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Home My WebLink AboutSE Interie Questions and Benefits 1998Statewide Questions di What is the long-term benefit to the State of the SE Intertie? The long-term benefits to the State of Alaska are: A) B) 2 Additional revenue to the State through sales of additional energy from the State’s Tyee project, and; Improved infrastructure directly supporting the viability of Southeast Alaska, a region geographically and economically vital to the State. What are the benefits of distributed vs. inter-connected generation for the Southeast? We believe the benefits of the Southeast Alaska Intertie can best be summarized by the following two quotations: 3 Swan-Tyee Intertie Final EIS “The underlying purpose and need to which this project responds is for KPU to 1) provide a reliable and efficient source of power for the City of Ketchikan’s intermediate and long-range needs at reasonable rates while 2) establishing an important link in the long-proposed electrical network for southern Southeast Alaska so the 3) more communities would have access to more power sources or more power customers.” [pg. 1-6] Southeast Alaska Electrical Intertie System White Paper (developed by Southeast Alaska communities December 1997) “At present, most every community in Southeast Alaska generates its own power in a largely isolated electrical environment. In an area with rich hydroelectric potential, most smaller communities remain entirely diesel dependent. Even in larger communities such as Juneau, Ketchikan and Sitka which currently have hydroelectric power, those facilities are reaching the limit of their capacity and supplemental diesel power is being pursued or contemplated. This, despite the fact there is adequate hydroelectric potential to serve all of Southeast for decades to come if an intertie system existed to transport power to the load centers. The communities of Southeast Alaska therefore support the concept of a southeast electric grid as a means of reducing or avoiding diesel dependence, encouraging economic development and stabilizing and equalizing power rates.” What is the current financing plan including specifics? KPU invested significant time and energy into a financing plan whereby the City of Ketchikan would accept the $20 million loan authorized by the state in 1993. We proposed in return that the State of Alaska offset power rates such that KPU could cover debt service and O&M costs. Although this plan seemed to offer the best compromise, it was ultimately not acceptable to either the State or the City. The State was concerned that rate reduction was excessive, and our analysis demonstrated that the financial burden to the City was unacceptable. KPU has recently proposed that a mutually satisfactory solution might be to devote the cash flow set aside in the 1993 legislation for the Southeast Intertie (40% of the Four Dam Pool payment to the State) to a bond issued by the State for the project. This would provide sufficient capital to cover most of the current-shortfall””- KPU would propose that-the-$20.million currently set aside by the. State tor the $20 million Joan would be released for other purposes. a This proposal i is ; provided as attachment (A). KPU stands ready to negotiate the specific details of the plan. 4. What are the economic benefits of the Southeast transmission corridor for multiple uses such as fiber optics, communications, etc.? Although the current design for the Swan-Tyee Intertie does not include provisions for fiber optics, that can be modified if that appears to be economically justified or desirable. In fact, KPU has been in contact with Alaska Fiber Star regarding a fiber spur between Juneau and Ketchikan via Petersburg and Wrangell. If the inclusion of fiber optics in the design is an option AIDEA or others wish to pursue, KPU is prepared to negotiate the terms and revise the design. With respect to other multiple uses, the Final EIS offers our best and most comprehensive review of this matter. In particular, the corridor was specifically routed along a logical road corridor to minimize environmental impact of that future development. J What municipal actions are necessary to implement the financing plan? The City of Ketchikan has approved the concept as presented in attachment (A). The City can continue to act as the project manager and would take such action as we have in the past to authorize and oversee project activities. City Council approval would be needed to ratify a power sales agreement with the Four Dam Pool and if needed a financing agreement with the State of Alaska. Regional Questions I, What are the current SE Intertie project costs assumed for Four Dam Pool debt service, R&R, and Four Dam Pool O&M costs? As an interruptible power sales agreement has not been executed with the State and the Four Dam Pool, these issues are all subject to negotiation. Generally KPU assumes that construction of the Intertie would be state owned, that energy would be sold to KPU at or near current Four Dam Pool rates but is dependent on KPU’s continuiig—risk“an and responsibility for the project. ‘These are issues KPU assumes are subject to negotiation and we stand ready to begin that~ process with the State and the Four Dam Pool. Zs What is the cost of power sensitivity in Petersburg, Wrangell, and Ketchikan to extended transmission line outages, e.g. 60 days, between Ketchikan and Swan Lake and between Tyee Lake and Swan Lake? Our view of the Swan-Tyee Intertie is that it allows the additional sale of available Four Dam Pool power, economically benefiting the State and the Four Dam Pool communities through revenue from an interruptible sales agreement. An outage today between Swan Lake and Ketchikan would not have a defined cost of power sensitivity, the sale would simply resume at the wholesale rate when service was restored. Lost revenue from that outage would ultimately be taken into account in setting the Four Dam Pool rate for the next year. We have a similar view of an outage that would affect a Four Dam Pool interruptible sale to Ketchikan over the Intertie. The thrust of this question may be to suggest terms in an interruptible power sales agreement that would define costs, risks and responsibilities for outages. KPU stands ready to negotiate those terms. 