERATING INCOME 2055. 2199. 2240. 2176. 3712. 3269. 4855. 4332. 5984. 3 NET PATRONAGE CAPITAL OR MARGINS 7932. 7855. 7771. 8144. 8541. 8424. 8295. 8790. 8637. 36 OPERATING RATIOS: % OF POWER COST 37 PROD & PURCH POWER EXPENSE 62.19 65.71 68. 42 77.24 82.35 87.53 88.70 89.12 90.17 38 TRANSMISSION EXPENSE 2.82 2.75 2.71 2.02 1.62 1.23 1.19 1.18 1.13 39 ADMIN & GENERAL EXPENSE 2.30 2.20 2.14 1.58 1.25 0.93 0.89 0.87 0.83 40 OTHER EXPENSES 32.68 29.34 26.73 19.16 14.77 10.31 9.22 8.83 7.87 a OPERATING REVENUE 104. 20 103.70 103.31 102.37 101.83 101.25 101.09 101.05 100.91 43 FINANCIAL RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 48 = NERT SFRUTCF CNUFRALE (NSe) 1a 1.41 1a 1.49 1.498 1.48 1.49 1.39 1.49 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 190 POWER SUPPLY PROGRAM DATE: 9-Mar-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 07:28 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT. D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS VERSION: FIN. FORE. TABLE 14 PROJECTED OPERATING RESULTS CONTRACT YEAR 2001 2002 2003 2004 2005 2006 2007 2008 2009 1 EXPENSES: 1,000 2 PRODUCTION O&M-EXCL FUEL 34895. 37967. 41147. 44707. 43694. 52778. 57381. 90121. 97878. 3 PRODUCTION-FUEL 799893. 908485. 1000185. 1117271. 1292021. 1396249. 1617422. 1648459. 1854777. 4 PURCHASED POWER 40518. 44322. 64475. 95350. 89409. 194421. 149991. 59160. 72069. 5 TRANSHISSION O&h 11784. 12879. 14041. 15339. 16718. 18208. 19814. 21553. 23430. 6 ADMIN & GENERAL-EXCL INSURANCE 10354. 11183. 12078. 13044. 14088. 15215. 16432. 26238. 28337. 7 LONG-TERM LEASES 133. 133. 133. 133. 133. 133. 133. 133. 133. 8 ADDITIONAL G&T STAFF 7993. 8432. 9323. 10068. 10874. 11744. 12683. 13698. 14794, 9 SUSITNA BARGE EXP 999. 1079. 1165. 1258. 1359. 1448. 1585. 1712. a 10 G & T ORGANIZATION 0. 0. 0. 0. 0. 0. 0. 0. 11 INSURANCE 1880. 1914. 1955. 1997. 2042, 2091. 2144, 6499. 4561: 12 DEPRECIATION 37974. 38973. 40052. 41217. 42475. 43834. 45301. 98507. 100218. 13 TAXES 4. 4. 4. 4. 4. 4. 4. 4. 4. 14 INTEREST ON LONG-TERM DEBT 101207. 100273. 99229. 98063. 96770. 95331. 93722. 280881. 278507. 15 LESS: INTEREST CHARGED TO CONSTR 0. 0. 0. 0. 0. 0. 0. 0. 0. 16 OTHER DEDUCTIONS 1323. 1428. 1543. 1646. 1799. 1943. 2099. 2267. 2448. 17 TOTAL POWER COST-ACCRUAL aes 1167275. — aes 1616385. 1833418. 2018713. 2249233. 2483006. 18 LESS POWER SOLD 0. 0. 0. 0. 0. 0. 19 NET POWER COST-ACCRUAL 1048958 1167275. 1285350, 1440117; 1616385. 1833418. 2018713. 2249233. 2483006. 2 POWER COST-ACCRUAL (MILLS/KWH) 329.03 353. 18 375.18 405.78 439.71 480.96 511.20 549.80 585.20 22 REVENUES: $1,000 23 REVENUES REGD TO MAINTAIN TIER 1069199. 1187329. 1305196. 1459730. 1635739. 1852485. 2037458. 2305409. 2538707. 24 LESS: NON-OPERATING INCOME 6225. 10046. 10958. 11365. 11376. 10915. 10142. 12465. 17792. 25 LESS: OTHER OPERATING REVENUES = 315. 315. 315. 315. 315. 315. 315. 315. 26 LESS: PATRONAGE CAPITAL RETIREMENT 0. 3231. 4934. 7283. 7261. 7236. 8123. 8084. 27 REVENUES FROM RATEPAYERS 1062459, 1176968. 1290692. 1443116. 1616765. 1833993. 2019765. 2284506. 2512514. 28 WHOLESALE REVENUES, MILLS/KWH 333.33 356.12 376.73 406.63 439.82 481.11 311.46 558. 42 592.15 = ANNUAL INCREASE X 7.47 6.84 5.79 7.93 8.16 9.39 6.31 9.18 6.04 31 MARGINS: $1,000 32 OPERATING MARGINS 14017. 10009. 8888. 8248. 7978. 8151. 8403. 43711. 37909. 33 NON-OPERATING INCOME 6225. 10046. 10958. 11365. 11376. 10915. 10142, 12465. 17792. 4 NET PATRONAGE CAPITAL OR MARGINS 20241. 20055. 19846. 19613. 19354, 19066. 18744, 56176. 55701. 33 OPERATING RATIOS: % OF POWER COST PROD & PURCH POWER EXPENSE 83. 45 84.88 846.03 87.31 88. 43 89.64 90.39 79.93 81.462 32 TRANSMISSION EXPENSE 1.12 1.10 1.09 1.07 1.03 0.99 0.98 0.96 0.94 39 «= ADMIN & GENERAL EXPENSE 1.17 1.12 1.09 1.04 1.00 0.94 0.92 1.46 1.41 40 OTHER EXPENSES 14.26 12.90 11.78 10.58 9.49 8.42 7.70 17.66 16.03 41 OPERATING REVENUE 101.93 101.72 101.54 101.36 101.20 101.04 100.93 102.50 102.24 42 43 FINANCIAL RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 45 NERT SFRUTCE CNUFRALF (NSh) 1.49 1.49 1 1 1.43 1.49 1.49 1.44 1.44 BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN CHUGACH, HOFER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION Sous AND TRANSMISSION COOP. CONTRACT YEAR 1 ee RPSSBNSERBRESSSNSGSSNES.oNouswN 32 SBSSASSELLKLG EXPENSES: $1,000 PRODUCTION O&M-EXCL FUEL PRODUCT ION-FUEL PURCHASED POWER TRANSMISSION O&M ADMIN & GENERAL-EXCL INSURANCE LONG-TERM LEASES ADDITIONAL G&T STAFF SUSITNA BARGE EXP G & T ORGANIZATION INSURANCE DEPRECIATION TAXES ined ON LONG-TERM DEBT OTHER DEDUCTIONS TOTAL POWER COST-ACCRUAL LESS POWER SOLD NET POWER COST-ACCRUAL POWER COST-ACCRUAL (MILLS/KWH) REVENUES: $1,000 REVENUES REQD TO MAINTAIN TIER LESS: NON-OPERATING INCOME ine OTHER OPERATING REVENUES gs: REVENUES FROM RATEPAYERS WHOLESALE REVENUES, MILLS/KWH ANNUAL INCREASE % MARGINS: $1,000 OPERATING MARGINS NON-OPERATING INCOME NET PATRONAGE CAPITAL OR MARGINS OPERATING RATIOS: % OF POWER COST PROD & PURCH POWER EXPENSE TRANSMISSION EXPENSE ADMIN & GENERAL EXPENSE OTHER EXPENSES OPERATING REVENUE FINANCIAL RATIOS: TIMES INTEREST EARNED RATIO (TIER) DFRT SFRUTCF CNUFRACF (NSC) INTEREST CHARGED TO CONSTR PATRONAGE CAPITAL RETIREMENT TABLE 14 PROJECTED OPERATING RESULTS 2010 2011 2012 2013 2014 106422. 115104. 125071. 175334. 190605. 2110536. 2274932. 2561894. 2798271. 3148837. 99312. 175434. 254049. 76045. 93440. 25456. 27445. 30009. 325461. 35918. 30605. 33053. 35697. 51031. 55113. 133. 133. 133. 133. 133. 15977. 17256. 18636. 20127. ~—«-21737. 1997. 2157. 2329. 2516. 2717. 0. 0. 0. 0. 0. 6628. 6700: 6778. (13176. 13267. 102067; 103707. 106063. 179194. 181711. 275914. 273028. 269853. 344193. 340550. 2644. 2856. 3084. 3331. 3597. 2777694. 3034410. 3413600. 9895921. 4287030. 2777694, 3034410. 3413400. 3895921, 4287030. 632.01 666.76 | 723.37 796.71 844.07 2832877. 3089016. 3467571. 4004760. 4395140. 22717. 27170. 31142. 39684. 52872. 315. “315. 315. 315. 315. 8044. 7994. 7932. 7855. 7771. 2801802. 3053537, 3428182. 3956905. 4334181. 637.50 670.96 726.46 809.18 855.37 7.66 5.25 8.27 11.39 5:71 32466. 27435. 228297. 69155. 55238. 29717. 27170. 31142. 39484. 52872. 55183. 54406. 53971. 108839. 108110. 83.39 84.62 86.16 78.28 80.08 0.92 0.91 0.88 0.84 0.82 1:34 1.31 1.24 1.45 1:40 14.35 13.16 11.72 19.24 17.51 101.99 10180 © 101.58 += 102.79 102.52 1.20 1.20 1.20 1.20 1.20 1.44 1-493 1_49 1.44 1.45 2015 PRESENT 207179. 3523752. 163910. 38297. 59522. 133. 23476. 2934. 0. 13365. 104428. 536476. 3885. 4757360. 4757360. 906.34 4864655. 65291. 315. 8144. 4790905. 912.73 6.71 42004. 65291. 107295. 81.87 0.60 1.53 15.79 102.24 1.20 1.42 VALUE (1983$) 4116803. PAGE: 191 DATE: 9-Mar-83 TINE: 07:28 FILES: CHMGT.D1 GASGT.D2 VERSION: FIN. FORE. a oe = Coal-Fired Expansion Scenario | G&T Cooperative 20-Year Capital Credit Rotation BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, DEVELOP COAL-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: COAL TABLE 14 PROJECTED OPERATING RESULTS CONTRACT YEAR 1983 1984 1985 1986 1 EXPENSES: $1,000 2 PRODUCTION O&M-EXCL FUEL 5303. 5863. 6921. 7739. 3 PRODUCTION-FUEL 3126. 6146. $517. 7631. 4 PURCHASED POWER 1291. 1252. 2029. 2220. 5 TRANSMISSION O&M 881. 1047. 2060. 2321. & ADMIN & GENERAL-EXCL INSURANCE 1676. 1849. 2222. 2483. 7 LONG-TERM LEASES 133. 133. 133. 133. 8 ADDITIONAL G&T STAFF 0. 340. 770. 1097. 9 SUSITNA BARGE EXP 700. 720. 742. 440. 10 G & T ORGANIZATION 200. 200. 150. 0. 11 INSURANCE 21. 4%. 198. 241. B § ren = — 1i7e4 _— 14 INTEREST ON LONG-TERM DEBT am. 24670. 36ai 4. 36306. 15 LESS: INTEREST CHARGED TO CONSTR 0. 0. 0. 16 OTHER DEDUCTIONS rai 580. 609. 640. 17 TOTAL POWER COST-ACCRUAL 45547. 51563. 70504. 73684. 18 LESS POWER SOLD 0. 0. 0. 0. 19 NET POWER COST-ACCRUAL 45547. 31563. 70504. 73684. 20 POWER COST-ACCRUAL (MILLS/KWH) 27.14 29.62 39.17 39.45 22 REVENUES: $1,000 23 REVENUES REQD TO MAINTAIN TIER 48778. 36497. 77787. 80945. 24 LESS: NON-OPERATING INCOME 320. 1049. 1165. 2442. 25 LESS: OTHER OPERATING REVENUES 315. 315. 315. 315. 26 LESS: PATRONAGE CAPITAL RETIREMENT 0. 0. 0. 0. 27 REVENUES FROM RATEPAYERS 48142. 55133. 76307. 78187. 28 WHOLESALE REVENUES, MILLS/KWH 28.69 31.67 42.39 41.86 a ANNUAL INCREASE % 0.00 10.38 33.87 -1.27 31 MARGINS: $1,000 32 OPERATING MARGINS 29710. 3883. 6118. 4819. 33 NON-QPERATING INCOME 320. 1049. 1165. 2442. a NET PATRONAGE CAPITAL OR MARGINS 3231. 4934. 7283. 7261. 36 OPERATING RATIOS: % OF POWER COST 37 PROD & PURCH POWER EXPENSE 25.73 25.72 21.94 23.87 38 TRANSMISSION EXPENSE 1.93 2.07 2.92 3.15 39 «ADMIN & GENERAL EXPENSE 3.73 3.48 3.43 3.70 40 OTHER EXPENSES 68.61 68.54 71.71 69.28 = OPERATING REVENUE 107.09 109.57 110.33 109.85 43 FINANCIAL RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 1.15 1.20 1.20 1.20 48 NERT SEWUTTF PNUFRALF (NSe) 1.49 1.97 1.40 1.41 1987 8421. 9012. 2308. 2604. 2682. 133. 1563. 465. 0. 252. 12742. 36180. 524. 76889. 76889. 39.72 84125. 2887. 315. 80923. 41.80 -0.14 4349. 2887. 7236. 25.67 3.39 3.82 67.12 109. 41 119620. 3385. 315. 0. 115920. 37.84 38.39 4738. 3385. 6123. 40.66 3.32 2.91 53.11 107.29 1.20 1.43 1989 9789. 9644. 28477. 4065. 3129. 133. 3174. 322. 0. 357. 15430. 40430. 0. 525. a 115000; 57.74 123966. 930. 315. 0. 122720. 61.15 5.71 7156. 930. 8086. 41.34 3.51 3.01 32.14 106.98 PAGE: 188 DATE: 9-Mar-83 TINE: 07:28 FILES: CHMGT.D1 COALGT.02 VERSION: FIN. FORE. 1990 1991 10430. 11574. 11364. 62604. 28710. 29003. 4457. 4881. 3378. 3649. 133. 133. 3428. 3702. 553. 58a. 0. 0. 371. 384. — — 40218. 39970. 0. 0. 567. 613. 119593. =_ 0. 119593. 173318, 56.55 77.62 127637. 181312. 1407. 1790. 315. 315. 0. 0. 125914. 179207. 59.53 80.25 -2.64 34.80 6636. 6204. 1407. 1790. 8044. 7994. 42. 40 59.53 3.73 2.82 3.13 2.33 50.74 35.32 104.73 104.41 1.20 1.20 1.42 1.48 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 189 POWER SUPPLY PROGRAN DATE: 9-Mar-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TINE: 07:28 PROJECT: €2-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, DEVELOP COAL-FIRED GENERATION COALGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: COAL ° VERSION: FIN. FORE. TABLE 14 PROJECTED OPERATING RESULTS CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 1 EXPENSES: $1,000 2 > ~=PROOUCTION O&N-EXCL FUEL 12569. 13708. 14875. 16203. 17657. 19128. 20864. 22616. 24606. 3 = PRODUCTION-FUEL 73447. 95670. 115312. 217101. 332995. 5354647. 615126. 676881. 757600. 4 PURCHASED POWER 29501. 30105. 30677. 31910. 33640. 35700. 39833. 49106. 75941. 5 TRANSMISSION O&n 3338. 5832. 6366. 6941. 7580. 8289. 9054. 9880. 10796. & ADMIN & GENERAL-EXCL INSURANCE 3940. 4255. 4596. 4964. 5361. 5790. 6254. 6754. 7294. 7 LONG-TERM LEASES 133. 133. 133. 133. 133. 133. 133. 133. 133. 8 ADDITIONAL G&T STAFF 3998. 4318. 9664. 5037. 3440. 5875. 6345. 6852. 7401. 9 SUSITNA BARGE EXP 625. 645. 708. 755. 805. 859. 918. 981. 925. 10 G & T ORGANIZATION 0. 0. 0. 0. 0. 0. 0. 0. 0. 11 INSURANCE 402. 420. 439. 460. 483. 507. 333. 562. 593. 12. DEPRECIATION ; 16672. 17171. 17711. 18294. 18924. 19604. 20338. 21132. 21988. 13. TAXES 4. 4. 4. 4. 4. 4. 4. 4. 4. 14 INTEREST ON LONG-TERM DEBT 39662. 39277. 38857. 40721. 42707. 42121. 41477. 43952. 43184. 15 LESS: INTEREST CHARGED TO CONSTR 0. 0. 0. 0. 0. 0. 0. 0. 0. 16 OTHER DEDUCTIONS 662. 715. 772. 834. 900. 972. 1050. 1134, 1225. 17 TOTAL POWER COST-ACCRUAL 188953. 212274. 235115. 343357. 466630. 6744628. 761930. 9839987. 951490. 18 LESS POWER SOLD 0. 0. 0. 0. 0. 0. 0. 0. 0. 19 NET POWER COST-ACCRUAL 188953. 212274. 235115. 343357. 466630. 674628. 761930. 839987. 951690. s POWER COST-ACCRUAL (MILLS/KWH) 81.73 88.52 94.54 133.39 174.96 244.08 265.85 283.01 309.39 22 REVENUES: $1,000 23° =REVENUES RE@D TO MAINTAIN TIER 196885. 220129. 242886. 351501. 475171. 683053. 770225. 848777. 9460327. 24 LESS: NON-OPERATING INCOME 2055. 2199. 2240. 2176. 3712. 5269. 4855. 4332. 5984. 25 LESS: OTHER OPERATING REVENUES 315. 315. 315. 315. 315. 315. 315. 315. 315. 26 LESS: PATRONAGE CAPITAL RETIREMENT 0. 0. 0. 0. 0. 0. 0. 0. 0. 27 REVENUES FROM RATEPAYERS 194515. 217615. 240331. 349010. 471144. 677469. 765055. 844131. 954027. 28 WHOLESALE REVENUES, MILLS/KWH 84.13 90.75 96.63 135.59 176.66 245.10 266.94 284. 41 310.15 2 ANNUAL INCREASE % 4.83 7.86 6.49 40.31 30.29 38.75 8.91 6.54 9.05 31 MARGINS: $1,000 32 OPERATING MARGINS 5878. 3657. 5531. 3968. 4829. 3155. 3440. 4459. 2653. 33 NON-OPERATING INCOME 2055. 2199. 2240. 2176. 3712. 5269. 4855. 4332. 5984. 3 NET PATRONAGE CAPITAL OR MARGINS 7932. 7853. 7771. 8144. 8541. 8424. 8295. 8790. 8637. 36 OPERATING RATIOS: % OF POWER COST 37 =PROD & PURCH POWER EXPENSE 62.19 65.71 68. 42 77.24 82.35 87.53 88.70 89.12 90.17 38 TRANSMISSION EXPENSE 2.82 2.75 2.71 2.02 1.62 1.23 1.19 1.18 1.13 39 ADMIN & GENERAL EXPENSE 2.30 2.20 2.14 1.58 1.25 0.93 0.89 0.87 0.83 40 OTHER EXPENSES 32. 68 29.34 26.73 19.16 14.77 10.31 9.22 8.83 7.87 2 OPERATING REVENUE 104. 20 103.70 103.31 102.37 101.83 101.25 101.09 101.05 100.91 43 FINANCIAL RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 48 NERT SERUTCE CNUFRACF Cnsry 1.a1 1.41 1.41 1.49 1.38 1.48 1.49 1.39 1.39 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 190 POWER SUPPLY PROGRAM DATE: 9-Mar-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 07:28 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, DEVELOP COAL-FIRED GENERATION COALGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: COAL VERSION: FIN. FORE. TABLE 14 PROJECTED OPERATING RESULTS CONTRACT YEAR 2001 2002 2003 2004 2005 2006 2007 2008 2009 1 EXPENSES: $1,000 2 PRODUCTION O8M-EXCL FUEL 48472. 52632. 56976. 61798. 67146. 72692. 78888. 159782. 173130. 3° PRODUCTION-FUEL 716623. 620624. 905189. 1015685. 1184273. 1278120. 1494085. 1247028. 1448964. 4 PURCHASED POWER 41685. 45953. 67527. 100826. 94578. 205950. 159118. 