3: What is the cost of power impacts of extreme high and low water scenarios of Tyee and Swan Lake occurring together or in opposition? Raytheon Infrastructure Services conducted an intertie operations study in April, 1995 to evaluate the combined operation of Tyee and Swan Lake provided as attachment (B). This study includes consideration of historical water availability, but it does not draw conclusions regarding the rate impact of extreme conditions. Our view is that analysis of cost of power impacts for abnormal conditions at any of the Four Dam Pool projects cannot be considered in isolation, because the costs and revenues are ultimately pooled. For example, in a given year low water conditions at Terror Lake may be balanced by high water conditions in the Swan-Tyee system, resulting in no impact to the Four Dam Pool cost of power. We assume however that the impact of extreme low water conditions in the Swan-Tyee system would result in a reduction of interruptible Tyee sales to Ketchikan as Petersburg and Wrangell have first right to that power. 4. How do you see the revenues, costs, and risks being shared among the State, Four Dam Pool, Petersburg and Wrangell, and Ketchikan? Our view is that the sale of Tyee power to Ketchikan would be defined under an interruptible sales agreement. Ultimately, all these terms are subject to negotiation. We see a negotiated allocation of revenue to the State and the Four Dam Pool communities for the additional sales. Previously, there has been reluctance by the State and Four Dam Pool to accept either costs or risks associated with the project. Therefore, KPU has been prepared to negotiate an assumption of various costs and risks, provided the City has reasonable compensation for those costs and risks. On the other hand, we are prepared to negotiate a division of those risks, costs and compensation with the State and Four Dam Pool. Further, we have always viewed this project as an improvement to the Four Dam Pool facilities and are open to negotiating the addition of this project to those facilities. >: What are the reductions in generation reserves for Petersburg, Wrangell, and Ketchikan resulting from the Intertie and how do these reductions impact cost of power for each city? Please note our response to question 3 above. The Raytheon study utilizes a certain operational model based on assumed monthly loads and average reservoir inflows. The generation reserve, or combined storage depicted in this model varies by month and year. An example is shown for the year 2013 in figure 5. However, Petersburg and Wrangell have a first right to Tyee power and we assume this would have to be protected through responsible reservoir management, just as we manage our reservoir levels today to avoid extreme conditions. 6. Are there opportunities for British Columbia sales or generation purchase which are enhanced by the SE Intertie? An electrical intertie with British Columbia has been considered by various studies and at various locations. Our view is that the development of a grid in Southeast Alaska creates a greater pool of both resources and loads creating more potential for either future sales or generation purchase with the North American grid through BC Hydro. Ketchikan Questions de How has the actual capital and O&M cost of the new KPU diesel generation impacted the cost of power? R. W. Beck has recently calculated our avoided cost of electrical generation. That document is provided as attachment (C). We refer you to tables 6 - 8 for detail of diesel costs. KPU rates have not been adjusted as a result of the addition of the new diesel engine. The City Council has largely concluded a review of KPU’s budget and has eliminated a 5% rate increase from KPU’s 1999 budget request. Z How do you see the SE Intertie affecting the Mahoney Lake project and vice versa? Our view of the interrelationship of the Intertie and various small hydro projects, including Mahoney Lake, is best detailed in attachment (F). ck What is the wholesale cost of power, escalation indices, reliability factors, and term of Mahoney Lake and 4 Dam Pool proposals for the power sales agreements? KPU has not received any detailed proposals for the purchase of Mahoney Lake power. We have a general proposal from AP&T to purchase power at the Four Dam Pool wholesale rate or our avoided cost, whichever is greater. KPU had provided a draft interruptible power sales agreement to the Four Dam Pool under our previous financing plan, which ultimately was not acceptable to either party. We are prepared to enter into negotiations for a revised interruptible power sales agreement Intertie power. We would expect to negotiate these issues in that process. 