67646. 83644. 3 TRANSMISSION On 11784. 12852. 14005. 15252. 16597. 18050. 19619. 21313. 23144. & ADMIN & GENERAL-EXCL INSURANCE 13999. 15119. 16329. 17635. 19046. 20570. 22215. 44976. 48574. 7 LONG-TERM LEASES 133. 133. 133. 133. 133. 133. 133. 133. 133. 8 ADDITIONAL G&T STAFF 7993. 8432. 9323. 10068. 10874. 11744. 12683. 13698. 14794. 9 SUSITNA BARGE EXP 999. 1079. 1165. _ 1359. 1448. 1585. 1712. 1849. 10 G & T ORGANIZATION 0. 0. 0. 0. 0. 0. 0. 0. 11 INSURANCE 3160. 3196. 3235. 3277 3322. 3371. 3424, 12164. 12226. 8 — — — meee 7 or — — —s ainige 2 14 INTEREST ON LONG-TERM DEBT 153812. 152878. 151834. 150668. 149073 147937. 146327. 493366. 490637. 15 LESS: INTEREST CHARGED TO CONSTR 0. 0. 0. 0. 0. 0. 0. 0. 16 OTHER DEDUCTIONS 1323. 1428. 1543. 16664. 1799. 1943. 2099. 2267. 2448. 17 TOTAL POWER COST-ACCRUAL 1054520. 1170061. 1283874. 14360464. re. 1822374. 2002040. 2255074. oo 18 LESS POWER SOLD 0. 0. 0. 0. 0. 0. 0. 19 NET POWER COST-ACCRUAL 1054520. 1170061. 1283874. 1436046. 1407540, 1822374. 2002040. 2255074. 2472246, ” POWER COST-ACCRUAL (MILLS/KWH) 330.78 354.03 374.74 404. 63 437.31 478.06 506.97 351.23 382.66 22 REVENUES: $1,000 23 REVENUES REQD TO MAINTAIN TIER 1085282. 1200637. 1314241. 1466179. 1637415. 18519461. 2031306. 2353747. 2570373. 24 LESS: NON-OPERATING INCOME 7308. 10603. 13681. 16254. 18432. 20138. 21530. 29412. 19674. 25 LESS: OTHER OPERATING REVENUES 315. 315. 315. 315. 315. 315. 315. 315. 315. 26 LESS: PATRONAGE CAPITAL RETIREMENT 0. 0. 3231. 4934. 7283. 7261. 7236. 8123. 8084. 27 REVENUES FROM RATEPAYERS 1077659. 1189719. 1297014. 1444675. 1611385. 1824247. 2002224. 2315897. 2542298. 28 WHOLESALE REVENUES, MILLS/KWH 338.04 359.98 378.58 407.07 438.35 478.55 307.02 566.10 599.17 a ANNUAL INCREASE % 8.99 6.49 5.17 7.52 7.69 9.17 5.95 11.465 5.84 31 MARGINS: $1,000 32 OPERATING MARGINS 23454. 19973. 16686. 13879. 11443. 9450. 7735. 69261. 78454. 33 NON-OPERATING INCOME 7308. 10603. 13681. 16254. 18432. 20138. 21530. 29412. 19674. 34 NET PATRONAGE CAPITAL OR MARGINS 30762. 30576. 30367. 30134. 29875. 29587. 29265. 98673. 98127. 36 OPERATING RATIOS: % OF POWER COST 37 PROD & PURCH POWER EXPENSE 76.51 78.56 80.20 82.05 83.73 85. 42 86.52 66.27 69.00 38 TRANSMISSION EXPENSE 1.12 1.10 1.09 1.06 1.03 0.99 0.98 0.95 0.94 39 ADMIN & GENERAL EXPENSE 1.43 1.57 1.52 1.46 1.39 1.31 1.28 2.53 2.46 40 OTHER EXPENSES 20.75 18.78 17.18 15.43 13.85 12.27 11.22 30.25 27.41 a OPERATING REVENUE 102.92 102.61 102.37 102.10 101.84 101.62 101.446 104.38 103.97 43 FINANCIAL RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 45 DFRT SFRUTLF CNUFRALF (DSM) 1. 4A 1.44 1.44 1.45 1.44 1.45 1.45 1.47 1.47 BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, DEVELOP COAL-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: COAL CONTRACT YEAR 1 EXPENSES: $1,000 PRODUCTION O&N-EXCL FUEL PRODUCT ION-FUEL. PURCHASED POWER TRANSMISSION O&M ADMIN & GENERAL-EXCL INSURANCE LONG-TERM LEASES ADDITIONAL G&T STAFF SUSITMA BARGE EXP 10 G & T ORGANIZATION 11 INSURANCE 12 DEPRECIATION 13. TAXES 14 INTEREST ON LONG-TERM DEBT 15 LESS: INTEREST CHARGED TO CONSTR 16 OTHER DEDUCTIONS 17 TOTAL POWER COST-ACCRUAL 18 LESS POWER SOLD 19 NET POWER COST-ACCRUAL 20 POWER COST-ACCRUAL (MILLS/KWH) 22 REVENUES: $1,000 23 REVENUES RE@D TO MAINTAIN TIER LESS: NON-OPERATING INCOME LESS: OTHER OPERATING REVENUES LESS: PATRONAGE CAPITAL RETIREMENT REVENUES FROM RATEPAYERS WHOLESALE REVENUES, MILLS/KWH ANNUAL INCREASE % MARGINS: $1,000 OPERATING MARGINS 33 NON-OPERATING INCONE NET PATRONAGE CAPITAL OR MARGINS OPERATING RATIOS: % OF POWER COST PROD & PURCH POWER EXPENSE TRANSMISSION EXPENSE ADMIN & GENERAL EXPENSE QTHER EXPENSES OPERATING REVENUE FINANCIAL RATIOS: TIMES INTEREST EARNED RATIO (TIER) DFRT RERUTCE CNUFRARF (DSM) CWONOULWH FESPASSBLKGREHLSVSVEGE 2010 187712. 1677509. 117165. 25120. 52460. 133. 15977. 1997. 0. 12293. ed — 2644, uae 2755209. 626.90 2852739. 33495. 315. 8044. 2810885. 639.56 6.74 64034. 33495. 97530. 71.95 0.91 2.35 24.79 103.54 1.20 1.47 erent 2013 343249. 1986159. 95136. 32051. 96914. 133. 20127. 2516. 0. 25287. er 977537. 0. 3331. ihcomts 39716305. 800.88 4111813. 81967. 315. 7855. 4021675. 822.43 14.35 113540. 81967. 195507. 61.91 0.82 3.12 34.15 104.99 1.20 1.49 TABLE 14 PROUECTED OPERATING RESULTS 2011 2012 202864. 219842. 1808634. 2059971. 207192. | 299372. 27255. 29561. 56657. 61189. 133. 133. 17256. 18636. 2157. 2329. 0. 0. 12365. 12443. 176386. 178342. 404322. 480657. 2856. 3084. 2798081. 3365763. 2998081. 3365763. 658.77 713.24 3094946. 3461895. 46806. 59591. 315. 315. 7994. 7932. 3039830. 3394056. 647.95 719223 4.44 7.88 50058. 36540. 46806. 59591. 96864. 96131. 74.09 76.63 "0.91 0.88 2.30 2.19 22.79 20.30 103.23 102.86 1.20 1.20 1_47 1.47 2014 372534. 2280143. 118950. 34740. 104469. 133. 21737. 2717. 0. 25378. oT 973283. 3597. 4274239. 4274239. 843.54 4468896. 70006. 315. 7771. 4370803. 866.55 5.36 124651. 70006. 194657. 64.84 0.81 3.04 31.30 104.55 2015 PRESENT 404180. 2585701. 208829. 37645. 113043. 133. 23476. 2934. 0. 25476. a 968149. 0. 3885. 47 sale 4712525. 897.79 4906155. 100834. 315. 8144, 4796862. 913.86 5.46 92796. 100834. 193630. 67.88 0.80 2.94 28.39 104.11 VALUE (1983$) 4126655. PACE: 191 DATE: 9-Mar-83 TIME: 07:28 FILES: CHNGT.D1 COALGT. D2 VERSION: FIN. FORE. ose een t 4 Hydroelectric Expansion Scenario G&T Cooperative 20-Year Capital Credit Rotation eae Sl ee ee | BURNS & HCDONNELL ENGINEERING COMPANY PAGE: 189 POWER SUPPLY PROGRAM DATE: 99-Mar-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 07:27 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE & SUSITNA PROJECTS HYDRGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: HYDRO (8%,20YR) TALE 14 VERSION: FIN. FORE. PROJECTED OPERATING RESULTS CONTRACT YEAR 1983 1984 1985 1986 1987 1988 1989 1990 1991 1 EXPENSES: $1,000 2 PRODUCTION O&M-EXCL FUEL 3303. 5863. 6921. 7739. 8421. 8993. 9789. 10630. 11576. 3 = PRODUCTION-FUEL 3126. 6146. 6517. 7631. 9012. 8195. 9644. 11364. 62604. 4 PURCHASED POWER 1291. 1252. 2029. 2220. 2308. 28144. 28477. 28710. 29003. 5 TRANSMISSION O8n 881. 1067. 2060. 2321. 2604. 3702. 4065. 4457. 4881. & ADMIN & GENERAL-EXCL INSURANCE 1676. 1849. 2222. 2483. 2682. 2897. 3129. 3378. 3649. 7 LONG-TERM LEASES 133. 133. 133. 133. 133. 133. 133. 133. 133. 8 ADDITIONAL G&T STAFF 0. 540. 770. 1097. 1563. 2227. 3174. 3428. 3702. 9 SUSITNA BARGE EXP 700. 720. 742. 44. 465. 492. 522. 353. 588. 10 G & T ORGANIZATION 200. 200. 150. 0. 0. 0. 0. 0. 0. 11 INSURANCE 2i. 46. 198. 241. 252. 344. 357. 371. 3864. 12 DEPRECIATION 7935. 8494, 11736. 12427. 12742. 15263. 154630. 15781. 16209. 13. TAXES 4. 4. 4. 4. 4. 4. 4. 4. 4. 14 INTEREST ON LONG-TERM DEBT 21537. 24670. 36414. 36306. 36180. 40614. 4. 40218. 39970. 15 LESS: INTEREST CHARGED TO CONSTR 0. 0. 0. 0. 0. 0. 0. 0. 0. 16 OTHER DEDUCTIONS 741. 580. 609. 640. 324. 486. 525. 367. 613. 17 TOTAL POWER COST-ACCRUAL 45547. 51563. 70504. 73684. 76889. 111497. 115880. 119593. 173318. 18 LESS POWER SOLD 0. 0. 0. 0. 0. 0. 0. 0. 0. 19 NET POWER COST-ACCRUAL 45347. 51563. 70504. 73684. 76889. 111497. 115880. 119593. 173318. =” POWER COST-ACCRUAL (HILLS/KWH) 27.14 29.62 39.17 39.45 39.72 55.64 57.74 56.55 77.62 22 REVENUES: $1,000 23 REVENUES REQD TO HAINTAIN TIER 48778. 56497. 77787. 80945. 84125. 119620. 123966. 127637. 181312. 24 LESS: NON-OPERATING INCOME 320. 1049. 1165. 2442. 2887. 3385. 930. 1407. 1790. 25 LESS: OTHER OPERATING REVENUES 315. 315. 315. 315. 315. 315. 315. 315. 315. 26 LESS: PATRONAGE CAPITAL RETIREMENT 0. 0. 0. 0. 0. 0. 0. 0. 0. 27 REVENUES FROM RATEPAYERS 48142. 53133. 76307. 78187. 80923. 115920. 122720. 125914. 179207. 28 WHOLESALE REVENUES, MILLS/KWH 28.69 31.67 42.39 41.86 41.80 57.84 61.15 59.53 80.25 = ANNUAL INCREASE % 0.00 10.38 33.87 -1.27 0.14 38.39 5.71 -2.64 34.80 31 MARGINS: $1,000 32 OPERATING MARGINS 29710. 3885. 6118. 4819. 4349. 4738. 7156. 6636. 6204. 33 NON-OPERATING INCOME 320. 1049. 1145. 2442. 2887. 3385. 930. 1407. 1790. “ NET PATRONAGE CAPITAL OR MARGINS 3231. 4934. 7283. 7261. 7236. 8123. 8086. 8044. 7994. 36 OPERATING RATIOS: % OF POWER COST 37 ~=PROD & PURCH POWER EXPENSE 25.73 25.72 21.94 23.87 25.67 40.64 41.34 42.40 59.53 38 TRANSMISSION EXPENSE 1.93 2.07 2.92 3.15 3.39 3.32 3.51 3.73 2.82 39 ADMIN & GENERAL EXPENSE 3.73 3.68 3.43 3.70 3.82 2.91 3.01 3.13 2.33 40 OTHER EXPENSES 68.61 68.54 71.71 69.28 67.12 53.11 32.14 50.74 35.32 a OPERATING REVENUE 107.09 109.57 110.33 109.85 109.41 107.29 106.98 104.73 104.41 43 FINANCIAL RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 1.15 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 48 NERT SFPUTCE CNUFRACE (ner) 1.99 1.97 1.40 1.41 1.4 1.43 1.43 1.43 1.43 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 190 POWER SUPPLY PROGRAN DATE: 99-Mar-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TINE: 07:27 PROJECT: 62-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE & SUSITNA PROJECTS HYDRGT.02 GENERATION AND TRANSMISSION COOP. PLAN: HYDRO (8%,20YR) VERSION: FIN. FORE. TABLE 14 PROJECTED OPERATING RESULTS CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 1 EXPENSES: $1,000 2 = PROOUCTION O&8M-EXCL FUEL 12569. 12442. 12738. 13917. 15197. 16561. 18123. 19649, 21522. 3 = PRODUCTION-FUEL 73447. 32102. 17063. 43964. 79125. 158614. 198699. 221031. 273175. 4 PURCHASED POWER 29501. 294629. 428587. 430205. 431750. 433461. 435465. 437405. 439540. 5 TRANSMISSION Osh 5338. 5832. 6366. 6941. 7580. 8289. 9054. 9880. 10796. & ADMIN & GENERAL-EXCL INSURANCE 3740. 4255. 4596. 4964, 5361. 5790. 6254. 6754. 7294. 7 LONG-TERM LEASES 133. 133. 133. 133. 133. 133. 133. 133. 133. 8 ADDITIONAL G&8T STAFF 3998. 4318. 4664, 5037. 3440. 5875. 6345. 6852. 7401. 9 SUSITNA BARGE EXP 625. 665. 708. 755. 805. 859. 918. 981. 925. 10 G & T ORGANIZATION 0. 0. 0. 0. 0. 0. 0. 0. 0. 11 INSURANCE 402. 420. 439. 460. 483. 507. 533. 362. 593. 12 DEPRECIATION 16672. 17171. 17711. 18294. 18924. 19604. 20338. 21132. 21988. 13. TAXES 4. 4. 4. 4. 4. 4. 4. 4. 4. 14 INTEREST ON LONG-TERM DEBT 39662. 39277. 38857. 40721. 42707. 42121. 41477. 43952. 43184. 15 LESS: INTEREST CHARGED TO CONSTR 0. 9. 0. 0. 0. 0. 0. 0. 0. 16 OTHER DEDUCTIONS 662. 715. 772. 834. 900. 972. 1050. 1134. 1225. 17 TOTAL POWER COST-ACCRUAL 188953. 411964. 532638. 566230. 608410. 692789. 738374. 769469. 827780. 18 LESS POWER SOLD 0. 0. 0. 0. 0. 0. 0. 0. 0. 19 NET POWER COST-ACCRUAL 188953. 411964. 532638. 566230. 608410. 692789. 738394. 769469. 827780. 3 POWER COST-ACCRUAL (MILLS/KWH) 81.73 171.79 214.17 219.98 228.13 250.65 257.64 259.25 269.11 22 REVENUES: $1,000 23 + =REVENUES RE@D TO MAINTAIN TIER 196885. 419820. 540410. 574374. 616951. 701213. 746689. 778259. 9836417. 24 LESS: NON-OPERATING INCOME 2055. 2199. 2240. 2176. 3712. 5269. 4855. 4332. 5984. 25 LESS: OTHER OPERATING REVENUES 315. 315. 315. 315. 315. 315. 315. 315. 315. 26 LESS: PATRONAGE CAPITAL RETIREMENT 0. 0. 0. 0. 0. 0. 0. 0. 0. 27 REVENUES FROM RATEPAYERS 194515. 417305. 537855. 571882. 612924. 695629. 741518. 773612. 9830118. 28 WHOLESALE REVENUES, MILLS/KWH 84.13 174.02 216.27 222.18 229.82 251.67 258.73 260.65 269.87 = ANNUAL INCREASE % 4.83 106.84 24.28 2.73 3.44 9.51 2.80 0.74 3.54 31 MARGINS: $1,000 32 OPERATING MARGINS 3878. 3657. 5531. 5968. 4829. 3155. 3440. 4459. 2653. 33 NON-QPERATING INCOME 2055. 2199. 2240. 2176. 3712. 5269. 4855. 4332. 5984. 4 NET PATRONAGE CAPITAL OR MARGINS 7932. 7855. 7771. 8144. 8541. 8424. 8295. 8790. 8637. 36 OPERATING RATIOS: % OF POWER COST 37 PROD & PURCH POWER EXPENSE 62.19 82.33 86.06 86.20 86. 47 87.85 88.34 88.12 88.70 38 TRANSMISSION EXPENSE 2.82 1.42 1.20 1.23 1.25 1.20 1.23 1.28 1.30 39 ADMIN & GENERAL EXPENSE 2.30 1.13 0.95 0.96 0.96 0.91 0.92 0.95 0.95 40 OTHER EXPENSES 32. 68 15.12 11.80 11.62 11.33 10.04 9.52 9.64 9.04 a OPERATING REVENUE 104.20 101.91 101.44 101.44 101.40 101.22 101.12 101.14 101.04 43 FINANCIAL RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 45 DFRT SFRUTCF COUFRALF (NSM) 1.41 14a 1.41 1.39 1.38 1.48 1.39 1.39 1.39 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 191 POWER SUPPLY PROGRAM DATE: 9-Mar-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TINE: 07:27 PROJECT: 62-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE & SUSITNA PROJECTS HYDRGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: HYDRO (8%,20YR) VERSION: FIN. FORE. TABLE 14 PROJECTED OPERATING RESULTS CONTRACT YEAR 2001 2002 2003 2004 2005 2006 2007 2008 2009 1 EXPENSES: $1,000 2 = PRODUCTION O&M-EXCL FUEL 23559. 22535. 24476. 26664. 29507. 32602. 35855. 38539. 42593. 3 PRODUCTION-FUEL 331498. 39912. $7009. 80078. 173787. 307022. 385908. 375202. 539377. 4 PURCHASED POWER 442024. 724472. 728987. 733193. 737539. 742189. 747452. 752886. 758724. 5 TRANSMISSION Osh 11784. 12879. 14090. 15399. 16844. 18445. 20211. 22162. 24269. & ADMIN & GENERAL-EXCL INSURANCE 7877. 8507. 9188. 9923. 10717. 11575. 12500. 13500. 14580. 7 LONG-TERM LEASES 133. 133. 133. 133. 133. 133. 133. 133. 133. 8 ADDITIONAL G&T STAFF 7993. 8632. 9323. 10068. 10874. 11744. 12683. 13698. 14794, 9 SUSITNA BARGE EXP 999. 1079. 1165. 1258. 1359. 1448. 1585. 1712. 1849. 10 G & T ORGANIZATION 0. 0. 0. 0. 0. 0. 0. 0. 0. 11 INSURANCE 627. 663. 702. 744, 790. 840. 893. 950. 1012. 12 DEPRECIATION 22914. 23914. 24993. 26159. 27418. 28779. 30248. 31833. 33546. 13. TAXES 4. 4. 4. 4. 4. 4. 4. 4. 4. 14 INTEREST ON LONG-TERM DEBT 46042. 49107. 48063. 51561. 35306. 59308. 63575. 61779. 66620. 15 LESS: INTEREST CHARGED TO CONSTR 0. 0. 0. 0. 0. 0. 0. 0. 0. 16 OTHER DEDUCTIONS 1323. 1428. 1543. 1666. 1799. 1943. 2099. 2267. 2448. 17 TOTAL POWER COST-ACCRUAL 896776. 893265. 929676. 956851. 1066080. 1216252. 1313147. 1314665. 1499951. 18 LESS POWER SOLD 0. 0. 0. 0. 0. 0. 0. 0. 0. 19 NET POWER COST-ACCRUAL 896776. 893265. 929676. 956851. 1066080. 1216252. 1313147. 13146465. 1499951. 2 POWER COST-ACCRUAL (MILLS/KWH) 281.30 270.28 271.36 269.61 290.01 319.06 332.53 321.36 353.51 22 REVENUES: $1,000 23 REVENUES REGD TO MAINTAIN TIER 905984. 903086. 939288. 967163. 1077141. 1228114. 1325862. 1327021. 1513275. 24 LESS: NON-OPERATING INCOME 5181. 6947. 8744. 7165. 8660. 10039. 11488. 12952. 9762. 25 LESS: OTHER OPERATING REVENUES 315. 315. 315. 315. 315. 315. 315. 315. 315. 26 LESS: PATRONAGE CAPITAL RETIREMENT 0. 0. 3231. 4934, 7283. 7261. 7236. 8123. 8084. 27 REVENUES FROM RATEPAYERS 900488. 895824. 926998. 954749. 1060882. 1210498. 1306822. 1305631. 1495111. 28 WHOLESALE REVENUES, MILLS/KWH 282.46 271.05 270.58 269.02 288.60 317.55 330.92 319.15 352.37 z ANNUAL INCREASE % 4.67 -4.04 -0.17 -0.58 7.28 10.03 4.21 -3.56 10.41 31 MARGINS: $1,000 32 OPERATING MARGINS 4027. 2875. 869. 3148. 2401. 1823. 1227. -596. 3562. 33 NON-OPERATING INCOME 5181. 6947. 8744. 7165. 8660. 10039. 11488. 12952. 9762. = NET PATRONAGE CAPITAL OR MARGINS 9208. 9821. 9613. 10312. 11061. 11862. 12715. 12354. 13324. 36 OPERATING RATIOS: % OF POWER COST 37 =PROD & PURCH POWER EXPENSE 88.88 88.09 88.25 87.78 88.25 88.96 89.04 88.74 89.38 38 TRANSMISSION EXPENSE 1.31 1.44 1.52 1.61 1.58 1.52 1.54 1.69 1.42 39 ADMIN & GENERAL EXPENSE 0.95 1.03 1.06 1.11 1.08 1.02 1.02 1.10 1.04 40 OTHER EXPENSES 8.85 9.44 9.17 9.49 9.09 8.50 8.40 8. 48 7.96 a OPERATING REVENUE 101.03 101.10 101.03 101.08 101.04 100.98 100.97 100.94 100.89 43 FINANCIAL RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 45 NERT SFRUTCTE CNUFRALF (NSM) 1.8A TA7 1.97 1.24 ee 1.39 1.439 1.31 wot BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 192 POWER SUPPLY PROGRAN DATE: 9-Mar-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 07:27 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE & SUSITNA PROJECTS HYDRGT. D2 GENERATION AND TRANSMISSION COOP. PLAN: HYDRO (8%,20YR) VERSION: FIN. FORE. TABLE 14 PROJECTED OPERATING RESULTS CONTRACT YEAR 2010 2011 2012 2013 2014 2015 Cate! 1 EXPENSES: $1,000 (1983$) 2 PRODUCTION O&N-EXCL FUEL 46534. 50968. 36585. 61252. 67292. 74667. 3 = PRODUCTION-FUEL 622725. 765482. 1029395. 1118677. 1413644. 1829319. 4 PURCHASED POWER 765347. 772157. 779551. 787835. 796442. 805729. 5 TRANSMISSION Osh 26594, 29159. 31987. 35105. 38471. 42181. & ADMIN & GENERAL-EXCL INSURANCE 15747. 17006. 18367. 19836. 21423. 23137. 7 LONG-TERM LEASES 133. 133. 133. 133. 133. 133. 8 ADDITIONAL G&T STAFF 15977. 17256. 18436. 20127. 21737. 23476. 9 SUSITNA BARGE EXP 1997. 2157. 2329. 2516. 2717. 2934. 10 G & T ORGANIZATION 0. 0. 0. 0. 0. 0. 11 INSURANCE 1080. 1152. 1231. 1315. 1406. 1505. 12. DEPRECIATION 35397. 37239. 39398. 36683. 39201. 41920. 13. TAXES 4. 4. 4. 4. 4. 4. 14 INTEREST ON LONG-TERM DEBT 71817. 77345. 83243. 80209. 87105. 94855. 15 LESS: INTEREST CHARGED TO CONSTR 0. 0. 0. 0. 0. 0. 16 OTHER DEDUCTIONS 2644, 2856. 3084. 3331. 3597. 3885. 17 TOTAL POWER COST-ACCRUAL 1605996. 1772916. 2063944. 2167023. 2493173. 2943746. 18 LESS POWER SOLD 0. 0. 0. 0. 0. 0. 19 NET POWER COST-ACCRUAL 1605996. 1772916. 2063944. 2167023. 2493173. 2943746. 2 POWER COST-ACCRUAL (MILLS/KWH) 365. 41 389.57 437.37 443.15 492.04 560.82 22 REVENUES: $1,000 23 REVENUES REQD TO MAINTAIN TIER 1620359. 1788385. 2080593. 2183064. 2510594. 2962717. 24 LESS: HON-OPERATING INCOME 11295. 12908. 14622. 16204. 10995. 12991. 25 LESS: OTHER OPERATING REVENUES 315. 315. 315. 315. 315. 315. 26 LESS: PATRONAGE CAPITAL RETIREMENT 8044. 7994. 7932. 7855. 7771. 8144. 27 REVENUES FROM RATEPAYERS 1600705. 1767167. 2057723. 2158690. 2491512. 2941267. 34497208. 28 WHOLESALE REVENUES, MILLS/KWH 364.21 388.30 436.05 441.45 471.71 560. 35 . ANNUAL INCREASE % 3.36 6.62 12.30 1.24 11.39 13.98 31 MARGINS: $1,000 32 OPERATING MARGINS 3068. 2561. 2026. ~162. 6426. 5980. 33 NON-OPERATING INCOME 11295. 12908. 14622. 16204, 10995. 12991. 4 NET PATRONAGE CAPITAL OR MARGINS 14363. 15449. 16649. 16042. 17421. 18971. 36 OPERATING RATIOS: % OF POWER COST 37 ~=PROD & PURCH POWER EXPENSE 89.33 89.460 90.39 90.80 91.34 92.05 38 TRANSMISSION EXPENSE 1.46 1.64 1.55 1.62 1.54 1.43 39 ADMIN & GENERAL EXPENSE 1.05 1.02 0.95 0.98 0.92 0.84 40 OTHER EXPENSES 7.97 7.73 7.11 4.60 6.20 5.468 4 OPERATING REVENUE 100.89 100.87 100.81 100.74 100.70 100.44 43 FINANCIAL RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 1.20 1.20 1.20 1.20 1.20 1.20 44 DFAT SFRUICE PNUFRACE (NSM) 1.30 1.9R 1.98 1.92 1.94 1.30 eo ie em psa Gas-Fired Expansion Scenario Existing Arrangement 10-Year Capital Credit Rotation BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82--113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION EXISTING GRGANIZATIONAL STRUCTURE PLAN: GAS(8Z, LOYR) CONTRACT YEAR 1 EXPENSES: 2 PRODUCTION O&M-EXCL FUEL 3 PRODUCTION-FUEL 4 PURCHASED PQWER 7 TRANSIIESSION 08M 7 8 9 $1,000 ADMIN & GENERAL-EXCL INSURANCE LGMC-TERM LEASES HOMER XMSN LEASE PNT SUSITNA BARGE EXP 10 = MATAN XMSN LEASE PNT 110 INSURANCE 12.) DEPRECIATION 13° TAXES 14 INTEREST ON LONG-TERM DEBT 15. LESS: INTEREST CHARGED TO CONSTR 16 = OTHER DEDUCTIONS 17 TOTAL PQWER COST-ACCRUAL 18 (ESS POWER SOLD 19 = WET POWER COST-ACCRUAL 20 = PQWER COST-ACCRUAL (MILLS/KWH) 22 REVENUES: $1,000 23 > REVENUES RE@D TO MAINTAIN TIER 24 LESS: NON-GPERATING INCOME 25° «LESS: OTHER OPERATING REVENUES 26 LESS: PATRONAGE CAPITAL RETIREMENT 27 REVENUES FROM RATEPAYERS 28 = WHOLESALE REVENUES, MILLS/KWH 2? = ANNUAL. INCREASE % 31 MARGINS: $1,000 32 OPERATING PARGINS 33) NON-OPERATING INCOME 34 NET PATRONAGE CAPITAL OR MARGINS 36 OPERATING RATIOS: % GF POWER COST 37 PROD & PURCH POWER EXPENSE 38 = TRANSMTSSION EXPENSE 39 = ADILIN & GENERAL EXPENSE 40 = OTHER EXPENSES 41 OPERATING REVENUE [Al. RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 45 DEBT SERVICE COVERAGE (DSC) 1983 3303. 5126. 1291. 881. 1676. 133. 336. 700. 149. 21. 7775. 4. 21302. 0. 741. 43437. 0. 45437. 27.08 48633. 320. 315. 0. 47998. 28.60 0.00 2876. 320. 3195. 25.79 1.94 3.73 68.53 107.03 —_ eco 1986 7739. 7631. 2220. 2290. 2483. 133. 370. 440. 172. 241. ee 30098. 0. 640. 66727. 0. 66727. 35.72 96825. 2397. 315. 0. 94113. 50.38 0.76 27701. 2397. 30098. 26.36 3.43 4.08 66.12 145.11 2.00 TABLE 14 PROJECTED OPERATING RESULTS 1984 1985 3863. 6921. 6146. 6517. 1252. 2029. 1067. 2060. 1849. 2222. 133. 133. 385. 377. 720. 742. 178. 175. 46. 198. 8333. 11574. 4. 4. 24441. 30199. 0. 0. 580. 609. — —_— 50996. 63760. 29.29 35.42 73437. 93959. 1829. 3644. 315. 315. 0. 0. 73293. 90000. 42.10 30.00 47.18 18.77 22612. 26556. 1829. 3644, 24441. 30199. 26.00 24.26 2.09 3.23 3.72 3.80 68.19 68.72 147.93 147.36 2.00 2.00 2.08 2.16 2.17 ao 29.27 3.77 4.35 62.61 141.49 2.00 2.18 45.79 3.64 3.27 47.30 130.39 2.00 2.23 mm a 9 PAGE: 180 DATE: 9-Har-83 TIME: 14:30 FILES: CHN.D1 GAS. 02 VERSION: FIN. FORE. 1989 1990 1991 9789. 10630. 11576. 9644. 11364. 62604. 28477. 28710. 29003. 3909. 4241. 4599. 3129. 3378. 3649. 133. 133. 133. 349. 341. 335. 322. 353. 388. 164. 161. 158. 356. 370. 385. oo — ety 29476. 297298. 25908. 0. 0. 0. 325. 367. 613. — — =_ 101945. 105368. 155602. 30.79 49.82 69. 68 131421. 134666. 181510. 2681. 340. 4255. 315. 315. 315. 0. 0. 0. 128426. 127811. 176940. 63.99 61.38 79.24 3.68 -4.08 27.10 26796. 24758. 21653. 2681. 4540. 4255. 29476. 297298. 25908. 47.00 48.12 66.31 3.83 4.02 2.96 3.42 3.56 2.59 45.75 44.30 28.14 128.91 127.81 116.45 2.00 2.00 2.00 2.24 2.23 2.26 BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION EXISTING ORGANIZATIONAL STRUCTURE PLAN: GAS(8%, LOYR) CONTRACT YEAR 1 EXPENSES: $1,000 PRODUCTION O&M-EXCL FUEL PRODUCT ION-FUEL PURCHASED POWER TRANSMISSION O&M ADMIN & GENERAL-EXCL INSURANCE LONG-TERM LEASES HOMER XMSN LEASE PNT SUSITNA BARGE EXP 10 MATAN XMSN LEASE PNT 11 INSURANCE 12 DEPRECIATION 13. TAXES 14 INTEREST ON LONG-TERM DEBT 15° LESS: INTEREST CHARGED TO CONSTR 16 OTHER DEDUCTIONS 17 TOTAL POWER COST-ACCRUAL 18 LESS POWER SOLD 19 ~=NET POWER COST-ACCRUAL 20 POWER COST-ACCRUAL (MILLS/KWH) 22 REVENUES: $1,000 23° REVENUES REQO TO MAINTAIN TIER 24 LESS: WON-OPERATING INCOME 25 LESS: OTHER OPERATING REVENUES 26 LESS: PATRONAGE CAPITAL RETIREMENT 27 REVENUES FROM RATEPAYERS 28 WHOLESALE REVENUES, MILLS/KWH 29 ANNUAL INCREASE % 31 MARGINS: $1,000 32 OPERATING MARGINS 33 NON-OPERATING INCOME BA NET PATRONAGE CAPITAL OR MARGINS 36 OPERATING RATIOS: % OF POWER COST 37 ~=PROD & PURCH POWER EXPENSE 38 TRANSMISSION EXPENSE 39 ADMIN & GENERAL EXPENSE 40 OTHER EXPENSES a OPERATING REVENUE 43 FINANCIAL RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 45 DEBT SERVICE COVERAGE (DSC) NWONOV BWR 1992 12569. 75447. 29501. 4985. 3940. 133. 329. 625. 155. 401. 16509. 21097. 0. 662. Tae 166359. 71.95 187456. 3095. 315. 184046. 79.60 0.46 18002. 3095. 21097. 70.64 3.00 2.61 23.75 112.68 1995 16203. 217101. 31910. 6342. 4964. 133. 278. 735. 145. 459. 18131. 4. 20335. 0. 834. la 317593. 123.39 337928. 4463. 315. 30199. 302950. 117.70 44.54 15871. 4463. 20335. 83.51 2.00 1.71 12.79 106. 40 2.00 TABLE 14 PROJECTED OPERATING RESULTS 1993 1994 13708. 14875. 95670. 115312. 30105. 30677. 3404. 3855. 4255. 4396. 133. 133. 320. 313. 665. 708. 151. 148. 419. 438. Hoa ia 20864. 20612. 0. 0. 715. 772. oe aileye 187422. 211992. 78.99 85.24 210286. 232605. 4398. 3340. 315. 315. 3195. 24441. 202378. 202509. 84.39 81.43 6.02 -3.52 16446. 13272. 4398. 5340. 20864. 20612. 73.64 73.88 2.85 2.76 2.47 2.37 21.04 18.98 111.01 109.72 2.00 2.00 2.29 2.30 2.29 0. 440562. 165.19 463107. 3097. 315. 30098. 429576. 161.08 36.86 19447. 3097. 22545. 87.23 1.56 1.33 9.89 105.12 2.00 2.26 PAGE: 181 DATE: 9-HMar-83 TIME: 14:30 FILES: CHM.D1 GAS. D2 VERSION: FIN. FORE. 1998 1999 2000 20864. 22616. 24606. 615126. 676881. 757600. 39833. 49106. 735941. 8108. 8834. 9643. 6254. 6754. 7294. 133. 133. 133. 234. 237. 228. 718. 981. 925. 131. 127. 122. 333. 362. 393. are aide ane 27504. 30290. 297869. 0. 0. 0. 1050. 1134. 1225. Ter inhi’ yee 740870. 818630. 9730009. 258.51 275.82 302. 34 768374. 848920. 959877. 4607. 3668. 6924, 315. 315. 315. 30083. 29476. 29298. 733389. 813460. 923340. 255.89 274.08 300. 18 9.84 7.11 9.52 22898. 24622. 22945. 4607. 3668. 6924. 27504. 30290. 29869. 971.22 91.45 92.27 1.09 1.08 1.04 0.92 0.89 0.85 6.77 6.58 5.84 103.71 103.70 103. 21 2.00 2.00 2.00 2.24 2.24 2.24 CHUGACH, HOMER & MATANUSKA ELEC. PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION EXISTING ORGANIZATIONAL STRUCTURE PLAN: GAS(2%, LOYR) CONTRACT YEAR 1 EXPENSES: $1,000 PRODUCTION O&M-EXCL FUEL PRODUC TION-FUEL PURCHASED POWER TRANSMISSION O&M ADMIN & GENERAL-EXCL INSURANCE LONG-TERM LEASES HOMER XMSN LEASE PNT SUSITNA BARGE EXP 10 NMATAN XMSN LEASE PNT 11 INSURANCE 12 DEPRECIATION 13. TAXES 14 INTEREST ON LONG-TERM DEBT 15 LESS: INTEREST CHARGED TO CONSTR 16 OTHER DEDUCTIONS 17. TOTAL POWER COST-ACCRUAL 18 LESS POWER SOLD 19 =NET POWER COST-ACCRUAL 20 POWER COST-ACCRUAL (MILLS/KWH) SCONGUaWH 21 22 REVENUES: $1,000 23> REVENUES RE@D TO MAINTAIN TIER 24 LESS: WNON-OPERATING INCOME 25 LESS: OTHER OPERATING REVENUES 26 LESS: PATRONAGE CAPITAL RETIREMENT 27 REVENUES FROM RATEPAYERS 28 WHOLESALE REVENUES, MILLS/KWH a ANNUAL INCREASE % 31 MARGINS: $1,000 32 OPERATING MARGINS 33 NON-OPERATING INCOME 34 NET PATRONAGE CAPITAL OR MARGINS 35 7 34 OPERATING RATIOS: % OF POWER COST 37 PROD & PURCH POWER EXPENSE 38 TRANSMISSION EXPENSE 39 = ADTIIN & GENERAL EXPENSE 49 OTHER EXPENSES 2 GPERATING REVENUE 43 FINANCIAL RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 45 DERT SERVICE COVERAGE (DSC) BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM ASSCCIATIONS 1013889. 318.03 1087114. 8150. 315. 25908. 1054740. 330. 85 10.22 67075. 8150. 75225. 2004 44707. 1117271. 95350. 13576. 13044, 133. 195. 1258. 100. 1997. — 68518. 0. 1666. ait 1398874, 394.16 1467393. 7362. 315. 20612. 1438703. 405.44 7.93 60956. 7362. 68518. 897.88 0.97 1.08 8.07 104.90 2.00 2.48 TABLE 14 PROJECTED OPERATING RESULTS 2002 2003 37967. 41147. 908485. 1000185. 44322. 64475. 11458. 12475. 11183. 12078. 133. 133. 211. 202. 1079. 1165. 113. 107. 1916. 1955. — rr 69980. 68851. 0. 0. 1428. 15343. ar se 1127090. 1244210. 341.03 363.17 1197070. 1313062. 3044. 3174. 315. 315. 21097. 20864. 1170613. 1286708. 354.19 375.57 7.06 6.04 64936. 63677. 5044. 3174. 69980. 68851. 87.91 88.88 1.02 1.00 1.16 1.13 9.92 8.99 106.21 105.53 2.00 2.00 2.43 2.48 2005 48694. 12972021. 89409. 14763. 14088. 133. 115. 1359. 94. 2042. — 68129. 0. 1799. 1574962. 0. 1574962. 428.44 1643071. 11032. 315. 20335. 1611409. 438.36 8.12 37097. 11032. 68129. 90.80 0.94 1.02 7.23 104.33 2.00 2.48 2006 352778. 1396247. 194421. 16046. 15215. 133. 109. 1468. 88. 20971. —_s 67675. 0. 1943. ates 1791871. 470.07 1859566. 14277. 315. 22545. 1822429. 478.08 9.06 33399. 14277. 67675. 91.72 0.90 0.97 6.42 103.78 2.00 2.48 2007 37381. 1617422. 149991. 17431. 16432. 133. 102. 1585. 83. 2144. 43139. 4. 67157. 0. 2099. — 1977102. 300. 46 2044259. 17079. 315. 24930. 2001934. 306. 95 6.04 30077. 17079. 67157. 72.30 0.88 0.94 3.88 103. 40 2.00 2.49 a PAGE: 182 DATE: 9-Mar-83 TIME: 14:30 FILES: CHM.D1 GAS. D2 VERSION: FIN. FORE. 2008 2009 90121. 97878. 1648459. 1856777. 39160. 72069. 18926. 20542. 26238. 28337. 133. 133. 93. 85. 1712. 1849. 76. 67. 6499. 6561. — sae —- 21 _ 2267. 2448. antes —T 2164690. 2378510. 329.13 365.29 2377346. 2610214. 27209. 13401. 315. 315. 27504. 30290. 2322318. 2566208. 367.67 604. 81 11.98 6.54 183448. 198303. 27209. 13401. 212657. 211704. 