4. How do ISER load growth predictions for 1998 compare to actuals? What new industries have been included in ISER projections? What new industries may occur or be attracted to Ketchikan and what is the impact cost of power (e.g. 10 MW industrial load in 2005)? What is the impact (e.g. a 10 MW hydro plant) independent power producer on-line in 2005 on the cost of power? ISER projections for 1998 compared to our estimated actual for 1998 are: ISER base case: 146,117 MWH ISER high case: 147,607 MWH ISER low case: 145,794 MWH Estimated actual 1998 gross generation: 164,000 MWH The summary of the ISER study is provided as attachment (H). ISER notes that they make conservative assumptions for the base case. Further, they note that they do not include new large scale commercial or industrial load in their projections. For example, they exclude the KPC sawmill because of the future uncertain of the timber industry even though KPU currently serves this load. The cost impacts of additional load and/or additional generation (independent or otherwise) are best detailed in attachment (C). Ss What is the impact of the transmission right-of-way maximum timber sales or no sales, storage, and disposal on the cost of power? Attachment (E) considers various approaches to construction sequencing and timber handling. It also includes a comparison of capital costs for different timber sales assumptions. Generally KPU assumes that construction of the Intertie would be state owned, that energy would be sold to KPU at or near the wholesale rate depending on KPU’s continuing risk and responsibility for the project. We view the cost of power as being a negotiated rate in an interruptible power sales agreement. We stand ready to enter into those negotiations with the State and the Four Dam Pool. 6. What is the cost of power impact of failure to receive the $4M appropriation (e.g. for 2 years). Failure to receive state and federal grant funding in general will result in delayed construction and completion, whether that is one year or ten years. The City of Ketchikan has proposed a financing scheme in attachment (A) that does rely on the 40% Four Dam Pool debt service allocation set up by the State in 1993, but also releases $20 million for other uses. Additionally, the existing federal funding of $10 million will lapse if not used by end of the federal fiscal year 2000. See also our response to question 10 below. i What is the impact of Intertie 25% capital cost overrun and/or 25% O&M cost overrun on cost of power? We assume that these impacts would be defined in a negotiated interruptible power sales agreement. Generally KPU assumes that the Intertie would be state owned, but we are prepared to negotiate an assumption or division of risk and reward, including those associated with the capital cost of the project. We stand ready to begin that process with the State and the Four Dam Pool. 8. What are the costs of power impacts of necessary coordinated and limited scheduled outages on Tyee Lake and Swan Lake on the communities? Please see our response to Regional Question 2. io. What is the term of the current EIS/ROD? The EIS and Record of Decision do not have a defined term. We are advised by our consultant and the USFS that the more time that passes before construction begins, the greater risk we have that a successful argument will be made that conditions have changed enough over time to warrant a supplemental EIS. 10. What are the KPU action plans if they fail to receive any additional Federal grants? Failure to receive additional federal funding in general reduces the state’s incentive to pursue bonding of the project. KPU plans in the absence of sufficient federal/state funding for the Swan-Tyee Intertie are best described in Attachment (F). See also response to Ketchikan question 6 above. 1k What is the impact on the cost of power of Tyee energy (e.g. 6.8 cents/KWH or interruptible rate, say 4.0 cents/KWH)? Our view of the Swan-Tyee Intertie is that it allows the additional sale of available Four Dam Pool power, economically benefiting the State and the Four Dam Pool communities through revenue from an interruptible sales agreement. The interruptible rate is subject to negotiation. The additional revenue received from those interruptible sales would be allocated to the State and Four Dam Pool. The resulting benefit to the communities and projects could be calculated for a variety of rate scenarios. We stand ready to negotiate the terms of an interruptible sales agreement, and perform associated calculations estimating the beneficial impact of those sales to the State and Four Dam Pool communities. 12s Will compensation (SVC) be required for the Intertie. What is the cost of power impact? The addition of a static var compensator (SVC) to the design has been discussed, but is not currently included in either the design or the cost estimate. 13: What is the Intertie cost of power difference between the second best alternative and the SE Intertie for low, medium, and high growth scenarios and what amount of investment does the reduction justify? Generally KPU assumes that construction of the Intertie would be state owned, that energy would be sold to KPU at or near the wholesale rate depending on KPU’s continuing risk and responsibility for the project. The avoided cost calculation is provided as attachment (C). That calculation assumes the Intertie is not constructed and that KPU proceeds with the small hydro alternative detailed in attachment (F). To compare the costs of our preferred alternative (the Intertie) with our second best alternative (small hydro), one is comparing our negotiated interruptible rate to the avoided costs detailed in attachment (C). The thrust of this question may to be establish the economic value to KPU of pursuing the Intertie over the alternative. Since the interruptible rate is not yet negotiated, we would propose that economic value be established through the negotiation process. 14. What is the impact on the cost of power of actual capital cost, shorter life, higher fuel cost, and higher O&M cost for the new diesel? All of these variables could be modified in the models presented in attachment (C). Also see our response to Ketchikan question 1 above. 15. What are the impacts of current and future air quality regulations and diesel emissions on cost of power and Ketchikan future growth? Our construction permit is provided as attachment (D). The operating limitations are detailed on page 8/19, section IV.A.5. At this point, the hourly limitations are set significantly higher than we have required in the past. We do not expect to exceed these limitations for some years, at which point we hope to have augmented our hydroelectric supply decreasing our reliance on diesel generation. This could change if the Intertie was not to be built and for one reason or another Whitman and Connell Lakes were not deemed to be economically developable as a result of FERC or other agency requirements. 16. What is the cost of power impact of 1% vs. 3% line losses? We assume that establishing the point of metering and sale of interruptible power would be established in negotiations. The cost of interruptible power established in negotiation would be influenced by those decisions, as well as our mutual assumptions for line loss. We stand ready to negotiate these issues. 17: What limits does the Ketchikan financing plan place on Ketchikan’s current loans and future borrowings? KPU has attempted to seek a compromise financing plan whereby the City of Ketchikan would accept the $20 million loan authorized by the state in 1993. We proposed in return that the State of Alaska offset power rates such that KPU could cover debt service and O&M costs. Under this plan, Ketchikan’s future borrowing ability would have been severely impacted. An analysis demonstrating this was prepared recently by Alan Dashen and is provided as attachment (G). This funding plan has since been abandoned by the City. KPU has recently proposed that a mutually satisfactory solution might be to devote the cash flow set aside in the 1993 legislation for the Southeast Intertie (40% of the Four Dam Pool payment to the State) to a bond issued by the State for the project. This would provide sufficient capital to cover most of the current shortfall. KPU would propose that the $20 million currently set aside by the State for the $20 million loan would be released for other purposes. This proposal is provided as attachment (A). KPU stands ready to negotiate the specific details of the plan. As an alternative, the $20 million could be used for Intertie construction thus requiring reduced bonding by the state for the remaining shortfall. 18. How will project insurance be provided and has the cost been included in the cost of power? We assume the mechanism, cost and responsibility for project insurance would be subject to negotiation. Through that process we can evaluate the impact of insurance, and other factors, on the negotiated cost of interruptible power. 19: What is the security for failure to make bond payments? We have proposed that AIDEA issue a bond with payments guaranteed by the State of Alaska through allocation of 40% of the Four Dam Pool debt service payments. This proposal presents a variety of issues to be considered and negotiated. We stand ready to work with AIDEA to define the security for the bond, and resolve other issues associated with this proposal. Statewide Questions 1. What is the long-term benefit to the State of the SE Intertie? The long-term benefits to the State of Alaska are: A) B) 2. Additional revenue to the State through sales of additional energy from the State’s Tyee project, and; Improved infrastructure directly supporting the viability of Southeast Alaska, a region geographically and economically vital to the State. What are the benefits of distributed vs. inter-connected generation for the Southeast? We believe the benefits of the Southeast Alaska Intertie can best be summarized by the following two quotations: 3. Swan-Tyee Intertie Final EIS “The underlying purpose and need to which this project responds is for KPU to 1) provide a reliable and efficient source of power for the City of Ketchikan’s intermediate and long-range needs at reasonable rates while 2) establishing an important link in the long-proposed electrical network for southern Southeast Alaska so the 3) more communities would have access to more power sources or more power customers.” [pg. 1-6] Southeast Alaska Electrical Intertie System White Paper (developed by Southeast Alaska communities December 1997) “At present, most every community in Southeast Alaska generates its own power in a largely isolated electrical environment. In an area with rich hydroelectric potential, most smaller communities remain entirely diesel dependent. Even in larger communities such as Juneau, Ketchikan and Sitka which currently have hydroelectric power, those facilities are reaching the limit of their capacity and supplemental diesel power is being pursued or contemplated. This, despite the fact there