83.05 84.50 0.87 0.86 1.51 1.45 14.36 13.19 109.82 108.83 2.00 2.00 2.37 2.37 BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION EXISTING GRGANIZATIONAL STRUCTURE PLAN: GAS(G%, LOYR) CONTRACT YEAR 1 NMONAU RON 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 EXPENSES: $1,000 PRODUCTION O&M-EXCL FUEL PRODUCTION-FUEL PURCHASED POWER TRAHSMISSION O&M ADMIN & GENERAL-EXCL INSURANCE LONC-TERM LEASES HOMER XMSN LEASE PNT SUSITNA BARGE EXP MATAH XMSN LEASE PNT INSURANCE DEPRECIATION TAXES INTEREST ON LONG-TERM DEBT LESS: INTEREST CHARGED TO CONSTR OFHER DEDUCTIONS TOTAL POWER COST-ACCRUAL LESS PQUER SOLD NET POWER COST-ACCRUAL POWER COST-ACCRUAL (MILLS/KWH) REVENUES: $1,000 REVEHUES REQD TO MAINTAIN TIER LESS: NON-OPERATING INCOME LESS: OTHER OPERATING REVENUES LESS: PATRONAGE CAPITAL RETIREMENT REVENUES FROM RATEPAYERS WHOLESALE REVENUES, MILLS/KWH ANHUAI. INCREASE % MARGINS: $1,000 OPERATING MARGINS NOW-OPERATING INCOME NET PATRONAGE CAPITAL OR MARGINS OPERATING RATIOS: % OF POWER COST PROD & PURCH POWER EXPENSE TRANSTSSION EXPENSE ADMIN & GENERAL EXPENSE OFHER EXPENSES OPERATING REVENUE FINANCIAL RATIOS: TIMES INTEREST EARNED RATIO (TIER) DEBT SERVICE COVERAGE (DSC) 0. 0. 0. 0. 26973250. 2950052. 3329347. 3670322. 4081440. 612.80 648.22 705.52 754. 67 2903892. 3159510. 3537487. 4053308. 4 30181. 46565. 58849. 80128. 315. 315. 315. 315. 29869. 75225. 69980. 68851. 646.99 667.41 722.26 798. 37 6.97 3.16 8.22 10.54 TABLE 14 PROJECTED OPERATING RESULTS 2010 2011 2012 2013 2014 106422. 115104. 125071. 175334. _ 190605. 2110536. 2276932. 2561874. 2798271. 3148837. 99312. 175636. 254049. — 76045. 93440. 22287. 24171. 26206. 28404. 30778. 30605. 33053. 35697. 51031. 55113. 133. 133. 133. 133. 133. 79. 58. 52. 44. 44. 1997. 2157. 2329. 2516. 2717. 59. 46. 13. 12. 10. 6628. 6700. 6778. 13176. 13267. 101903. 103743. 105901. 179034. 181549. 210642. 209458. 208138. 962987. 361347. 2644. 2856. 3084. 3331. 3597. 2693250. 29750052. 3327349. 3690322. 4081440. 1442787. 21654, 315. 68518. 2843527. 3037404. 3408343. 39704013. 4352300. 858.95 7.59 180460. 162893. 149289. 282859. 339693. 30181. 46565. 38849. 80128. 21654. 210642. 209458. 208138. 362987. 361347. 86.00 87.04 88.34 82.64 0.83 0.82 0.79 0.77 1.38 1.35 1.28 1.74 11.79 10.79 9.60 14.85 107.82 107.10 106.25 109.84 2.00 2.00 2.00 2.00 2.37 2.37 2.36 2.40 84.11 0.75 1.68 13.46 108.85 2.00 2.40 2015 PRESENT 207179. 3523752. 163910. 33342. 59522. 133. 0. 2934. 10. 13365. ie 359173. 0. 3885. 455147 . 4551474, 867.11 4710648. 30610. 315. 68129. 4791594. 912.86 6.28 308564. 50610. 359173. 85.57 0.73 1.60 12.09 107.8? 2.00 2.34 VALUE (19783$) 4099280. PAGE: 183 DATE: 9-Mar-83 TIME: 14:30 FILES: CHM.D1 GAS. D2 VERSION: FIN. FORE. nee pray Coal-Fired Expansion Scenario E Existing Arrangement 10-Year Capital Credit Rotation BURHS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, DEVELOP COAL-FIRED GENERATION EXISTING ORGANIZATIONAL STRUCTURE PLAN: COAL (8%, LOYR) CONTRACT YEAR 1 SWONOU DWN 24 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 4i 42 43 44 45 EXPENSES: $1, 000 PRODUCTION O&N-EXCL FUEL PRODUCT ION-FUEL PURCHASED POWER TRANSMISSION O&M ADMIN & GENERAL-EXCL INSURANCE LONG-TERM LEASES HOMER XPSN LEASE PNT SUSITMA BARGE EXP MATAN XMSN LEASE PriT INSURANCE DEPRECIATION TAXES INTEREST ON LONG-TERM DEBT LESS: INTEREST CHARGED TO CONSTR OTHER DEDUCTIONS TOTAL POWER COST-ACCRUAL LESS POWER SOLD NET POWER COST-ACCRUAL POWER COST-ACCRUAL (MILLS/KWH) REVENUES: $1,000 REVENUES REQOD TO MAINTAIN TIER LESS: NON-OPERATING INCOME LESS: OTHER OPERATING REVENUES LESS: PATRONAGE CAPITAL RETIREMENT REVENUES FROM RATEPAYERS WHOLESALE REVENUES, MILLS/KWH ANNUAL INCREASE % MARGINS: $1,000 OPERATING MARGINS NON-OPERATING INCOME NET PATRONAGE CAPITAL OR MARGINS OPERATING RATIOS: % OF POWER COST PROD & PURCH POWER EXPENSE TRANSMISSION EXPENSE ADMIN & GENERAL EXPENSE OTHER EXPENSES OPERATING REVENUE FINANCIAL RATIOS: TIMES INTEREST EARNED RATIO (TIER) DEBT SERVICE COVERAGE (DSC) 2876. 320. 3195. 23.79 1.94 3.73 68.53 107.03 1986 7739. 7631. 2220. 2290. 2483. 133. 370. 440. 172. 241. 12265. 30098. 0. 640. —e 66727. 35.72 96825. 2397. 315. 94113. 50. 38 0.76 27701. 2397. 30078. 26.36 3.43 4.08 66.12 145.11 2.00 TABLE 14 PROJECTED OPERATING RESULTS 1984 1985 3863. 6921. 6146. 6517. 1252. 2029. 1067. 2060. 1849. 2222. 133. 133. 385. 377. 720. 742. 178. 175. 44. 198. 8333. 11574. 4. 4. 24441. 30199. 0. 0. 380. 609. sale e's 50996. 63760. 29.29 35.42 73437. 93959. 1829. 3644. 315. 315. 0. 0. 73293. 970000. 42.10 50.00 47.18 18.77 22612. 26556. 1829. 3644. 24441. 30199. 26.00 24.26 2.09 3.23 3.72 3.80 68.19 68.72 147.93 147.36 2.00 2.00 2.08 2.16 2.17 29.27 3.77 4.35 62.61 141.49 2.00 2.18 1988 8993. 8195. 28146. 3602. 2897. 133. 359. 492. 167. 343. 15101. 4. 30083. 0. 486. — 977002. 49.40 1297085. 3093. 315. 0. 123677. 61.72 32.00 249791. 5093. 30083. 45.79 3.64 3.27 47.30 130.39 2.00 2.23 PAGE: 180 DATE: 9-Mar-83 TINE: 14:48 FILES: CHM.01 COAL.D2 VERSION: FIN. FORE. 1989 1990 1991 9789. 10630. 11576. 9644, 11364. 62604, 28477. 28710. 29003. 3909. 4241. 4579. 3129. 3378. 3649. 133. 133. 133. 349. 341. 335. 522. 553. 388. 164. 161. 158. 354. 370. 385. ~— _— — ° 29476. 29298. 25908. 0. 0. 0. 325. 367. 613. en —_—,- ne 101745. 105368. 155602. 30.79 49.82 69. 68 131421. 134666. 181510. 2681. 4540. 4255. 315. 315. 315. 0. 0. 0. 128426. 127811. 176940. 63.99 61.38 79.24 3.68 -4.08 27.10 26796. 24758. 21653. 2681. 4540. 4255. 29476. 29298. 25908. 47.00 48.12 66.31 3.83 4.02 2.96 3.42 3.56 2.59 45.75 44.30 28.14 128.91 127.81 116.465 2.00 2.00 2.00 2.24 2.23 2.26 CHUGACH, HOMER & MATANUSKA ELEC. PROJECT: 82-113-4-000 EXISTING ORCANIZATIONAL STRUCTURE PLAN: COAL (8%, 1OYR) CONTRACT YEAR 1 WONAU RW 45 EXPENSES: $1, 000 PRODUCTION O&N-EXCL FUEL PRODUCT ION-FUEI_ PURCHASED POWER TRANSMISSION O&M" ADMIN & GENERAL-EXCL INSURANCE LONG-TERM LEASES HOrIER XMSN LEASE PNT SUSITNA BARGE EXP MATAN XMSN LEASE PHT INSURANCE DEPRECIATION TAXES INTEREST ON LONG-TERM DEBT LESS: INTEREST CHARGED TO CONSTR OTHER DEDUCTIONS TOTAL POWER COST-ACCRUAL LESS POWER SOLD NET POWER COST-ACCRUAL POWER COST-ACCRUAL (MILLS/KWH) REVENUES: $1, 000 REVENUES REGD TO MAINTAIN TIER LESS: NON-OPERATING INCOME LESS: OTHER OPERATING REVENUES LESS: PATRONAGE CAPITAL RETIREMENT REVENUES FROM RATEPAYERS WHOLESALE REVENUES, MILLS/KWH ANNUAL INCREASE % MARGINS: $1,000 OPERATING MARGINS WON-OPERATING INCOME NET PATROHAGE CAPITAL OR MARGINS OPERATING RATIOS: % OF POWER COST PROD & PURCH POWER EXPENSE TRANSMISSION EXPENSE ADMIN & GENERAL EXPENSE OTHER EXPENSES OPERATING REVENUE FINANCIAL RATIOS: TIMES INTEREST EARNED RATIO (TIER) DEBT SERVICE COVERAGE (DSC) BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN ASSOCIATIONS BRADLEY LAKE, DEVELOP COAL-FIRED GENERATION 1992 12569. 73447. 29501. 4985. 3940. 133. 329. 625. 155. 401. 16509. 4. 21097. 0. 662. 166359. 0. 166359. 71.95 187456. 3095. 315. 0. 184046, 79.60 0.46 18002. 3095. 21097. 70.64 3.00 2.61 23.75 112.468 2.00 2.29 1995 16203. 217101. 31910. 6342. 4964. 133. 278. 733. 145. 459. 18131. 4. 20335. 0. 834. 317593. 0. 317593. 123.39 337928. 4463. 315. 30199. 302950. 117.70 44.54 15871. 4453. 20335. 83.51 2.00 1.71 12.79 106. 40 TABLE 14 PROJECTED OPERATING RESULTS 1993 1994 13708. 14875. 93670. 115312. 30105. 30677. 5404. 3855. 4255. 4596. 133. 133. 320. 313. 665. 708. 151. 148. 419. 438. — = 20864. 20612. 0. 0. 715. 772. _ 21 aves 187422, 211992. 78.99 85.24 210286. 232605. 4398. 3340. 315. 315. 3195. 24441. 202378. 202509. 84.39 81.43 6.02 3.52 16466. 15272. 4398. 5340. 20864. 20612. 73.64 75.88 2.85 2.76 2.47 2.37 21.04 18.98 111.01 109.72 2.00 2.00 2.29 2.30 1996 17657. 332995. 33640. 6868. 3361. 133. 269. 805. 142. 482. 18741. 4. 22545. 0. 900. ane 440562. 165.19 463107. 3097. 315. 30098. 429596. 161.08 36.86 19447. 3097. 22545. 87.23 1.56 1.33 9.89 105.12 1997 19128. 335647. 33700. 7454. 5790. 133. 262. 859. 137. 507. ia 24930. 0. 972. 650965. 0. 650965. 235.52 673875. 3648. 315. 27984. 643748. 232.98 44.64 21282. 3648. 24930. 90.71 1.15 0.97 7.18 103.83 2.00 2.24 PAGE: 181 DATE: 99-Mar-83 TIME: 14:48 FILES: CHM.D1 COAL.D2 VERSION: FIN. FORE. 1998 1999 2000 20864. 22616. 24606. 615126. 676881. 757600. 39833. 491064. 75941. 8108. 8834. 9643. 6254. 6754. 7294, 133. 133. 133. 254. 237. 228. 918. 981. 925. 131. 127. 122. 533. 362. 593. aan aa’ —_: 27504. 30290. 29869. o. 0. 0. 1050. 1134. 1225. rer alee: roe 740870. 818630. 9730009. 258.51 275.82 302.34 768374. 848920. 959877. 4607. 3668. 6924. 315. 315. 315. 30083. 29476. 29298. 733389. 813460. 923340. 255.89 274.08 300. 18 9.84 7.11 9.52 22898. 24622. 22945. 4607. 3648. 6724. 27504. 30290. 29869. 91.22 91.45 92.27 1.09 1.08 1.04 0.92 0.89 0.85 6.77 6.58 5.84 103.71 103.70 103.21 2.00 2.00 2.00 2.24 2.24 2.24 BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSCCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, DEVELOP COAL-FIRED GENERATION EXISTING ORGANIZATIONAL STRUCTURE PLAN: COAL (8%, LOYR) CONTRACT YEAR 1 EXPENSES: $1,000 PRODUCTION O&N-EXCL FUEL PRODUCT ION-FUEL PURCHASED POWER TRANSMISSION O&" ADMIN & GENERAL-~EXCL INSURANCE LONG-TERM LEASES HOMER XPSN LEASE Prt SUSITNA BARGE EXP 10 =MATAN XMSN LEASE PriT 11 INSURANCE 12 DEPRECIATION 13. TAXES 14 INTEREST ON LONG-TERM DEBT 15. LESS: INTEREST CHARGED TO CONSTR 16 OTHER DEDUCTIONS 17, TOTAL POWER COST-ACCRUAL 18 LESS POWER SOLD 19 NET POWER COST-ACCRUAL 20 POQUER COST-ACCRUAL (MILLS/KWH) 22 REVENUES: $1,000 23 > REVENUES RE@D TO MAINTAIN TIER 24 LESS: NON-OPERATING INCOME 25 LESS: OTHER OPERATING REVENUES 26 LESS: PATROHAGE CAPITAL RETIREMENT 27 REVENUES FROM RATEPAYERS 28 WHOLESALE REVENUES, MILLS/KWH 2? ANNUAL INCREASE % 31 MARGINS: $1,000 32 OPERATING MARGINS 33 NON-GPERATING INCOME 34 NET PATRGHAGE CAPITAL OR MARGINS 34 OPERATING RATIOS: % OF POWER COST 37 PRUD & PLIRCH POWER EXPENSE 38 = TRANSTIISSIGH EXPENSE 3? ADMIN & GENERAL EXPENSE 40 OFHER EXPENSES 41 OPERATING REVENUE 43 FINANCIAL RATIOS 44 TINES INTEREST EARNED RATIO (TIER) 45 DEKT SERVICE COVERAGE (DSC) CONAUbWN 2001 48472. 716623. 41685. 10515. 13999. 133. 219. 999. 118. 3160. 54372. 4. 124311. 0. 1323. 1015933. 0. 1015933. 318. 67 1140243. 10776. 315. 25908. 1103243. 346.06 15.29 113534. 10776. 124311. 79,41 1.04 1.49 17.86 112.24 2.00 2.31 2004 61798. 10154685. 100826. 13576. 17635. 133. 195. 1258. 100. 3277. — 117604. 0. 1666. ar 13971372. 392.05 1508975. 20690. 315. 20612. 1467358. 413.45 7.07 96913. 20690. 117604. 84.69 0.98 1.50 12.83 108. 43 2.00 2.42 TABLE 14 PROJECTED OPERATING RESULTS 2002 2003 532632. 34976. 820624. 9705189. 45953. 47527. 11458. 12475. 15119. 16329. 133. 133. 211. 202. 1079. 1165. 113. 107. 3196. 3235. oad a so. 119065. 117937. 0. 0. 1428. 1543. 1iggPaE — 1126385. 1239272. 340.81 361.73 1243431. 1357209. 7669. 13051. 315. 315. 21097. 20864. 1216369. 1322979. 368.04 386.16 6.35 4.92 111397. 104886. 7669. 13051. 119065. 117937. 81.61 83.09 1.02 1.01 1.63 1.58 15.75 14.33 110.57 109.52 2.00 2.00 2.39 2.42 2005 67146. 1184273. 94578. 14763. 19046. 133. 115. 1359. 94. 3322. 38873. 4. 117214. 0. 1799. 1562720. 0. 1562720. 425.11 1679934. 29412. 315. 20335. 1629872. 443.38 7. 24 87802. 27412. 117214. 86.13 1 10, 0. 1. 8s «83 2. 2. 94 43 2006 72692. 1278120. 205950. 16046. 20570. 133. 109. 1448. 88. 3371. — 116761. 0. 1943. th: 1777486. 466.29 1894247. 37908. 315. 22545. 1833479. 480.98 8.48 78853. 37908. 116761. 87.58 0.90 1.35 10.17 106.57 2.00 2.42 2007 78888. 1494085. 159118. 17431. 22215. 133. 102. 1585. 83. 3424. sr 116242. 0. 2099. 1957108. 0. 1957108. 495.60 2073350. 45962. 315. 24930. 2002143. 307.00 3.41 70280. 45962. 116242. 88.50 0.89 1.31 9.30 105.94 2.00 2.43 PAGE: 182 DATE: 99-Mar-83 TIME: 14:48 FILES: CHM.D1 COAL.D2 VERSION: FIN. FORE. 2008 2009 159782. 173130. 1267028. 1448966. 67646. 83644. 18926. 20542. 44976. 48574. 133. 133. 93. 85. 1712. 1849. 76. 67. 12165. 12227. 170824. 172536. 300963. se2se0. 2267. 2448. 2129595. 2346884. 2129595. 2346884. 520.56 553.12 2513558. 27297563. 68354. 22398. 315. 315. 27504, 30290. 2417384, 2676561. 590.90 630.82 16.55 6.75 315609. 360282. 68354. 22398. 383963. 382680. 70.18 72.68 0.89 0.88 2.68 2.59 26.25 23.85 118.03 = 116.31 2.00 2.00 2.38 2.37 BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, DEVELOP COAL-FIRED GENERATION EXISTING ORGANIZATIONAL STRUCTURE PLAN: COAL.(8Z, LOYR) CONTRACT YEAR 1 EXPENSES: $1,000 PRODUCTION O&M-EXCL FUEL PRODUC TION-FUEL PURCHASED POWER TRANSMISSION 08M ADMIN & GENERAL-EXCL INSURANCE LONG-TERM LEASES HOMER XMSN LEASE PMT SUSITNA BARGE EXP 10 MATAN XMSN LEASE Prt 11 INSURANCE 12 DEPRECIATION 13. TAXES 14 INTEREST ON LONG-TERM DEBT 15. LESS: INTEREST CHARGED TO CONSTR 16 OTHER DEDUCTIONS 17 TOTAL POWER COST-ACCRUAL 18 LESS POWER SOLD 19 NET POWER COST-ACCRUAL 20 POWER COST-ACCRUAL (NILLS/KWH) 22 REVENUES: $1,000 23° REVENUES REQD TO MAINTAIN TIER 24 LESS’ NON-OPERATING INCOME 25° LESS: OTHER OPERATING REVENUES NSONBU DWH 2010 187712. 1677509. 117165. 22287. 52460. 133. 79. 1997. 59. 12294. 174385. 2644. 2629975. 2629975. 598. 40 3011224, 58368. 315. 26 LESS: PATRONAGE CAPITAL RETIREMENT 29869. 27 REVENUES FROM RATEPAYERS 28 WHOLESALE REVENUES, MILLS/KWH 29 ANNUAL INCREASE % 31 MARGINS: $1,000 32 OPERATING MARGINS 33 NON-OPERATING INCOME 34 NET PATRONAGE CAPITAL OR MARGINS 36 OPERATING RATIOS: % OF POWER COST 37 = PROD & PURCH POWER EXPENSE 38 TRANSMISSION EXPENSE 39 ADMIN & GENERAL EXPENSE 40 OTHER EXPENSES 41 OPERATING REVENUE 43 FIHANCIAL RATIOS: 44 TIrlES INTEREST EARNED RATIO (TIER) 45 DEBT SERVICE COVERAGE (DSC) 2922672. 665.00 5.42 322881. 58368. 381249. 75.38 0.85 2.46 21.31 114.50 2.00 2.37 2013 343269. 1986159. 95136. 28404. 96916. 133. 44. 2516. 12. 25287. 993678. 676688. 0. 33931. 3591578. 3591578. 734. 47 4268266. 166692. 315. 117937. 3983322. 814.59 13.79 509996. 166692. 676688. 67.51 0.79 3.40 28.30 118.84 2.00 2.42 TABLE 14 PROJECTED OPERATING RESULTS 2011 2012 202864. 219842. 1808634. 2059971. 207192. | 299372. 24171. 26206. 56657. 61189. 133. 133. 58. 52. 2157. 2329. 46. 13. 12366. 12444. 176223. 178381- 379654. 37876. 2856. 3084. 2073016. 32408%6. 2873016. 3240896. 631.29 ” 686.78 3252670. 3618772. 93879. 121294. 315. 315. 124311. 119065. 