is adequate hydroelectric potential to serve all of Southeast for decades to come if an intertie system existed to transport power to the load centers. The communities of Southeast Alaska therefore support the concept of a southeast electric grid as a means of reducing or avoiding diesel dependence, encouraging economic development and stabilizing and equalizing power rates.” What is the current financing plan including specifics? KPU invested significant time and energy into a financing plan whereby the City of Ketchikan would accept the $20 million loan authorized by the state in 1993. We proposed in return that the State of Alaska offset power rates such that KPU could cover debt service and O&M costs. Although this plan seemed to offer the best compromise, it was ultimately not acceptable to either the State or the City. The State was concerned that rate reduction was excessive, and our analysis demonstrated that the financial burden to the City was unacceptable. KPU has recently proposed that a mutually satisfactory solution might be to devote the cash flow set aside in the 1993 legislation for the Southeast Intertie (40% of the Four Dam Pool payment to the State) to a bond issued by the State for the project. This would provide sufficient capital to cover most of the current-shortfall”” KPU would propose that-the-$20.million currently set aside by the. State for the $20 million Joan n would be released for other purposes. eo This proposal is provided as attachment (A). KPU stands ready to negotiate the specific details of the plan. 4. What are the economic benefits of the Southeast transmission corridor for multiple uses such as fiber optics, communications, etc.? Although the current design for the Swan-Tyee Intertie does not include provisions for fiber optics, that can be modified if that appears to be economically justified or desirable. In fact, KPU has been in contact with Alaska Fiber Star regarding a fiber spur between Juneau and Ketchikan via Petersburg and Wrangell. If the inclusion of fiber optics in the design is an option AIDEA or others wish to pursue, KPU is prepared to negotiate the terms and revise the design. With respect to other multiple uses, the Final EIS offers our best and most comprehensive review of this matter. In particular, the corridor was specifically routed along a logical road corridor to minimize environmental impact of that future development. d: What municipal actions are necessary to implement the financing plan? The City of Ketchikan has approved the concept as presented in attachment (A). The City can continue to act as the project manager and would take such action as we have in the past to authorize and oversee project activities. City Council approval would be needed to ratify a power sales agreement with the Four Dam Pool and if needed a financing agreement with the State of Alaska. Regional Questions 1. What are the current SE Intertie project costs assumed for Four Dam Pool debt service, R&R, and Four Dam Pool O&M costs? As an interruptible power sales agreement has not been executed with the State and the Four Dam Pool, these issues are all subject to negotiation. Generally KPU assumes that construction of the Intertie would be state owned, that energy would be sold to KPU at or near current Four Dam Pool rates but is dependent on KPU’s continuin “and “responsibility for the proj ‘project. These are issues KPU assumes are subject to negotiation and we stand ready to begin that process with the State and the Four Dam Pool. a? 2. What is the cost of power sensitivity in Petersburg, Wrangell, and Ketchikan to extended transmission line outages, e.g. 60 days, between Ketchikan and Swan Lake and between Tyee Lake and Swan Lake? Our view of the Swan-Tyee Intertie is that it allows the additional sale of available Four Dam Pool power, economically benefiting the State and the Four Dam Pool communities through revenue from an interruptible sales agreement. An outage today between Swan Lake and Ketchikan would not have a defined cost of power sensitivity, the sale would simply resume at the wholesale rate when service was restored. Lost revenue from that outage would ultimately be taken into account in setting the Four Dam Pool rate for the next year. We have a similar view of an outage that would affect a Four Dam Pool interruptible sale to Ketchikan over the Intertie. The thrust of this question may be to suggest terms in an interruptible power sales agreement that would define costs, risks and responsibilities for outages. KPU stands ready to negotiate those terms. 3. What is the cost of power impacts of extreme high and low water scenarios of Tyee and Swan Lake occurring together or in opposition? Raytheon Infrastructure Services conducted an intertie operations study in April, 1995 to evaluate the combined operation of Tyee and Swan Lake provided as attachment (B). This study includes consideration of historical water availability, but it does not draw conclusions regarding the rate impact of extreme conditions. Our view is that analysis of cost of power impacts for abnormal conditions at any of the Four Dam Pool projects cannot be considered in isolation, because the costs and revenues are ultimately pooled. For example, in a given year low water conditions at Terror Lake may be balanced by high water conditions in the Swan-Tyee system, resulting in no impact to the Four Dam Pool cost of power. We assume however that the impact of extreme low water conditions in the Swan-Tyee system would result in a reduction of interruptible Tyee sales to Ketchikan as Petersburg and Wrangell have first right to that power. 4. How do you see the revenues, costs, and risks being shared among the State, Four Dam Pool, Petersburg and Wrangell, and Ketchikan? Our view is that the sale of Tyee power to Ketchikan would be defined under an interruptible sales agreement. Ultimately, all these terms are subject to negotiation. We see a negotiated allocation of revenue to the State and the Four Dam Pool communities for the additional sales. Previously, there has been reluctance by the State and Four Dam Pool to accept either costs or risks associated with the project. Therefore, KPU has been prepared to negotiate an assumption of various costs and risks, provided the City has reasonable compensation for those costs and risks. On the other hand, we are prepared to negotiate a division of those risks, costs and compensation with the State and Four Dam Pool. Further, we have always viewed this project as an improvement to the Four Dam Pool facilities and are open to negotiating the addition of this project to those facilities. Ds What are the reductions in generation reserves for Petersburg, Wrangell, and Ketchikan resulting from the Intertie and how do these reductions impact cost of power for each city? Please note our response to question 3 above. The Raytheon study utilizes a certain operational model based on assumed monthly loads and average reservoir inflows. The generation reserve, or combined storage depicted in this model varies by month and year. An example is shown for the year 2013 in figure 5. However, Petersburg and Wrangell have a first right to Tyee power and we assume this would have to be protected through responsible reservoir management, just as we manage our reservoir levels today to avoid extreme conditions. 6. Are there opportunities for British Columbia sales or generation purchase which are enhanced by the SE Intertie? An electrical intertie with British Columbia has been considered by various studies and at various locations. Our view is that the development of a grid in Southeast Alaska creates a greater pool of both resources and loads creating more potential for either future sales or generation purchase with the North American grid through BC Hydro. Ketchikan Questions Te How has the actual capital and O&M cost of the new KPU diesel generation impacted the cost of power? R. W. Beck has recently calculated our avoided cost of electrical generation. That document is provided as attachment (C). We refer you to tables 6 - 8 for detail of diesel costs. KPU rates have not been adjusted as a result of the addition of the new diesel engine. The City Council has largely concluded a review of KPU’s budget and has eliminated a 5% rate increase from KPU’s 1999 budget request. 2: How do you see the SE Intertie affecting the Mahoney Lake project and vice versa? Our view of the interrelationship of the Intertie and various small hydro projects, including Mahoney Lake, is best detailed in attachment (F). Ss What is the wholesale cost of power, escalation indices, reliability factors, and term of Mahoney Lake and 4 Dam Pool proposals for the power sales agreements? KPU has not received any detailed proposals for the purchase of Mahoney Lake power. We have a general proposal from AP&T to purchase power at the Four Dam Pool wholesale rate or our avoided cost, whichever is greater. KPU had provided a draft interruptible power sales agreement to the Four Dam Pool under our previous financing plan, which ultimately was not acceptable to either party. We are prepared to enter into negotiations for a revised interruptible power sales agreement Intertie power. We would expect to negotiate these issues in that process. 4. How do ISER load growth predictions for 1998 compare to actuals? What new industries have been included in ISER projections? What new industries may occur or be attracted to Ketchikan and what is the impact cost of power (e.g. 10 MW industrial load in 2005)? What is the impact (e.g. a 10 MW hydro plant) independent power producer on-line in 2005 on the cost of power? ISER projections for 1998 compared to our estimated actual for 1998 are: ISER base case: 146,117 MWH ISER high case: 147,607 MWH ISER low case: 145,794 MWH Estimated actual 1998 gross generation: 164,000 MWH The summary of the ISER study is provided as attachment (H). ISER notes that they make conservative assumptions for the base case. Further, they note that they do not include new large scale commercial or industrial load in their projections. For example, they exclude the KPC sawmill because of the future uncertain of the timber industry even though KPU currently serves this load. The cost impacts of additional load and/or additional generation (independent or otherwise) are best detailed in attachment (C). 