3034165, 3378098. 666.70 715.85 0.26 7.37 285775. 256583. 93879. 121294. 379654. 377876. 77.23 79.58 0.84 0-81 2.40 2.27 19.53 17.34 113-21 111.46 2.00 2.00 2.37 2.36 2014 372534. 2280143. 118950. 30778. 104669. 133. 44, 2717. 10. 25378. 336193. 0. 3749630. 779.48 4624110. 40144. 315. 117604, 4466047. 881.40 8.20 634336. 40144. 674480. 70.17 0.78 3.29 25.75 117.08 2.00 2.42 2015 PRESENT 404180. 2585701. 208829. 33342. 113043. 133. 0. 29734. 10. 25476. 338909. 4387828. 835.94 5057210. 101802. 315. 117214, 4837878. 922.06 4.61 567580. 101802. 671382. 72.90 0.76 3.16 23.18 115.30 2.00 2.36 VALUE (1783$) 4150604. PAGE: 183 DATE: 9-Mar-83 TIME: 14:48 FILES: CHN.D1 COAL.D2 VERSION: FIN. FORE. ene =m Hydroelectric Expansion Scenario Existing Arrangement a 10-Year Capital Credit Rotation -, . » - . - - ew Pane ee oe — me ea ao em wenn ey ieee BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 173 POWER SUPPLY PROGRAM DATE: 99-Mar-83 CHUGACH, HOMER & TIATANUSKA ELEC. ASSCCIATIONS TIME: 14:14 PROJECT: 82-113-4-000 FILES: CHM.01 BRADLEY LAKE & SUSITNA PROJECTS HYDRO. D2 EXISTING ORGANIZATIONAL STRUCTURE PLAN: HYDRO (8%, 10YR) VERSION: FIN. FORE. TABLE 14 PROJECTED OPERATING RESULTS CONTRACT YEAR 1983 1984 1985 1986 1987 1988 1989 1990 1991 1 EXPENSES: $1,000 2 PRODUCTIGN O&M-EXCL FUEL 5303. 3863. 6921. 7739. 8421. 8993. 9789. 10630. 11576. 3. PRODUCTION-FUEI_ 3126. 6146. 6517. 7631. 9012. 8195. 9644. 11364. 62604, 4 PURCHASED POWER 12971. 1252. 2029. 2220. 2308. 28146. 28477. 28710. 29003. 3 TRANSMISSION Oar 881. 1067. 2060. 2290. 2540. 3602. 39709. 4241. 4599. 6 ADMIN & GENERAL-EXCL INSURANCE 1676. 1849. 2222. 2483. 2682. 2897. 3129. 3378. 3649. 7 LOWG-TERM LEASES 133. 133. 133. 133. 133. 133. 133. 133. 133. 8 HOMER XMSN LEASE PrT 336. 385. 377. 370. 367. 359. 349. 341. 335. 9 SUSITNA BARGE EXP 700. 720. 742. 440. 465. 492. 322. 3533. 388. 10 MATAN XrSN LEASE PMT 149. 178. 175. 172. 170. 167. 164. 161. 158. 11. INSURANCE 21. 46. 198. 241. 252. 343. 356. 370. 385. 12 DEPRECIATION 7773. 8333. 11574. 12265. 12580. 15101. 15468. 15618. 16047. 13° TAXES 4. 4. 4. 4. 4. 4. 4. 4. 4. 14 INTEREST ON LONG-TERM DEBT 21302. 24441. 30199. 30098. 27984. 30083. 29476. 29298. 25908. 15 LESS: INTEREST CHARGED TO CONSTR 0. 0. 0. 0. 0. 0. 0. 0. 0. 16 OFHER DEDUCTIONS 741. 580. 609. 640. 324. 486. 325. 367. 613. 17 TOTAL POWER COST-ACCRUAL 45437. 50996. 63760. 66727. 67441. 997002. 101945. 105368. 155602. 18 LESS POWER SOLD 0. 0. 0. 0. 0. 0. 0. 0. 0. 19 NET POWER COST-ACCRUAL 43437. 50996. 63760. 66727. 67441. 97002. 101945. 105368. 155602. a POWER COST-ACCRUAL (MILLS/KWH) 27.08 29.29 35.42 35.72 34.84 49.40 30.79 49.82 69.48 22 REVENUES: $1,000 23 REVENUES REQD TO MAINTAIN TIER 49633. 73437. 93959. 96825. 95424. 127085. 131421. 134666. 181510. 24 LESS: NON-OPERATING INCOME 320. 1829. 3644. 2397. 4596. 3093. 2681. 4540. 4255. 25 LESS: OTHER OPERATING REVENUES 315. 315. 315. 315. = 315. 315. — ~ 26 LESS: PATRONAGE CAPITAL RETIREMENT 0. 0. 0. 0. 0. 0. 27 REVENUES FROM RATEPAYERS 47998. 73293. 90000. 94113. 90513, 123677. 128426. 129011. 176940; 28 WHOLESALE REVENUES, MILLS/KWH 28.60 42.10 50.00 30.38 46.75 61.72 63.99 61.38 79.24 = AWNUAL INCREASE % 0.00 47.18 18.77 0.76 -7.20 32.00 3.68 4.08 27.10 31 MARGINS: $1,000 32 OPERATING MARGINS 2876. 22612. 26556. 27701. 23387. 24991. 26796. 24758. 21653. 33 WON-OPERATING INCOrE 320. 1829. 3644. 2397. 4576. 3093. 2681. 4540. 4255. a NET PATRONAGE CAPITAL OR MARGINS 3195. 24441. 30199. 30098. 27984. 30083. 29476. 297298. 25908. 5 36 OPERATING RATIOS: X OF POWER COST 37 PROD & PURCH POWER EXPENSE 25.79 26.00 24.26 26.36 29.27 45.79 47.00 48.12 46.31 38 TRANSMISSION EXPENSE 1.94 2.09 3.23 3.43 3.77 3.64 3.83 4.02 2.96 39 ADMIN & GENERAL EXPENSE 3.73 3.72 3.80 4.08 4.35 3.27 3. 42 3.56 2.59 40 OTHER EXPENSES 68.53 68.19 68.72 66.12 62.61 47.30 45.75 44.30 28.14 = OPERATING REVENUE 107.03 147.93 147.36 145.11 141.49 130.39 128.91 127.81 116.65 43 FINANCIAL RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 1.15 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 45 DEBT SERVICE COVERAGE (DSC) 1.33 2.08 2.16 2.17 2.18 2.23 2.24 2.23 2.26 CHUGACH, HOrER & MATANUSKA ELEC. PROJECT: 82-113-4-000 BRADLEY LAKE & SUSITNA PROJECTS EXISTING ORGANIZATIONAL STRUCTURE PLAN: HYDRO (8%, 1OYR) CONTRACT YEAR 1 EXPENSES: $1,000 PRODUCTION O&M-EXCL FUEL PRODUCT IGN-FUEL PURCHASED POWER TRANSMISSION O&M ADMIN & GENERAL-EXCL INSURANCE LONG-TERM LEASES HOMER XMSN LEASE PNT SUSITNA BARGE EXP 10 = MATAN XMSN LEASE PNT 11 INSURANCE 12 DEPRECIATION 13. TAXES 14 INTEREST ON LONG-TERM DEBT 15 LESS: INTEREST CHARGED TO CONSTR 16 OTHER DEDUCTIONS 17. TOTAL POWER COST-ACCRUAL 18 LESS POWER SOLD 19 NET POWER COST-ACCRUAL 20 POWER COST-ACCRUAL (MILLS/KWH) 22 REVENUES: $1,000 23> REVEHUES RE@D TO MAINTAIN TIER SCONAUM BWM 24 LESS: NOH-GPERATING INCOME 25° LESS: OTHER OPERATING REVENUES 26 LESS: PATRONAGE CAPITAL RETIREMENT 27 REVENUES FROM RATEPAYERS 28 WHOLESALE REVENUES, MILLS/KWH 2? ANNUAL INCREASE % 31 MARGINS: $1,000 32 OPERATING MARGINS 33 NON-OPERATING INCOME = NET PATRONACE CAPITAL OR MARGINS 36 OPERATING RATIOS: % OF POWER COST 37 PROD & PURCH POWER EXPENSE 38 = TRANSMISSION EXPENSE 39 = ADIITH 2 GENERAL EXPENSE 40 OTHER EXPENSES i OPERATING REVEHUE 43 FINANCIA! RATIOS: 44 TIHES INTEREST EARNED RATIO (TIER) 45 DERT SERVICE COVERAGE (DSC) BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAN ASSOCIATIONS 1992 12569. 73447. 297501. 49785. 3940. 133. 329. 625. 155. 401. 164509. 187456. 3095. 315. 0. 184046. 79.60 0.46 18002. 3095. 21097. 70.64 3.00 2.61 23.75 112. 68 2.00 2.29 1995 13917. 43964. 430205. 6342. 4964. 133. 278. 7353. 145. 459. 18131. 4. 20335. 0. 834. or 340466. 209.97 560801. 4463. 315. 30199. 325823. 204. 28 1.640 15871. 4463. 20335. 90.31 1.17 1.00 7.51 103.76 2.00 2.29 TABLE 14 PROJECTED OPERATING RESULTS 1993 1994 12442. 12738. 32102. 17063. 294629. 428587. 3404. 3855. 4255. 4596. 133. 133. 320. 313. 645. 708. 151. 148. 419. 438. 17009. 17548. 4. 4. 20864. 20612. 0. 0. 715. 772. 3891 ie aaa: 389113. 509516. 162.27 204.87 409977. 5330128. 4398. 3340. 315. 315. 3195. 24441. 402068. 500033. 167.67 201.06 110.43 19.91 164466. 15272. 4378. 3340. 20864. 20612. 87.17 89.97 1.39 1.15 1.20 0.99 10.24 7.90 105.36 104.05 2.00 2.00 2.29 2.30 1996 15197. 797125. 431750. 6868. 5361. 133. 269. 805. 142. 482. 18761. 4. 22545. 0. 900. “ae 382342. 218.35 604887. 3097. 315. 30098. 371376. 214.24 4.87 19447. 3097. 22545. 90.34 1.18 1.00 7.48 103.87 2.00 2.26 1997 16561. 158614. 433441. 7454. 3790. 133. 262. 8597. 137. 507. 19442. 4. 24930. 0. 972. aon 667125. 242.09 674055. 3648. 315. 27984. 662108. 239.55 11.81 21282. 3648. 24930. 90.96 1.11 0.94 6.99 103.73 2.00 2.24 PAGE: 174 DATE: 9-Har-83 TIME: 14:14 FILES: CHN.D1 HYDRO. D2 VERSION: FIN. FORE. 1998 1999 2000 18123. 19649. 21522. 198699. 221031. 273175. 4335465. 437405. 439540. 8108. 8834. 9643. 6254. 6754. 7294. 133. 133. 133. 254. 237. 228. 918. 981. 925. 131. 127. 122. 333. 542. 373. al ae sear 27504. 30290. 29849. 0. 0. 0. 1050. 1134. 1225. 7 alas 7481 1}. ee 717353. 748112. 8060979. 250.30 232.06 262.06 744858. 778401. 9835768. 4607. 3668. 6924. 315. 315. 315. 30083. 29476. 29298. 709852. 742742. 7997431. 247.68 250.32 259.89 3.40 1.06 3.83 22898. 24622. 22945. 4607. 3668. 6724. 27504. 30290. 29869. 90.93 90.64 91.09 1.13 1.18 1.20 0.95 0.98 0.98 6.99 7.20 6.74 103.83 104.05 103.71 2.00 2.00 2.00 2.24 2.24 2.24 - om ~——— me oe BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOPER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82~-113-4-000 BRADLEY LAKE & SUSITNA PROJECTS EXISTING GRGANIZATIONAL STRUCTURE PLAN: HYDRO (8%, 1OYR) TABLE 14 PROJECTED OPERATING RESULTS CONTRACT YEAR 2001 2002 2003 2004 2005 1 EXPENSES: $1,000 2 PRODUCTION O&M-EXCL FUEL 23559. 22535. 24476. 266464. 29507. 3 PRODUCTION-FUEL. 331478. 39912. 67009. 80078. 173787. 4 PURCHASED POWER 442024. 724472. 728987. 733193. 737539. 3 TRANSMISSION Oar 10515. 11458. 12475. 13607. 14828. 6 ADMIN & GENERAL-EXCL INSURANCE 7877. 8507. 9188. 9923. 10717. 7 LONG-TERM LEASES 133. 133. 133. 133. 133. 8 HONER XMSN LEASE Prt 219. 211. 202. 195. 115. 9 SUSITNA BARGE EXP 999. 1079. 1145. 1258. 1359. 10 =MATAN XMSN LEASE PrT 118. 113. 107. 100. 94. 11. INSURANCE 426. 662. 702. 744. 789. 12 DEPRECIATION 22752. 23750. 24830. 25995. 27255. 13 TAXES 4. 4. 4. 4. 4. 14 INTEREST ON LONG-TERM DEBT 29410. 28914. 32688. 32071. 36411. 15. LESS: INTEREST CHARGED TO CONSTR 0. 0. 0. 0. 0. 16 OTHER DEDUCTIONS 1323. 1428. 1543. 1466. 1799. 17 TOTAL POWER COST-ACCRUAL 871057. 863179. 703509. 925631. 1034338. 18 LESS POWER SOLD 0. 0. 0. 0. 0. 19 NET POWER COST-ACCRUAL 871057. 863179. 903509. 925631. 1034338. = POWER CGST-ACCRUAL (MILLS/KWH) 273.23 261.17 263.72 260.81 281.38 22 REVENUES: $1, 000 23° REVENUES REQO TO MAINTAIN TIER 900467. 892073. 936197. 957702. 1070749. 24 LESS: WNON-OPERATING INCOME 5715. 4607. 3853. 6188. 5344. 25 LESS: OTHER OPERATING REVENUES 315. 315. 315. 315. 315. 26 LESS: PATRONAGE CAPITAL RETIREMENT 25908. 21097. 208464. 20612. 20335. 27 REVENUES FROM RATEPAYERS 868528. 866074. 9711164. 930586. 1044755. 28) WHOLESALE REVENUES, MILLS/KWH 272.44 262.05 245.96 262.21 284.21 z ANHUAL IHCREASE % 4.83 -3.81 1.49 71.41 8.39 31 MARGIHS: $1,000 32 OPERATING MARGINS 23495. 24307. 28834. 25882. 31067. 33 4 NON-OPERATING INCOME 5715. 4607. 3853. 6188. 3344. = NET PATRONAGE CAPITAL OR MARGINS 29410. 28914, 32688. 32071. 36411. 36 OPERATING RATIOS: % OF POUER COST 37 = =PROD & PURCH POWER EXPENSE 91.51 91.17 90.81 90.74 90.96 38 = TRANSMISSION EXPENGE 1.21 1.33 1.38 1.47 1.43 3? «ADMIN & GEHERAL EXPENSE 0.98 1.06 1.09 1.15 1.11 40 OTHER EXPENSES 6.31 6.45 6.72 6.64 6.49 E OPERATING REVENUE 103. 38 103.35 103.62 103. 46 103.52 43 FINANCIAL RATIOS 44 TIMES INTEREST EARNEN RATIO (TIER? 2.00 2.00 2.00 2.00 2.00 45 DEBT SERVICE COVERAGE (DSC) 2.26 2.29 2.25 2.24 2.22 2006 32802. 307022. 742189. 16184. 11575. 133. 109. 1468. 88. 838. — 35627. 0. 1943. Ti) 1178596. 309.18 1214223. 8108. 315. 22545. 1183254. 310. 40 9.22 27520. 8108. 35627. 971.81 1.37 1.05 3.77 103.02 2.00 2.22 sy pea peg 24930. 1271867. 322.07 3.76 28020. 6730. 34750. 92.13 1.39 1.06 3.42 102.74 2.00 2.22 eee iis PAGE: 175 DATE: 9-Mar-83 TIME: 14:14 FILES: CHM.D1 HYDRO. 02 VERSION: FIN. FORE. 2008 2009 38539. 42593. 375202. 3397377. 732886. 738724. 19228. 20783. 13500. 14380. 133. 133. 93. 85. 1712. 1849. 76. 67. 949. 1011. 31668. 33380. 40129. 39049. 0. o. 2267. 2448. 1276387. 1454903. 1276387. 1454303. 312.00 342.75 1316516. 1493373. 3089. 7784. 315. 315. 27504. 30290. 1283608. 1454984, 313.76 342. 91 -2.58 9.29 33040. 31285. 3087. 7784. 40129. 39069. 971.40 92.19 1.51 1.44 1.13 1.07 3.96 5.30 103.14 102.69 2.00 2.00 2.19 2.23 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 176 PQWER SUPPLY PROGRAM DATE: 9-Mar-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSCCIATIONS TIME: 14:14 PROJECT: 82-113-4-000 ‘FILES: CHM.01 BRADLEY LAKE & SUSITNA PROJECTS HYDRO. D2 EXISTING ORGANIZATIONAL STRUCTURE PLAN: HYDRO (8%, 10YR) VERSION: FIN. FORE. TABLE 14 PROJECTED OPERATING RESULTS CONTRACT YEAR 2010 2011 2012 2013 2014 2015 ee 1 EXPENSES: $1,000 (19838) 2 PRODUCTION O&H-EXCL FUEL 46534. 50968. 56585. 61252. 67292. 74667. 3 = PRODUCTION-FUEL. 622725. 765482. 1027395. 1118677. 1413644. 1827319. 4 PURCHASED POWER 765347. 772157. 779551. 787835. 796442. 805729. S TRANSMLSSION 02M 22877. 24977. 27244, 29755. 32467. 33471. 6& ADMIN & GENERAL-EXCL INSURANCE 15747. 17006. 18347. 19836. 21423. 23137. 7 LONG-TERM LEASES 133. 133. 133. 133. 133. 133. 8 HOMER XMSN LEASE PNT 79. 58. 52. 44. 44. 0. 9 SUSITNA BARGE EXP 1997. 2157. 2329, 2516. 2717. 2934. 10 MATAM XMSN LEASE PHT 59. 46. 13. 12. 10. 10. 11) THSURANCE 1078. 1150. 1229. 1313. 1404. 1502. 12 DEPRECTATION 35230. 37070. 39229. 36514. 39032. 41748. 13. TAXES 4. 4. 4. 4. 4. 4. 14 INTEREST ON LONG-TERM DEBT 45337. 44063. 51313. 49791. 58179. 54288. 15. LESS: INTEREST CHARGED TO CONSTR 0. 0. 0. 0. 0. 0. 16 OFHER DEDUCTIONS 2644. 2856. 3084. 3331. 3597. 3885. 17 TOTAL PCWER COST-ACCRUAL 1559791. 1718127. 2008528. 2111013. 24346389. 2874828. 18 LESS POWER SOLD 0. 0. 0. 0. 0. 0. 19 = NET POWER COST-ACCRUAL 1559791. 1718127. 2008528. 2111013. 2436389. 2874828. 2 POWER COST-ACCRUAL (MILLS/KWH) 354.90 377.53 425.63 431.70 480.83 547.49 22 REVENUES: $1,000 23 REVENUES REQD TO MAINTAIN TIER 1605129. 1762190. 2059841. 2160804. 2474568. 2731114. 24 LESS: WNON-OPERATING INCOME 5582. 8676. 6347. 10020. 6785. 10727. 25 LESS: OTHER OPERATING REVENUES 315. 315. 315. 315. 315. 315. 26 LESS: PATRONAGE CAPITAL RETIRENEHT 29859. 29410. 28914, 32688. 32071. 36411. 27 REVENUES FROM RATEPAYERS 1569363. 1723788. 2024265. 2117782. 2455397. 2883663. 3376370. 28 WHOLESALE REVENUES, MILLS/KWH 357.08 378.77 428.96 433.08 484.59 349.37 z ANNUAL INCREASE % 4.13 © 6.07 13.25 0.96 11.89 13.37 31 MARGINS: $1,000 32 OPERATIHG MARGINS 39755. 35387. 44965. 39771. 51394. 455461. 33 NON-OPERATING INCORE 5582. 8476. 6347. 10020. 6785. 10727. a NET PATRONAGE CAPITAL OR MARGINS 45337. 44063. 31313. 49791. 58179. 56288. 36 OPERATING RATICS: % OF POWER COST 37 = PROD & PURCH POWER EXPENSE 91.97 92.46 92.88 93.21 93.47 94.26 38 =TRANSMISSIUN EXPENSE 1.47 1.45 1.36 1.41 1.33 1.23 39 = ADMIN & GENERAL EXPENSE 1.08 1.06 0.98 1.00 0.94 0.86 40 OTHER EXPENSES 5.48 5.03 4.79 4.37 4.26 3.465 m4 OPERATING REVENUE 102.91 102.56 102.55 102.36 102.39 101.96 43 FINANCIAL. RATIOS: 44 TIES INTEREST EARNED RATIO (TIER) 2.00 2.00 2.00 2.00 2.00 2.00 45 DEBT SERVICE COVERAGE (DSC) 2.20 2.21 2.20 2.13 2.11 2.10 oo Gas-Fired Expansion Scenario G&T Cooperative 10-Year Capital Credit Rotation BURNS & NCDONNELL ENGINEERING COMPAHY PAGE: 188 POWER SUPPLY PROGRAM DATE: 21-Mar-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 07:42 PROJECT: 82-113-4-000 FILES: CHNGT.Di BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, LOYR) VERSION: FIN. FORE. TABLE 14 PROJECTED OPERATING RESULTS CONTRACT YEAR 1983 1984 1985 1986 1987 1988 1989 1990 1991 1 EXPENSES: $1,000 2 PRODUCTION O&M-EXCL FUEL 3303. 3863. 6721. 7739. 8421. 8993. 9789. 10630. 11576. 3 PRODUCTIGN-FUEL 3126. 6146. 6517. 7631. 9012. 8195. 9644. 11364. 62604, 4 PURCHASED POWER 1291. 1252. 2029. 2220. 2308. 28146. 28477. 28710. 29003. 5 TRANSMISSION Oan 881. 1067. 2060. 2321. 2604, 3702. 4065. 4437. 4881. 6 ADMIN & GENERAL-EXCL INSURANCE 1676. 1849. 2222. 2483. 2682. 2697. 3129. 3378. 3649. 7 LONG-TERM LEASES 133. 133. 133. 133. 133. 133. 133. 133. 133. 8 ADDITIONAL G&T STAFF 0. 340. 770. 1097. 1563. 2227. 3174, 3428. 3702. 9 SUSITNA BARGE EXP 700. 720. 742. 440. 465. 492. 522. 353. 588. 10 G & T ORGANIZATION 200. 200. 150. 0. 0. 0. 0. 0. 0. 11 INSURANCE 21. 46. 198. 241. 252. 344, 357. 371. 386. 12 DEPRECIATION 7935. 8494. 11736. 12427. 12742. 15263. 15630. 15781. 16209. 13. TAXES 4. 4. 4. 4. 4. 4. 4. 4. 4. 14 INTEREST GN LONG-TERM DEBT 21537. 24670. 36414. 36306. 36180. 40614. 40430. 40218. 39970. 15 LESS: INTEREST CHARGED TO CONSTR 0. 0. 0. 0. 0. 0. 0. 0. 0. 16 OTHER DEDUCTIONS 741. 380. 609. 640. 324. 486. 525. 367. 613. 17 TOTAL PGWER COST-ACCRUAL 43547. 31563. 70504. 73684. 76887. 111497. 115880. 119593. 173318. 18 LESS POWER SOLD 0. 0. 0. 0. 0. 0. 0. 0. 0. 19 =NET POWER COST-ACCRUAL 43547. 31543. 70504, 73684, 76889. 111497. 115880. 119593. 173318. +t POWER COST-ACCRUAL (HILLS/KWH) 27.14 29.62 39.17 39.45 39.72 35.64 37.74 36.55 77.62 22 REVENUES: $1,000 23 REVENUES REGD TO MAINTAIN TIER 48778. 36497. 77787. 80945. 84125. 1197620. 123766. 127637. 181312. 24 LESS: NON-GPERATING INCOME 320. 1049. 1165. 2442. 2887. 3385. 930. 1407. 1790. 25 LESS: OTHER OPERATING REVENUES 315. 315. 315. 315. 315. 315. 315. 315. 315. 26 LESS: PATRCNAGE CAPITAL RETIREMENT 0. 0. 0. 0. 0. 0. 0. oo. | 0. 27 REVENUES FROM RATEPAYERS 43142. 53133. 76307. 78187. 80923. 115920. 122720. 125914. 179207. 28 WHOLESALE REVEHUES, MILLS/KWH 28.69 31.67 42.39 41.86 41.80 37.84 61.15 39.53 80. 25 2 ANNUAL INCREASE % 0.00 10.38 33.87 -1.27 0.14 38.37 3.71 2.64 34.80 31 MARGINS: $1,000 32 OPERATING MARGINS 2910. 38385. 6118. 4819. 4349. 4738. 7136. 6636. 6204. 33 NOM-OPERATING INCOME 320. 1049. 1165. 2442. 2887. 3385. 930. 1407. 1790. = NET PATRGNAGE CAPITAL OR MARGINS 3231. 4934. 7283. 7261. 7236. 8123. 8086. 8044. 7994, 36 OPERATING RATIGS: % OF POWER COST 37 =PROD & PURCH POWER EXPENSE 25.73 25.72 21.94 23.87 25.67 40.66 41.34 42.40 39.53 33 = TRAHSrIISSIOH EXPENSE. 1.93 2.07 2.92 3.15 3.39 3.32 3.51 3.73 2.82 39 «ADMIN & GErERAL EXPENSE 3.73 3.68 3.43 3.70 3.82 2.91 3.01 3.13 2.33 40 OTHER EXPENSES 68.61 68.54 71.71 69.28 67.12 33.11 32.14 30.74 35.32 i OPERATING REVENUE 107.09 109.57 110.33 109.85 109. 41 107.2? 106.98 106.73 104. 61 43 FINANCIAL RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 1.15 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 45 DEBT SERVICE COVERAGE (DSC) 1.32 1.37 1.40 1.41 1.40 1.43 1.43 1.43 1.43 BURNS & MCDONHELL ENGINEERING COMPANY POWER SUPPLY PROGRAN CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, GAS-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: GAS(8%, LOYR) CONTRACT YEAR 1 EXPENSES: $1,000 2 PRODUCTION O&N-EXCL FUEL 3 PRODUCTICN-FUEL 4 PURCHASED POWER S TRANSMISSION 08" 6& ADMIN & GEHERAL-EXCL INSURANCE 7 LONG-TERM LEASES 8 ADDITIONAL G&T STAFF 9 SUSITNA BARGE EXP 10 G & T ORGANIZATION 11 INSURANCE 12. DEPRECIATION 13. TAXES 14 INTEREST OH LONG-TERM DEBT 15 LESS: INTEREST CHARGED TO CONSTR 16 OTHER DEDUCTIOHS 17 TOTAL POWER COST-ACCRUAL 18 LESS POWER SOLD 19 =NET POWER COST-ACCRUAL 20 POWER COST-ACCRUAL (NILLS/KWH) 22 REVENUES: $1,000 23 REVENUES REQD TO MAINTAIN TIER 24 LESS: HON-CPERATING INCOME 25 LESS: OTHER OPERATING REVENUES 26 LESS: PATRONAGE CAPITAL RETIREMENT 27 REVENUES FROM RATEPAYERS 28 WHOLESALE REVENUES, MILLS/KWH 2? = AHNUAL INCREASE % 31 MARGINS: $1,000 32 OPERATING MARGINS 33 NON-OPERATING INCOME 34 NET PATRGNAGE CAPITAL OR MARGINS 36 OPERATING RATIOS: % OF POWER COST 37 = PROD & PURCH POWER EXPENSE 38 TRANSMISSION EXPENSE 39 = ADMIN & GENERAL EXPENSE 40 OTHER EXPENSES 41 OPERATING REVEHUE 43 FINANCIAL RATICS: 44 TIMES INTEREST EARNED RATIO (TIER) 45 DEBT SERVICE COVERAGE (DSC) 1992 12549. 73447. 297501. 3338. 3940. 133. 3998. 625. 0. 402. 16672. 4. 39662. 0. 662. seeES 188953. 81.73 196885. 2055. 315. 0. 194515. 84.13 4.83 5878. 2055. 7932. 62.19 2.82 2.39 32.63 104.20 1995 16203. 217101. 31910. 6741. 4964. 133. 3037. 7355. 0. 460. seni a 40721. 0. 834. =". 343357. 133.39 351501. 1523. 315. 7283. 342380. 133.01 40.38 6621. 1523. 8144. 77.24 2.02 1.58 19.16 102.37 TABLE 14 PROJECTED OPERATING RESULTS 1993 1994 13703. 14875. 93670. 115312. 30105. 30677. 5832. 6366. 4255. 4596. 133. 133. 4318. 4664. 665. 708. 0. 0. 420. 439. 17171. 17711. 4. 4. 39277. 38857. Q. 0. 715. 772. an sas 212274. 9235115. 88.52 94.54 220127. 242886. 2199. 1982. 315. 315. 3231. 4934. 214365. 235655. 89.40 94.75 6.26 5.99 3657. 3790. 2199. 1982. 7855. 7771. 65.71 68. 42 2.75 2.71 2.20 2.14 29.34 26.73 103.70 103.31 1.20 1.20 1.41 1.41 1.20 1.39 1996 17657. 332995. 33640. 7580. 3361. 133. 3440. 805. 0. 483. = 42707. 0. 900. ar 966630. 174.96 475171. 2477. 315. 7261. 465118. 174. 40 31.11 6065. 2477. 8541. 82.35 1.462 1.25 14.77 101.83 1.20 1.38 972. 674628. 674628. 244.08 683053. 34532. 315. 7236. 672049. 243.14 39.42 4972. 3432. 8424, 87.53 1.23 0.93 10.31 101.25 1.20 1.38 PAGE: 189 DATE: 21-Mar-83 TIME: 07:42 FILES: CHMGT.D1 GASGT. D2 VERSION: FIN. FORE. 1998 1999 2000 20864. 22616. 24606. 615126. 676881. 757600. 39833. 47106. 73941. 9054. 97880. 10776. 6254. 6754. 7294. 133. 133. 133. 6345. 6852. 7401. 918. 981. 925. 0. 0. 0. 333. 362. 373. —_ — —_— 41477. 43952. 43184. 0. 0. 0. 1050. 1134. 1225. 761730. 839987. 951690. 761930. 839987. 951690. 265.85 283.01 309.39 770225. 848777. 60327. 2460. 1286. 2292. 315. 315. 315. 8123. 8086. 8044. 759328. 837090. 97497676. 264.94 282.71 308.74 8.97 6.71 9.21 3836. 73504. 6345. 2460. 1286. 2292. 8295. 8790. 8637. 88.70 89.12 90.17 1.19 1.18 1.13 0.89 0.87 0.83 9.22 8.83 7.87 101.09 101.05 100.91 1.20 1.20 1.20 1.39 1.39 1.39 7 es’ FS Fre rt ro Ts PR FA Oe ese BURNS & MCDOHNELL ENGINEERING COMPANY PAGE: 190 POWER SUPPLY PROGRAM DATE: 21-Mar-83 CHUGACH, HOrER & MATANUSKA ELEC. ASSOCIATIONS TIME: 07:42 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: GAS(B%, 1OYR) VERSION: FIN. FORE. TABLE 14 PROJECTED OPERATING RESULTS CONTRACT YEAR 2001 2002 2003 2004 2005 2006 2007 2008 2009 1 EXPENSES: $1,000 2 = PRODUCTIOH O&-EXCL FUEL 34895. 37967. 41147. 44707. 498694. 32778. 37381. 90121. 97878. 3 PRODUCTION-FUEL 797893. 908485. 1000185. 1117271. 1292021. 1396247. 1617422. 1648459. 18546777. 4 PURCHASED PGUER 40318. 44322. 64475. 95350. 89409. 194421. 149991. 39140. 72069. 3 TRANSMISSIOH O&M 11784, 12879. 14061. 15339. 16718. 18208. 19816. 21553. 23430. 6 ADMIN & GEHERAL-EXCL INSURANCE 10354. 11183. 12078. 13044. 14088. 15215. 16432. 26238. 28337. 7 LONG-TERM LEASES 133. 133. 133. 133. 133. 133. 133. 133. 133. 8 ADDITIONAL G&T STAFF 7993. 8632. 9323. 10068. 10874. 11744, 12683. 13698. 14794, 9 SUSITNA BARGE EXP 999. 1079. 1165. 1258. 1359. 1468. 1585. 1712. 1849. 10 = G & T ORGANIZATION 0. 0. 0. 0. 0. 0. 0. 0. 0. 11 THSURANCE 1880. 1916. 1955. 1997. 2042. 20971. 2144. 6499. 6561. 12 DEPRECIATIOH 37974, 38973. 40052. 41217. 42475. 43834, 45301. 98507. 100218. 13. TAXES 4. 4. 4. 4. 4. 4. 4. 4. 4. 14 INTEREST GH LOWG-TERM DEBT 101207. 100273. 99229. 98063. 96770. 95331. 93722. 280881. 278507. 15 LESS: INTEREST CHARGED TO CONSTR 0. 0. 0. 0. 0. 0. 0. 0. 0. 16 OTHER DEDUCTIONS 1323. 1428. 1543. 1644. 1799. 1943. 2099. 2267. 2448. 17 TOTAI. PGWER CGST-ACCRUAL 1048958. 1167275. 1285350. 1440117. 1616385. 1833418. 2018713. 2247233. 2483006. 18 LESS POWER SOLD 0. 0. 0. 0. 0. 0. 0. 0. 0. 19 NET POWER COST-ACCRUAL 10489758. 1167275. 1285350. 1440117. 1616385. 1833418. 2018713. 2247233. 2483006. e POWER COST-ACCRUAL (NILLS/KWH) 329.03 353.18 375.18 405.78 439.71 480.96 311.20 349. 80 385.20 22 REVENUES: $1,000 23 REVENUES RE@D TO MAINTAIN TIER 10671997. 1187327. 13051976. 14597730. 1635739. 1852485. 2037438. 2305407. 2538707. 24 LESS: WON-GPERATING INCOME 1889. 3071. 3348. 3385. 3170. 4640. 3763. 3992. 11305. 23 LESS: OTHER OPERATING REVENUES 315. 315. 315. 315. 315. 315. 315. 315. 315. 26 LESS: PATRONAGE CAPITAL RETIREMENT 7994. 7932. 7855. 7771. 8144, 8541. 8424, 8295. 8790. 27 REVENUES FROM RATEPAYERS 1057001. 1174011. 12971677. 1446258. 1622110. 1838988. 2024955. 2290807. 25182976. 28 WHOLESALE REVENUES, MILLS/KWH 332.18 355.22 377.02 _. 407.51 441.27 482. 42 312.78 359.96 593.52 2 ANNUAL INCREASE % 7.59 6.94 6.14 8.07 8.28 9.33 6.29 9.20 3.99 31 MARGINS: $1,000 32 OPERATING MARGINS 18352. 14984, 14498. 14228. 14184. 14427. 14981. 30185. 44396. 33 NON-OPERATING INCOME 1889. 3071. 3348. 3385. 3170. 4640. 3763. 3992. 11305. = NET PATROWAGE CAPITAL OR MARGIHS 20241. 20055. 19846. 19613. 19354. 19066. 18744, 36176. 35701. 36 OPERATING RATIOS: % GF POWER COST 37 PROD & PLIRCH POWER EXPEHSE 83. 45 84.88 86.03 87.31 88. 48 89.64 90.39 79.93 81.62 33 = TRANSMISSIOH EXPENSE 1.12 1.10 1.09 1.07 1.03 0.99 0.98 0.96 0.94 39 ADMIN & GENERAL EXPENSE 1.17 1.12 1.09 1.04 1.00 0.94 0.92 1.46 1.41 40 OTHER EXPErSES 14.26 12.90 11.78 10.58 9.49 8.42 7.70 17.466 16.03 - OPERATING REVENUE 101.93 101.72 101.54 101.36 101.20 101.04 100.93 102.50 102.24 43 FINANCIAL RATICS: 44 TIMES INTEREST EARNED RATIO (TIER) 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 45 DEBT SERVICE COVERAGE (DSC) 1.43 1.43 1.43 1.43 1.43 1.42 1.42 1.44 1.44 BURNS & MCDONHELL ENGINEERING COMPANY PAGE: 191 POWER SUPPLY PROGRAM DATE: 21-Mar-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 07:42 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, GAS-FIRED GENERATION GASGT. D2 GENERATIGN AND TRANSMISSION COOP. PLAH: GAS(8%, LOTR) VERSION: FIN. FORE. TABLE 14 PROJECTED OPERATING RESULTS CONTRACT YEAR 2010 2011 2012 2013 2014 2015 ate 1 EXPENSES: $1,000 (1983$) 2 PRODUCTION O&M-EXCL FUEL 106422. 115104. 125071. 175334. 190605. 207179. 3 PRODUCTION-FUEL 2110536. 2276932. 2561874. 2798271. 3148837. 3523752. 4 PURCHASED PCWER 99312. 175636. 254049. 76045. 93440. 163910. 5 TRANSITISSION O&M 25436. 27645. 30009. 32561. 35318. 38297. 6 ADMIN & GEHERAL-EXCL INSURANCE 30605. 33053. 35697. 31031. 35113. 39522. 7 LONG-TERT LEASES 133. 133. 133. 133. 133. 133. 8 ADDITIONAL G&T STAFF 15977. 17256. 18636. 20127. 21737. 23476. 9 SUSITNA BARGE EXP 1997. 2157. 2329. 2516. 2717. 29734. 10 =G & T ORGANIZATION 0. 0. 0. 0. 0. 0. 11 INSURANCE 6628. 6700. 6778. 13176. 13267. 13365. 12 DEPRECIATIOH 102067. 103907. 106063. 179196. 181711. 184428. 13. TAXES 4. 4. 4. 4. 4. 4. 14 INTEREST OH LOHG-TERNM DEBT 275914. = =273028. 269853. 544195. 540550. 536476. 15 LESS: INTEREST CHARGED TO CONSTR 0. Oo. 0. 0. 0. 0. 16 OTHER DEDUCTIONS 2644, 2856. 3084. 3331. 3597. 3885. 17 TOTAL PGWER COST-ACCRUAL 2777674. 3039410. 3413600. 3895921. 4287030. 47573640. 18 LESS POWER SOLD 0. 0. 0. 0. 0. 0. 19 =NET POWER COST-ACCRUAL 2777694. 3034410. 3413600. 38975921. 4287030. 4757360. = POWER COST-ACCRUAL (MILLS/KWH) 632.01 666.76 723.37 796.71 846.07 906.34 22 REVENUES: $1,000 23 REVENUES REQOD TO MAINTAIN TIER 2832877. 3089016. 3467571. 4004760. 4395140. 4864655. 24 LESS: HON-CPERATING INCOME 16173. 20579. 23571. 31143. 43373. 34844. 25. LESS: OTHER OPERATING REVENUES 315. 315. 315. 315. 315. 315. 26 LESS: PATRONAGE CAPITAL RETIREFENT 8637. 20241. 20055. 19846. 19613. 19354. 27 REVENUES FROM RATEPAYERS 2807752. 3047880. 3423630. 3953455. 4331839. 4790142. 4107924. 28 WHOLESALE REVENUES, HMILLS/KWH 638. 85 469.72 725.50 808. 438 854.91 912.58 z ANNUAL INCREASE % 7.64 4.83 8.33 11.44 3.74 6.75 31 MARGINS: $1,000 32 OPERATING MARGINS 37010. 340264. 30399. 77695. 64738. 32451. 33 =NON-OPERATING INCOME 16173. 20579. 23571. 31143. 43373. 34844, 4 NET PATRONAGE CAPITAL OR MARGINS 55183. 34606. 53971. 108837. 108110. 107295. 34 OPERATING RATIOS: % OF POWER COST 37 = PROD & PURCH POWER EXPENSE 83.37 84.62 86.16 78.28 80.08 81.87 38 TRANSMISSION EXPENSE 0.92 0.91 0.88 0.84 0.82 0.80 39 = ADMIH & GEHERAL EXPENSE 1.34 1.31 1.24 1.45 1.40 1.53 40 OTHER EXPENSES 14.35 13.16 11.72 19.24 17.51 15.79 2 OPERATING REVEHUE 101.97 101.80 101.58 102.79 102.52 102.26 43 FINANCIAL RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 1.20 1.20 1.20 1.20 1.20 1.20 45 DEBT SERVICE COVERAGE (DSC) 1.44 1.43 1.43 1.44 1.45 1.43 er et — ~ - _ ores — ad a - ” - - ~- - . ” ey 4 eo pews oe i Coal-Fired Expansion Scenario G&T Cooperative 10-Year Capital Credit Rotation BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 188 POWER SUPPLY PROGRAM DATE: 8-Mar-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 18:27 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, DEVELOP COAL-FIRED GENERATION COALGT. D2 ae car AND TRANSMISSION — PLAN: VERSION: FIN. FORE. TABLE 14 PROJECTED OPERATING RESULTS CONTRACT YEAR 1983 1984 1985 1986 1987 1988 1989 1990 1991 1 EXPENSES: $1,000 2 PRODUCTION O&M-EXCL FUEL 3303. 3863. 6921. 7739. 8421. 8993. 9789. 10630. 11576. 3 = PRODUCTION-FUEL 5126. 6146. 6517. 7631. 9012. 8195. 9644, 11364. 62604. 4 PURCHASED POWER 1291. 1252. 2029. 2220. 2308. 28144. 28477. 28710. 29003. 3 TRANSMISSION O&n 881. 1067. 2060. 2321. 2604. 3702. 4065. 4457. 4881. & ADMIN & GENERAL-EXCL INSURANCE 1676. 1849. 2222. 2483. 2682. 2897. 3129. 3378. 3649. 7 LONG-TERM LEASES 133. 133. 133. 133. 133. 133. 133. 133. 133. 8 ADDITIONAL G&T STAFF 0. 540. 770. 1097. 1563. 2227. 3174. 3428. 3702. 9 SUSITNA BARGE EXP 700. 720. 742. 440. 465. 492. 522. 553. 588. 10 G & T ORGANIZATION 200. 200. 150. 0. 0. 0. 0. 0. 0. 11 INSURANCE 21. 46. 198. 241. 252. 344. 