5 What is the impact of the transmission right-of-way maximum timber sales or no sales, storage, and disposal on the cost of power? Attachment (E) considers various approaches to construction sequencing and timber handling. It also includes a comparison of capital costs for different timber sales assumptions. Generally KPU assumes that construction of the Intertie would be state owned, that energy would be sold to KPU at or near the wholesale rate depending on KPU’s continuing risk and responsibility for the project. We view the cost of power as being a negotiated rate in an interruptible power sales agreement. We stand ready to enter into those negotiations with the State and the Four Dam Pool. 6. What is the cost of power impact of failure to receive the $4M appropriation (e.g. for 2 years). Failure to receive state and federal grant funding in general will result in delayed construction and completion, whether that is one year or ten years. The City of Ketchikan has proposed a financing scheme in attachment (A) that does rely on the 40% Four Dam Pool debt service allocation set up by the State in 1993, but also releases $20 million for other uses. Additionally, the existing federal funding of $10 million will lapse if not used by end of the federal fiscal year 2000. See also our response to question 10 below. Ze What is the impact of Intertie 25% capital cost overrun and/or 25% O&M cost overrun on cost of power? We assume that these impacts would be defined in a negotiated interruptible power sales agreement. Generally KPU assumes that the Intertie would be state owned, but we are prepared to negotiate an assumption or division of risk and reward, including those associated with the capital cost of the project. We stand ready to begin that process with the State and the Four Dam Pool. 8. What are the costs of power impacts of necessary coordinated and limited scheduled outages on Tyee Lake and Swan Lake on the communities? Please see our response to Regional Question 2. 9. What is the term of the current EIS/ROD? The EIS and Record of Decision do not have a defined term. We are advised by our consultant and the USFS that the more time that passes before construction begins, the greater risk we have that a successful argument will be made that conditions have changed enough over time to warrant a supplemental EIS. 10. What are the KPU action plans if they fail to receive any additional Federal grants? Failure to receive additional federal funding in general reduces the state’s incentive to pursue bonding of the project. KPU plans in the absence of sufficient federal/state funding for the Swan-Tyee Intertie are best described in Attachment (F). See also response to Ketchikan question 6 above. 11. What is the impact on the cost of power of Tyee energy (e.g. 6.8 cents/KWH or interruptible rate, say 4.0 cents/KWH)? Our view of the Swan-Tyee Intertie is that it allows the additional sale of available Four Dam Pool power, economically benefiting the State and the Four Dam Pool communities through revenue from an interruptible sales agreement. The interruptible rate is subject to negotiation. The additional revenue received from those interruptible sales would be allocated to the State and Four Dam Pool. The resulting benefit to the communities and projects could be calculated for a variety of rate scenarios. We stand ready to negotiate the terms of an interruptible sales agreement, and perform associated calculations estimating the beneficial impact of those sales to the State and Four Dam Pool communities. 12. Will compensation (SVC) be required for the Intertie. What is the cost of power impact? The addition of a static var compensator (SVC) to the design has been discussed, but is not currently included in either the design or the cost estimate. 13. What is the Intertie cost of power difference between the second best alternative and the SE Intertie for low, medium, and high growth scenarios and what amount of investment does the reduction justify? Generally KPU assumes that construction of the Intertie would be state owned, that energy would be sold to KPU at or near the wholesale rate depending on KPU’s continuing risk and responsibility for the project. The avoided cost calculation is provided as attachment (C). That calculation assumes the Intertie is not constructed and that KPU proceeds with the small hydro alternative detailed in attachment (F). To compare the costs of our preferred alternative (the Intertie) with our second best alternative (small hydro), one is comparing our negotiated interruptible rate to the avoided costs detailed in attachment (C). The thrust of this question may to be establish the economic value to KPU of pursuing the Intertie over the alternative. Since the interruptible rate is not yet negotiated, we would propose that economic value be established through the negotiation process. 14. What is the impact on the cost of power of actual capital cost, shorter life, higher fuel cost, and higher O&M cost for the new diesel? All of these variables could be modified in the models presented in attachment (C). Also see our response to Ketchikan question 1 above. 15. What are the impacts of current and future air quality regulations and diesel emissions on cost of power and Ketchikan future growth? Our construction permit is provided as attachment (D). The operating limitations are detailed on page 8/19, section IV.A.5. At this point, the hourly limitations are set significantly higher than we have required in the past. We do not expect to exceed these limitations for some years, at which point we hope to have augmented our hydroelectric supply decreasing our reliance on diesel generation. This could change if the Intertie was not to be built and for one reason or another Whitman and Connell Lakes were not deemed to be economically developable as a result of FERC or other agency requirements. 16. What is the cost of power impact of 1% vs. 3% line losses? We assume that establishing the point of metering and sale of interruptible power would be established in negotiations. The cost of interruptible power established in negotiation would be influenced by those decisions, as well as our mutual assumptions for line loss. We stand ready to negotiate these issues. 