357. 371. 386. 12 DEPRECIATION 7935. 8494. 11736. 12427. 12742. 15263. 15630. 15781. 16209. 13. TAXES 4. 4. 4. 4. 4. 4. 4. 4. 4. 14 INTEREST ON LONG-TERM DEBT 21537. 24670. 36414, 36306. 36180. 40614. 40430. 40218. 39970. 15 LESS: INTEREST CHARGED TO CONSTR 0. 0. 0. 0. 0. 0. 0. 0. 0. 16 OTHER DEDUCTIONS 741. 580. 609. 640. 524. 486. 325. 367. 613. 17 TOTAL POWER COST-ACCRUAL 45347. 51563. 70504. 73684. 76889. 111497. 115880. 119593. 173318. 18 LESS POWER SOLD 0. 0. 0. 0. 0. 0. 0. 0. 0. 19 NET POWER COST-ACCRUAL 45547. 31563. 70504, 73684. 76889. 111497, 115880. 119593. 173318. = POWER COST-ACCRUAL (MILLS/KWH) 27.14 29.62 39.17 39. 45 39.72 55.64 57.74 56.55 77.62 22 REVENUES: $1,000 23 REVENUES REGD TO MAINTAIN TIER 48778. 36497. 77787. 80945. 84125. 119620. 123966. 127637. 181312. 24 LESS: NON-OPERATING INCOME 320. 1049. 1165. 2442. 2887. 3385. 930. 1407. 1790. 25 LESS: OTHER OPERATING REVENUES 315. 315. 315. 315. 315. 315. 315. 315. 315. 26 LESS: PATRONAGE CAPITAL RETIREMENT 0. 0. 0. 0. 0. 0. 0. 0. 0. 27 REVENUES FROM RATEPAYERS 48142. 33133. 76307. 78187. 809723. 115920. 122720. 125914. 179207. 28 WHOLESALE REVENUES, MILLS/KWH 28.469 31.67 42.39 41.86 41.80 57.84 61.15 59.53 80.25 = ANNUAL INCREASE % 0.00 10.38 33.87 -1.27 0.14 38.39 5.71 2.64 34.80 31 MARGINS: $1,000 32 OPERATING MARGINS 2910. 3885. 6118. 4819. 4349. 4738. 7156. 6636. 6204, 33 NON-OPERATING INCOME 320. 1049. 1165. 2442, 2887. 3385. 930. 1407. 1790. 4 NET PATRONAGE CAPITAL OR MARGINS 3231. 4934. 7283. 7261. 7236. 8123. 8084. 8044. 7994. 36 OPERATING RATIOS: X OF POWER COST 37 ~=PROO & PURCH POWER EXPENSE 25.73 25.72 21.94 23.87 25.67 40. 66 41.34 42. 40 59.53 38 TRANSMISSION EXPENSE 1.93 2.07 2.92 3.15 3.39 3.32 3.51 3.73 2.82 39 ADMIN & GENERAL EXPENSE 3.73 3.68 3.43 3.70 3.82 2.91 3.01 3.13 2.33 40 OTHER EXPENSES 68.61 68.54 71.71 69.28 67.12 33.11 32.14 50.74 35.32 a OPERATING REVENUE 107.09 109.57 110.33 109.85 109.41 107.29 106.98 106.73 104.61 43 FINANCIAL RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 1.15 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 45 DEBT SERVICE COVERAGE (DSC) 1.32 1.37 1.40 1.41 1.40 1.43 1.43 1.43 1.43 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 189 POWER SUPPLY PROGRAM DATE: 8-Nar-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 18:27 PROJECT: 62-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE, DEVELOP COAL-FIRED GENERATION COALGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: COAL VERSION: FIN. FORE. TABLE 14 PROJECTED OPERATING RESULTS CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 1 EXPENSES: $1,000 2 PRODUCTION O&8M-EXCL FUEL 12569. 13708. 14875. 16203. 17657. 19128. 20864. 22616. 24606. 3 = PRODUCTION-FUEL 735447. 95670. 115312. 217101. 332995. 535647. 615126. 676881. 757600. 4 PURCHASED POWER 29501. 30105. 30677. 31910. 33640. 35700. 39833. 49106. 75941. 5 TRANSMISSION 08M 5338. 3832. 6366. 6741. 7580. 8289. 9054. 9880. 10796. & ADMIN & GENERAL-EXCL INSURANCE 3940. 4253. 4596. 4964. 5361. 5790. 6254. 6754. 7294. 7 LONG-TERM LEASES 133. 133. 133. 133. 133. 133. 133. 133. 133. 8 ADDITIONAL G&T STAFF 3998. 4318. 4664. 5037. 5440. 5875. 6345. 6852. 7401. 9 SUSITNA BARGE EXP 625. 665. 708. 7355~ 805. 859. 918. 981. 925. 10 G & T ORGANIZATION 0. 0. 0. 0. 0. 0. 0. 0. 0. 11 INSURANCE 402. 420. 439. 460. 483. 507. 333. 562. 593. 12 DEPRECIATION 16672. 17171. 17711. 18294. 18924. 19604. 20338. 21132. 21988. 13° TAXES 4. 4. 4. 4. 4. 4. 4. 4. 4. 14 INTEREST ON LONG-TERM DEBT 39662. 39277. 38857. 40721. 42707. 42121. 41477. 43952. 43184. 15 LESS: INTEREST CHARGED TO CONSTR 0. 0. 0. 0. 0. 0. 0. 0. 0. 16 OTHER DEDUCTIONS 662. 715. 772. 834. 900. 972. 1050. 1134. 1225. 17 TOTAL POWER COST-ACCRUAL 188953. 212274. 235115. 343357. 466630. 674628. 761930. 9839987. 951690. 18 LESS POWER SOLD 0. 0. 0. 0. 0. 0. 0. 0. 0. 19 NET POWER COST-ACCRUAL 188953. 212274. 235115. 343357. 466630. 674628. 761930. 98397987. 951690. = POWER COST-ACCRUAL (MILLS/KWH) 81.73 88.52 94.54 133.39 174.96 244. 08 265.85 283.01 309.39 22 REVENUES: $1,000 23 REVENUES REQD TO MAINTAIN TIER 196885. 220129. 242886. 351501. 475171. 683053. 770225. 848777. 960327. 24 LESS: NON-OPERATING INCOME 2055. 2199. 1982. 1523. 2477. 3452. 2460. 1286. 2292. 25 LESS: OTHER OPERATING REVENUES 315. 315. 315. 315. 315. 315. 315. 315. 315. 26 LESS: PATRONAGE CAPITAL RETIREMENT 0. 3231. 4934, 7283. 7261. 7236. 8123. 8086. 8044. 27 REVENUES FROM RATEPAYERS 194515. 214385. 235655. 342380. 465118. 672049. 759328. 8397090. 949676. 28 WHOLESALE REVENUES, MILLS/KWH 84.13 89.40 94.75 133.01 174. 40 243.14 264.94 282.71 308.74 = ANNUAL INCREASE % 4.83 6.26 5.99 40.38 31.11 39. 42 8.97 6.71 9.21 31 MARGINS: $1,000 32 OPERATING MARGINS 5878. 3657. 5790. 6621. 6065. 4972. 3836. 7504. 6345. 33 NON-OPERATING INCOME 2055. 2199. 1982. 1523. 2477. 3452. 2460. 1286. 2292. = NET PATRONAGE CAPITAL OR MARGINS 7932. 7855. 7771. 8144. 8541. 8424. 8295. 8790. 8637. 36 OPERATING RATIOS: % OF POWER COST 37 ~=PROD & PURCH POWER EXPENSE 62.19 65.71 68. 42 77.24 82.35 87.53 88.70 89.12 90.17 38 TRANSMISSION EXPENSE 2.82 2.75 2.71 2.02 1.62 1.23 1.19 1.18 1.13 39 ADMIN & GENERAL EXPENSE 2.30 2.20 2.14 1.58 1.25 0.93 0.89 0.87 0.83 40 OTHER EXPENSES 32. 68 29.34 26.73 19.16 14.77 10.31 9.22 8.83 7.87 a OPERATING REVENUE 104.20 103.70 103. 31 102.37 101.83 101.25 101.09 101.05 100.91 43 FINANCIAL RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 45 DEBT SERVICE COVERAGE (DSC) 1.41 1.41 1.41 1.39 1.38 1.38 1.39 1.39 1.39 BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: @2-113-4-000 BRADLEY LAKE, DEVELOP COAL-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: COAL TABLE 14 PROJECTED OPERATING RESULTS CONTRACT YEAR 2001 2002 2003 2004 2005 1 EXPENSES: $1,000 2 PRODUCTION O&M-EXCL FUEL 48472. 52632. 36976. 61798. 67146. 3 > PRODUCTION-FUEL 716623. 820624. 905189. 1015685. 1184273. 4 PURCHASED POWER 41685. 45953. 67527. 100826. 94578. 3 TRANSMISSION O&n 11784. 12852. 14005. 15252. 16597. & ADMIN & GENERAL-EXCL INSURANCE 13999. 15119. 16329. 17635. 19046. 7 LONG-TERM LEASES 133. 133. 133. 133. 133. 8 ADDITIONAL G&T STAFF 79936 8632. 9323. 10068. 10874. 9 SUSITNA BARGE EXP 999. 1079. 1165. 1258. 1359. 10 G & T ORGANIZATION 0. 0. 0. 0. 0. 11 INSURANCE 3160. 3196. 3235. 3277. 3322. 12 DEPRECIATION 34534. 35532. 36611. 37776. 39034. 13. TAXES 4. 4. 4. 4. 4. 14 INTEREST ON LONG-TERM DEBT 153812. 152878. —— -_—«, 149375. 15 LESS: INTEREST CHARGED TO CONSTR 0. 0. 0. 16 OTHER DEDUCTIONS 1323. 1428. 1543. 1666: 1799. 17 TOTAL POWER COST-ACCRUAL 1054520. sates. 4 a or 1607540. 18 LESS POWER SOLD 0. 0. 19 NET POWER COST-ACCRUAL 1054520. 4170064" 1289874, 1436046, 1607540. 2° POWER COST-ACCRUAL (MILLS/KWH) 330.78 354.03 374.74 404.63 437.31 22 REVENUES: $1,000 23 REVENUES REGD TO MAINTAIN TIER 1085282. 1200637. 1314241. 1466179. 1637415. 24 LESS: NON-OPERATING INCOME 2972. 3627. 8071. 10275. 12226. 25 LESS: OTHER OPERATING REVENUES 315. * 315. 315. 315. 315. 26 LESS: PATRONAGE CAPITAL RETIREMENT 7994. 7932. 7855. 7771. 8144. 27 REVENUES FROM RATEPAYERS 1074001. 1186762. 1297999. 1447818. 1616730. 28 WHOLESALE REVENUES, MILLS/KWH 336.89 359.08 378.87 407.95 439.81 ¢ ANNUAL INCREASE % 9.12 6.59 5.51 7.68 7.81 31 MARGINS: $1,000 32 OPERATING MARGINS 27790. 24948. 22296. 19859. 17649. 33 NON-OPERATING INCOME 2972. 3627. 8071. 10275. 12226. = NET PATRONAGE CAPITAL OR MARGINS 30762. 30576. 30367. 30134. 29875. 36 OPERATING RATIOS: % OF POWER COST 37 PROD & PURCH POWER EXPENSE 76.51 78.56 80.20 82.05 83.73 38 TRANSMISSION EXPENSE 1.12 1.10 1.09 1.06 1.03 39 «ADMIN & GENERAL EXPENSE 1.463 1.57 1.52 1.46 1.39 4 OTHER EXPENSES 20.75 18.78 17.18 15.43 13.85 = OPERATING REVENUE 102.92 102.61 102.37 102.10 101.84 43 FINANCIAL RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 1.20 1.20 1.20 1.20 1.20 45 DEBT SERVICE COVERAGE (DSC) 1.46 1.46 1.46 1.45 1.46 2006 72692. 1278120. 205950. 18050. 20570. 133. 11744. 1468. 0. 3371. — — * 1943. — 1822374, 478.06 1851961. 13862. 315. 8541. 1829243. 479.86 911 15725. 13862. 29587. 85. 42 0.99 1.31 12.27 101.62 1.20 1.45 2007 78888. 1494085. 1597118. 19619. 22215. 133. 12683. 1585. 506.97 2031306. 15152. 315. 8424. - 2007414, 508. 33 5.93 14113. 15152. 29265. 86.52 0.98 1.28 il. 101. as ah PAGE: 190 DATE: 8-Mar-83 TIME: 18:27 FILES: CHMNGT.D1 COALGT.02 VERSION: FIN. FORE. 2008 159782. 1267028. 67646. 21313. 44976. 133. 13698. 17 7 12164. 170986. 473366. 2267. 2255074. 2255074. 551.23 2353747. 22939. 315. 8295. 2322197. 567.64 11.67 75734. 22939. 98673. 66.27 0.95 2.53 30.25 104. 38 1.20 1.47 2009 173130. 1448966. 83644. 23144. 48574. 133. 14794. 1849. 0. 12226. — a 2448. ss 2472246. 382.66 2570373. 13187. 315. 8790. 2348081. 600.54 5.80 84941. 13187. 98127. 69.00 0.94 2.46 27.61 103.97 1.20 1.47 a BURNS & MCDOMNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE, DEVELOP COAL-FIRED GENERATION GENERATION AND TRANSMISSION COOP. PLAN: COAL 2013 343269. 1986159. 95136. 32051. 96916. 133. 20127. 2516. 0. 25287. 333839. 4. 977537. 3331. 3916303. 3916305. 800. 88 4111813. 71744. 315. 30367. 4009387. 819.92 14.48 123764. 71744. 195507. 61.91 0.82 3.12 34.15 104.99 TABLE 14 PROJECTED OPERATING RESULTS 2011 2012 202864. 219842. 1808634. 2059971. 207192. + 299372. 27255. 29561. 56657. 61189. 133. 133. 17256. 18636. 2157. 2329. 0. 0. 12365. 12443. 176284. 178543. 424322. 480657. 2856. 3084. arene. 3365763. 2978081. 3365763. 658.77 713.24 3094946. 3461895. 40216. — 51179. 315. 315. 30762. 30574. 3023452, 3379825. 664.39 716.22 3.66 7.80 56649. 44952. 40216. 51179. 96864. 96131. 74.00 76.63 0.91 0.88 2.30 2.19 22.79 20.30 103.23 102.86 1.20 1.20 1.47 1.47 CONTRACT YEAR 2010 1 EXPENSES: $1,000 2 PRODUCTION O&M-EXCL FUEL 187712. 3 > = PRODUCTION-FUEL 1677509. 4 PURCHASED POWER 117165. 3 TRANSMISSION On 25120. & ADMIN & GENERAL-EXCL INSURANCE 32460. 7 LONG-TERM LEASES 133. 8 ADDITIONAL G&T STAFF 15977. 9 SUSITNA BARGE EXP 1997. 10 G & T ORGANIZATION 0. 11 INSURANCE 12293. 12 DEPRECIATION 174546. 13. TAXES 4. 14 INTEREST ON LONG-TERM DEBT 487649. 15 LESS: INTEREST CHARGED TO CONSTR 0. 16 OTHER DEDUCTIONS 2644, 17 TOTAL POWER COST-ACCRUAL 2753209. 18 LESS POWER SOLD 0. 19 NET POWER COST-ACCRUAL 27355209. - POWER COST-ACCRUAL (MILLS/KWH) $26.90 22 REVENUES: $1,000 23 REVENUES REQD TO MAINTAIN TIER 2852739. 24 LESS: NON-OPERATING INCOME 26952. 25° LESS: OTHER OPERATING REVENUES 315. 26 LESS: PATRONAGE CAPITAL RETIREMENT 8637. 27 REVENUES FROM RATEPAYERS 2816835. 28 WHOLESALE REVENUES, MILLS/KWH 640.92 2 ANNUAL INCREASE % 6.72 31 MARGINS: $1,000 32 OPERATING MARGINS 70578. 33 + MNON-OPERATING INCOME 26952. a NET PATRONAGE CAPITAL OR MARGINS 97530. 36 OPERATING RATIOS: % OF POWER COST 37. PROD & PURCH POWER EXPENSE 71.95 38 TRANSMISSION EXPENSE 0.91 39 ADMIN & GENERAL EXPENSE 2.35 40 = OTHER EXPENSES 24.79 a OPERATING REVENUE 103.54 43 FINANCIAL RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 1.20 45 DEBT SERVICE COVERAGE (DSC) 1.47 2014 372534. 2280143. 118950. 34740. 1044669. 133. 21737. 2717. 0. 25378. 336354. 4. 973283. 0. 3597. 4274239. 0. 427 4239. 843. 34 4468896. 57981. 315. 30134. 4380466. 864. 5. Si 44 136675. 57981. 194657. 64. 0. 3. 31. 104. 1. 1. 84 81 04 30 535 20 49 2015 PRESENT 404180. 2585701. 208829. 37645. 113043. 133. 23476. 2934. 0. 25476. sali mele: 3885. 47: = 4712525. 897.79 4906155. 87020. 315. 29875. 4788945. 912.35 5.53 106610. 87020. 193630. 67.88 0.80 2.94 28.397 104.11 VALUE (1983$) 4115786. PAGE: 191 DATE: 8-Nar-83 TINE: 18:27 » FILES: CHMGT.D1 COALGT. D2 VERSION: FIN. FORE. a ese ———. —n Hydroelectric Expansion Scenario fF: G&T Cooperative 10-Year Capital Credit Rotation BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 189 POWER SUPPLY PROGRAM DATE: 86-Mar-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 18:18 PROJECT: 82-113-4-000 FILES: CHMGT.D1 BRADLEY LAKE & SUSITNA PROJECTS HYDRGT. 02 GENERATION AND TRANSMISSION COOP. PLAN: HYDRO (8%, 10YR) VERSION: FIN. FORE. TABLE 14 PROJECTED OPERATING RESULTS CONTRACT YEAR 1983 1984 1985 1986 1987 1988 1989 1990 1991 1 EXPENSES: $1,000 2 PRODUCTION O&M-EXCL FUEL 5303. 5863. 6921. 7739. 8421. 8993. 9789. 10630. 11576. 3 PRODUCTION-FUEL 3126. 6146. 6517. 7631. 9012. 8195. 9644. 11364. 62604. 4 PURCHASED POWER 1291. 1252. 2029. 2220. 2308. 28146. 28477. 28710. 29003. 3 TRANSMISSION O&M 881. 1067. 2060. 2321. 2604. 3702. 4065. 4457. 4881. & ADMIN & GENERAL-EXCL INSURANCE 1676. 1849. 2222. 2483. 2682. 2897. 3129. 3378. 3649. 7 LONG-TERM LEASES 133. 133. 133. 133. 133. 133. 133. 133. 133. 8 ADDITIONAL G&T STAFF 0. 340. 770. 1097. 1563. 2227. 3174. 3428. 3702. 9 SUSITNA BARGE EXP 700. 720. 742. 44%. 465. 492. 522. 353. 588. 10 G & T ORGANIZATION 200. 200. 150. 0. 0. 0. 0. 0. o. 11 INSURANCE 21. 4%. 198. 241. 252. 344. 357. 371. 386. 12 DEPRECIATION 7935. 8494. 11736. 12427. 12742. 15263. 15430. 15781. 16209. 13. TAXES 4. 4. 4. 4. 4. 4. 4. 4. 4. 14 INTEREST ON LONG-TERM DEBT 21537. 24470. 36414. 36306. 36180. 40614. DAD. 4218. 39970. 15 LESS: INTEREST CHARGED TO CONSTR 0. 0. 0. 0. 0. 0. 0. 0. 0. 16 OTHER DEDUCTIONS 741. 580. 609. 640. 324. 486. 525. 347. 613. 17 TOTAL POWER COST-ACCRUAL 45547. 31543. 70504. 73684. 76889. 111497. — 119593. 173318. 18 LESS POWER SOLD 9. 0. 0. 0. 0. 0. 0. 0. 19 NET POWER COST-ACCRUAL 45547. 31563. 70504. 73684. 76889. 111497. 115800; 119593. 173318. 2 POWER COST-ACCRUAL (MILLS/KWH) 27.14 29.62 39.17 39.45 39.72 35.64 37.74 36.55 77.62 22 REVENUES: $1,000 23 REVENUES REQ@D TO MAINTAIN TIER 48778. 36497. 77787. 80945. 84125. 119620. 123966. 127637. 181312. 24 LESS: NON-OPERATING INCOME 320. 1049. 1165. 2442. 2887. 3385. 930. 1407. 17%. 25 LESS: OTHER OPERATING REVENUES 315. 315. 315. 315. 315. a = 315. 315. 26 LESS: PATRONAGE CAPITAL RETIREMENT 0. 0. 0. 0. 0. 0. 0. 27 REVENUES FROM RATEPAYERS 48142. 55133. 76307. 78187. 80923. 115920; 122720 125914. 179207. 28 WHOLESALE REVENUES, MILLS/KWH 28.69 31.67 42.39 41.86 41.80 57.84 61.15 59.53 80.25 2 ANNUAL INCREASE % 0.00 10.38 33. 87 -1.27 ~0.14 38.39 5.71 -2.64 34.80 31 MARGINS: $1,000 32 OPERATING MARGINS 2910. 3885. 6118. 4819. 4349. 4738. 7156. 6636. 6204. 33 NON-OPERATING INCOME 320. 1049. 1165. 2442. 2887. 3385. 930. 1407. 1790. 2 NET PATRONAGE CAPITAL OR MARGINS 3231. 4934. 7283. 7261. 7236. 8123. 8086. 8044. 7994. 36 OPERATING RATIOS: % OF POWER COST 37 PROD & PURCH POWER EXPENSE 25.73 25.72 21.94 23.87 25.67 40. 66 41.34 42.40 59.53 38 TRANSMISSION EXPENSE 1.93 2.07 2.92 3.15 3.39 3.32 3.51 3.73 2.82 39 ADMIN & GENERAL EXPENSE 3.73 3.68 3.43 3.70 3.82 2.91 3.01 3.13 2.33 40 OTHER EXPENSES 68.41 68.54 71.71 69.28 67.12 53.11 52.14 50.74 35.32 a OPERATING REVENUE 107.09 109.57 110.33 109.85 109.41 107.29 106.98 106.73 104.61 43 FINANCIAL RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 1.15 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 45 DEBT SERVICE COVERAGE (DSC) 1.32 1.37 1.40 1.41 1.40 1.43 1.43 1.43 1.43 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 190 POWER SUPPLY PROGRAN DATE: 8-Mar-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 18:18 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE & SUSITNA PROJECTS HYDRGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: HYDRO (8%, 10YR) VERSION: FIN. FORE. TABLE 14 PROJECTED OPERATING RESULTS CONTRACT YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 EXPENSES: $1,000 PRODUCTION O&N-EXCL FUEL 12569. 12442, 12738. 13917. 15197. 16561. 18123. 19649. 21522. 5 PRODUCT ION-FUEL 73447. 32102. 17063. 43964. 79125. 158614. 1984699. 221031. 273175. 4 PURCHASED POWER 29501. 294627. 428587. 430205. 431750. 433461. 435465. 437405. 439540. 3 TRANSMISSION 08" 3338. 5832. 6366. 6941. 7580. 8289. 9054. 9880. 10796. & ADMIN & GENERAL-EXCL INSURANCE 3940. 4255. 4596. 4964, 5361. 5790. 6254. 6754. 7294. 7 LONG-TERM LEASES 133. 133. 133. 133. 133. 133. 133. 133. 133. 8 ADDITIONAL G&T STAFF 3998. 4318. 4664. 3037. 3440. 5875. 6345. 6852. 7401. 9 SUSITNA BARGE EXP 625. 665. 708. 753. 805. 859. 918. 981. 925. 10 G & T ORGANIZATION 0. 0. 0. 0. 0. 0. 0. 0. 0. 11 INSURANCE 402. 420. 439. 460. 483. 507. 533. 362. 3973. 12 DEPRECIATION 16672. 17171. 17711. 18294, 18924. 19404. 20338. 21132. aes 13. TAXES 4. 4. 4. 4. 4. 4. 4. 4. 14 INTEREST ON LONG-TERM DEBT 39662. 39277. = 40721. 42707. 42121. 41477. 43952. sat04 15 LESS: INTEREST CHARGED TO CONSTR 0. 0. 0. 0. 0. 0. 0. 16 OTHER DEDUCTIONS 642. 715. 772. 834. 900. 972. 1050. 1134, 1225. 17 TOTAL POWER COST-ACCRUAL 188953. 411964. 532638. 566230. 608410. 692789. 738374. 769469. ae 18 LESS POWER SOLD 0. 0. 0. 0. 0. 0. 0. 0. 19 = NET _PQWER COST-ACCRUAL 188953. 411964. 532638. 566230. 608410. 692787. 738374. 7697469. 827780, 2) POWER COST-ACCRUAL (MILLS/KWH) 81.73 171.79 214.17 219.98 228.13 250.465 257.64 259.25 269.11 22 REVENUES: $1,000 23 > REVENUES REGD TO MAINTAIN TIER 196885. 419820. 540410. 574374. 616951. 701213. 746689. 7782597. 836417. 24 LESS: NON-GPERATING INCOME 2055. 2199. 1982. 1523. 2477. 3452. 2460. 1286. 2292. 25 LESS: OTHER OPERATING REVENUES 315. 315. 315. 315. 315. 315. 315. 315. 315. 26 LESS: PATRONAGE CAPITAL RETIREMENT 0. 3231. 4934. 7283. 7261. 7236. 8123. 8086. 8044. 27 REVENUES FROM RATEPAYERS 194515. 414075. 5331779. 565253. 606898. 6970210. 735791. 768572. 825767. 28 WHOLESALE REVENUES, NILLS/KWH 84.13 172.68 214.39 219.60 227.56 249.71 256.73 258.95 268. 45 = ANNUAL INCREASE % 4.83 105.24 24.16 2.43 3.62 9.74 2.81 0.87 3.67 31 MARGINS: $1,000 32 OPERATING MARGINS 5878. 5657. 5790. 64621. 6065. 4972. 5836. 73504. 6345. 33 NON-OPERATING INCOME 2055. 2199. 1982. 1523. 2477. 3452. 2460. 1286. 2292. = NET PATRONAGE CAPITAL OR MARGINS 7932. 78535. 7771. 8144. 8541. 8424. 8295. 8790. 8637. 36 OPERATING RATIOS: % OF POWER COST 37 =PROD & PURCH POWER EXPENSE 62.19 82.33 86.06 86.20 86.47 87.85 88.34 88.12 88.70 38 TRANSMISSION EXPENSE 2.82 1.42 1.20 1.23 1.25 1.20 1.23 1.28 1.0 39 ADMIN & GENERAL EXPENSE 2.30 1.13 0.95 0.96 0.96 0.91 0.92 0.95 0.95 40 OTHER EXPENSES 32.68 15.12 11.80 11.62 11.33 10.04 9.52 9.64 9.04 4 OPERATING REVENUE 104. 20 101.91 101.46 101.44 101.40 101.22 101.12 101.14 101.04 43 FINANCIAL RATIOS: 44 TINES INTEREST EARNED RATIO (TIER) 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 45 DEBT SERVICE COVERAGE (DSC) 1.41 1.41 1.41 1.39 1.38 1.38 1.39 1.39 1.39 mre, BURNS & MCDONNELL ENGINEERING COMPANY POWER SUPPLY PROGRAM CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS PROJECT: 82-113-4-000 BRADLEY LAKE & SUSITNA PROJECTS GENERATION AND TRANSMISSION COOP. PLAN: HYDRO (6%, 10YR) CONTRACT YEAR 1 EXPENSES: $1,000 2 PRODUCTION O&M-EXCL FUEL 3 PRODUCTION-FUEL 4 PURCHASED POWER 5 TRANSMISSION O&M & ADMIN & GENERAL-EXCL INSURANCE 7 LONG-TERM LEASES 8 ADDITIONAL G&T STAFF 9 SUSITNA BARGE EXP 10 G & T ORGANIZATION 11 INSURANEE 12 DEPRECIATION 13. TAXES 14 INTEREST ON LONG-TERM DEBT 15 LESS: INTEREST CHARGED TO CONSTR 16 OTHER DEDUCTIONS 17 TOTAL POWER COST-ACCRUAL 18 LESS POWER SOLD 19 NET POWER COST-ACCRUAL ae POWER COST-ACCRUAL (MILLS/KWH) 22 REVENUES: $1,000 23 REVENUES RE@D TO MAINTAIN TIER 24 LESS: NON-OPERATING INCOME 25 LESS: OTHER OPERATING REVENUES 26 LESS: PATRONAGE CAPITAL RETIREMENT 27 REVENUES FROM RATEPAYERS 28 WHOLESALE REVENUES, MILLS/KWH B ANNUAL INCREASE % 31 MARGINS: $1,000 32 OPERATING MARGINS 33 NON-OPERATING INCOME = NET PATRONAGE CAPITAL OR MARGINS 36 OPERATING RATIOS: % OF POWER COST 37 = PROD & PURCH POWER EXPENSE 38 TRANSMISSION EXPENSE 39 ADMIN & GENERAL EXPENSE 40 OTHER EXPENSES 4 OPERATING REVENUE 43 FINANCIAL RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 45 DEBT SERVICE COVERAGE (DSC) 2001 23559. 331498. 442024. 11784. 7877. 133. 7993. 999. 0. 627. 22914, 4. 46042. 0. 1323. ower . 896776. 281.30 9059784. 845. 315. 7994, 896830. 281.31 4.79 8363. 845. 9208. 2004 956851. 269.61 967163. 1185. 315. 7771. 957892. 269.90 -0.35 9127. 1185. 10312. 87.78 TABLE 14 PROJECTED OPERATING RESULTS 2002 2003 22535. 24476. 39912. 67009. 724472. 728987. 12879. 14090. 8507. 9188. 133. 133. 8632. 9323. 1079. 1165. 0. 0. 663. 702. _— TT 49107. 48063. 0. 0. 1428. 1543. lane’ Meta 893265. 929676. 270.28 271.36 903086. 939288. 1971. 3134. 315. 315. 7932. 7855. 892867. 927984. 270.16 270.87 3.97 0.26 7850. 6479. 1971. 3134. 9821. 9613. 88.09 88. 25 1.44 1.52 1.63 1.06 9.44 9.17 101.10 101.03 1.20 1.20 1.37 1.37 2005 29507. 173787. 737539. 16846. 10717. 133. 10874. 1359. 0. 7%. 27418. 1077141. 2454. 315. 8144, 1066228. 290.05 7.4% 8608. 2454. 11061. 88. 1.58 1. 9. 1 & 10 8&8 838 os as 88.96 1.52 1.02 100.98 PAGE: 191 DATE: 8-Nar-83 TINE: 18:18 FILES: CHNGT.D1 HYDRGT. 02 VERSION: FIN. FORE. 2007 2008 2009 35855. 38539. 42593. 385908. 375202. 539377. 747432. 752886. 758724. 20211. 22162. 24269. 12500. 13500. 14580. 133. 133. 133. 12683. 13698. 14794. 1585. 1712. 1849. 0. 0. 0. 893. 950. 1012. -— — — _— -— acre. 2099. 2267. 2448. — ° — a 1313147. 1314665. 1499951. 332.53 321.36 353.51 1325862. 1327021. 1513275. 5110. 6478. 3275. 315. 315. 315. 8424, 8295. 8790. 1312013. 1311932. 15008974. 332.24 320.69 353.73 4.20 -3. 48 10.31 7605. 3877. 10049. 3110. 6478. 3275. 12715. 12356. 13324. 897.04 88.74 89.38 1.54 1.69 1.62 1.02 1.10 1.04 8.40 8.48 7.96 100.97 100.94 100.89 1.20 1.20 1.20 1.32 1.31 1.31 BURNS & MCDONNELL ENGINEERING COMPANY PAGE: 192 POWER SUPPLY PROGRAM DATE: 8-Mar-83 CHUGACH, HOMER & MATANUSKA ELEC. ASSOCIATIONS TIME: 18:18 PROJECT: 82-113-4-000 FILES: CHNGT.D1 BRADLEY LAKE & SUSITNA PROJECTS HYDRGT.D2 GENERATION AND TRANSMISSION COOP. PLAN: HYDRO (8%, 10YR) VERSION: FIN. FORE. TABLE 14 PROJECTED OPERATING RESULTS CONTRACT YEAR 2010 2011 2012 2013 2014 2015 arid 1 EXPENSES: $1,000 (1983$) 2 PRODUCTION O&M-EXCL FUEL 46534. 50968. 56585. 61252. 67292. 74667. 3 PRODUCTION-FUEL 622725. 765482. 1029395. 1118677. 1413644. 1829319. 4 PURCHASED POWER 765347. 772157. 779551. 787835. 796442. 805729. S TRANSMISSION O&N 26594. 29159. 31987. 35105. 38471. 42181. & ADMIN & GENERAL-EXCL INSURANCE 15747. 17006. 18367. 19836. 21423. 23137. 7 LONG-TERM LEASES 133. 133. 133. 133. 133. 133. 8 ADDITIONAL G&T STAFF 15977. 17256. 18636. 20127. 21737. 23476. 9 SUSITNA BARGE EXP 1997. 2157. 2329. 2516. 2717. 2934. 10 G & T ORGANIZATION 0. 0. 0. 0. 0. 0. 11 INSURANCE 1080. 1152. 1231. 1315. 1406. 1505. 12 DEPRECIATION 35397. 37239. 39398. 36683. 39201. 41920. 13. TAXES 4. 4. 4. 4. 4. 4. 14 INTEREST ON LONG-TERM DEBT 71817. 77345. 83243. 80209. 87105. 94855. 15 LESS: INTEREST CHARGED TO CONSTR 0. 0. 0. 0. 0. 0. 16 OTHER DEDUCTIONS 2644. 2856. 3084. 3331. 3597. 3885. 17 TOTAL POWER COST-ACCRUAL 1605996. 1772916. 2063944. 2167023. 2493173. 2943746. 18 LESS POWER SOLD 0. 0. 0. 0. 0. 0. 19 NET POWER COST-ACCRUAL 1605996. 1772916. 2063744. 2167023. 2493173. 2943746. » POWER COST-ACCRUAL (MILLS/KWH) 365. 41 389.57 437.37 443.15 492.04 560. 82 22 REVENUES: $1,000 23° REVENUES REQD TO MAINTAIN TIER 1620359. 1788385. 2080593. 2183064. 2510594. 2962717. 24 LESS: NON-OPERATING INCOME 4752. 6317. 7934, 9364. 4015. 5808. 25 LESS: OTHER OPERATING REVENUES 315. 315. 315. 315. 315. 315. 26 LESS: PATROHAGE CAPITAL RETIREMENT 8637. 9208. 9821. 9613. 10312. 11061. 27 REVENUES FROM RATEPAYERS 1605655. 1772544. 2062522. 2163772. 2495951. 2945533. 3442194, 28 WHOLESALE REVENUES, MILLS/KWH 365.56 389. 48 437.07 442.49 492.59 561.16 2 ANNUAL INCREASE % 3.34 6.54 12.22 1.24 11.32 13.92 31 MARGINS: $1,000 32 OPERATING MARGINS 9611. 9152. 8714. 6677. 13406. 13163. 33 NON-OPERATING INCOME 4752. 6317. 7934. 9364. 4015. 5808. a NET PATRONAGE CAPITAL OR MARGINS 14363. 15469. 16649. 16042. 17421. 18971. 36 OPERATING RATIOS: % OF POWER COST 37 PROD & PURCH POWER EXPENSE 89.33 89.460 90.39 90.80 91.34 92.05 38 TRANSMISSION EXPENSE 1.66 1.64 1.55 1.62 1.54 1.43 39 ADMIN & GENERAL EXPENSE 1.05 1.02 0.95 0.98 0.92 0.84 40 OTHER EXPENSES 7.97 7.73 7.A1 6.60 6.20 5.68 a OPERATING REVENUE 100.89 100. 87 100.61 100.74 100.70 100.64 43 FINANCIAL RATIOS: 44 TIMES INTEREST EARNED RATIO (TIER) 1.20 1.20 1.20 1.20 1.20 1.20 45 DEBT SERVICE COVERAGE (DSC) 1.30 1.28 1.28 1.23 1.26 1.30 og pg t perce ey t t es | APPENDIX D — TIER REQUIREMENTS. VERIFICATION FROM REA AND CFC bee co [nae ee NATIONAL RURAL UTILITIES COOPERATIVE FINANCE CORPORATION 1115 30th STREET, N.W., WASHINGTON, D.C. 20007 e (202) 337-6700 November 4, 1982 Mr. J.D. Farber, P.E. Vice President and General Manager Power Division Burns & McDonnell 4800 East 63rd Street P.O. Box 173 Kansas City, Missouri 64141 Dear Mr. Farber: Your inquiry of October 19, 1982 specifically requested a statement from CFC on the probability that Chugach Electric Association, Inc. would be permitted to carry a TIER of 1.0 on the generation and transmission portion of its system without formally organizing a G&T Cooperative. CFC's position remains the same as it always has. Under the present structure of their organization a TIER of 1.5 is required to meet CFC's mortgage requirements and pledge the notes against our indenture. Even though REA has waived the TIER requirement of 1.5 on two Alaska systems there is no way CFC can permit less than the 1.5 TIER under the requirements of its indenture. In our opinion, the proposed formation of a G&T is still the most viable solution. It enables the spin-off of the G&T property and facilitates the achievement of a 1.5 TIER on the remaining distribu- tion property. The other alternative would be to simply create two separate Chugach entities with separate boards and accounting functions thus enabling them to meet a 1.0 TIER on the generation and transmission side and the 1.5 TIER on the distribution side. If you have any further questions please feel free to call me. Sincerely, a= \ Te c= i, Gerald V. Beer Director of Loan Review and Analysis —<—\ — United States Rural Washington Department Electrification oC. of Agriculture Administration 20250 MOV 12 1982 Mr. J. D. Farber, P.E. Vice President and General Manager Power Division Burns and McDonnell P. 0. Box 173 Kansas City, Missouri 64141 Dear Mr. Farber: This is in reference to your letter of October 19, 1982, concerning the study being performed by Burns and McDonnell Engineering Company to evaluate alter- native organizational structures to meet the power supply needs of Chugach Electric Association, Inc. (Chugach), Homer Electric Association, Inc. (Homer), and Matanuska Electric Association, Inc. (Matanuska). The Rural Electrification Administration (REA) has agreed that, for a period of up to 2 years, Chugach will be required to maintain a TIER of only 1.15 on its generation and transmission plant debt. The Alaska Public Utilities Commission approved rates sufficient to achieve this level in its order dated July 22, 1982. REA has taken this position only temporarily in order to allow Chugach the time it needs to improve its present financial condition while exploring the possi- bility of "spinning off" its generation and transmission facilities to a new power supply organization. REA will not, under any circumstances, provide a permanent waiver of the 1.50 TIER requirement if a separate G&T cooperative or other power supply organization is not formed. If we can be of further assistance, please let us know. A copy of this letter is being sent to Chugach, Homer and Matanuska Electric Associations and to NRUCFC. Sincerely, ae OE Ss. Assistant Administrator - Electric “APPENDIX E — SUMMARY OF ENERGY SALES AND CUSTOMERS FOR THE COOPERATIVES Appendix E SUMMARY OF 1981 ENERGY SALES AND CUSTOMERS FOR THE COOPERATIVES Energy Sales Customers (Average) Cooperative (Millions of kWh) (Percent) (Thousands) (Percent) Chugach 849.3 62 48.4 65 Homer 291.9 21 11.3 15 Matanuska 228.3 Lie 14.5 __20 Total 1369.5 100 74.2 100 E-1