17. What limits does the Ketchikan financing plan place on Ketchikan’s current loans and future borrowings? KPU has attempted to seek a compromise financing plan whereby the City of Ketchikan would accept the $20 million loan authorized by the state in 1993. We proposed in return that the State of Alaska offset power rates such that KPU could cover debt service and O&M costs. Under this plan, Ketchikan’s future borrowing ability would have been severely impacted. An analysis demonstrating this was prepared recently by Alan Dashen and is provided as attachment (G). This funding plan has since been abandoned by the City. KPU has recently proposed that a mutually satisfactory solution might be to devote the cash flow set aside in the 1993 legislation for the Southeast Intertie (40% of the Four Dam Pool payment to the State) to a bond issued by the State for the project. This would provide sufficient capital to cover most of the current shortfall. KPU would propose that the $20 million currently set aside by the State for the $20 million loan would be released for other purposes. This proposal is provided as attachment (A). KPU stands ready to negotiate the specific details of the plan. As an alternative, the $20 million could be used for Intertie construction thus requiring reduced bonding by the state for the remaining shortfall. 18. How will project insurance be provided and has the cost been included in the cost of power? We assume the mechanism, cost and responsibility for project insurance would be subject to negotiation. Through that process we can evaluate the impact of insurance, and other factors, on the negotiated cost of interruptible power. 19. What is the security for failure to make bond payments? We have proposed that AIDEA issue a bond with payments guaranteed by the State of Alaska through allocation of 40% of the Four Dam Pool debt service payments. This proposal presents a variety of issues to be considered and negotiated. We stand ready to work with AIDEA to define the security for the bond, and resolve other issues associated with this proposal. KETCHIKAN PUBLIC UTILITIES KETCHIKAN, ALASKA 99901 2930 TONGASS AVENUE October 2, 1998 MUNICIPALLY OWNED ELECTRIC TELEPHONE WATER Randy Simmons, Executive Director Alaska Industrial Development and Export Authority 480 West Tudor Road Anchorage, AK 99503 Dear Randy, Last evening Ketchikan City Council unanimously approved my recommendation to seek funding for the Swan-Tyee Intertie from the state as described in the attached memorandum - I had provided Caitlin a draft copy at Southeast Conference last week. I want to make sure this information is in your hands and (through you) Governor Knowles’ just as soon as possible, since he is scheduled to be in Ketchikan next week. On the related issue of federal funding, we are still hopeful that the FY99 Energy & Water Development appropriations bill will inciude additional funding for the intertie. Per Dennis McCrohan’s suggestion, we look forward to discussing intertie funding with you once the appropriations bill has cleared congress. We do appreciate your interest in finding a way to make this project move forward. It is also heartening to be able to identify ail Southeast Alaska utilities, Southeast Conference and Ketchikan Electric Company (AP&T) as supporters of this approach. Thanks, again! Sincerely, ohn A. Magyar General Manager JAM:klo Attachment G:\USERUOHNM\WINWORD\PUBLIC\IT81002.DOC TELEPHONE 907-225-1000 FAX 907-225-1888 KETCHIKAN PUBLIC UTILITIES Memorandum To: The Honorable Bob Weinstein & Cif~Council From: John A. Magyar, KPU General Manag Date: September 25, 1998 Subject: SE Alaska Intertie (Swan-Tyee) Funding Request This is to request City Council authorization to seek funding from the State of Alaska generally as set forth in the attached Community of Ketchikan Legislative Liaison project document and to seek support for this funding approach from other interested parties in southeast and throughout the state of Alaska. In answer to some questions you may have: ¢ Why would the Four Dam Pool communities/operating utilities support this? Because construction of the intertie will permit full utilization of the Tyee Project and reduce per kWh operating costs to these utilities and their rate payers. Four Dam Pool support for the intertie is greater than it has ever been and, I believe this funding approach and the possibility of speeding up the project has great support by the the Four Dam Pool communities. e Why would the state consider bonding for the intertie? Because construction of the intertie will: (1) improve efficiency and future revenue generation of the Four Dam Pool projects which is strongly supported by the voters in the Four Dam Pool communities and the operating utilities; (2) begin construction of a SE Alaska electrical grid that is universally supported by communities and utilities throughout SE Alaska (including Cape Fox Corporation and Alaska Power and Telephone); (3) allow construction of the intertie to go forward with just a little more funding help from state/federal sources; and, (4) allow $20 million to be freed up for PCE, rail belt utilities or other state uses. ¢ Why would such entities as Cape Fox Corporation and Alaska Power and Telephone support the intertie? Because the intertie will serve as a highway for electrical generation from the Lake Mahoney Project. It creates other generating and marketing possibilities and it opens the door for AP&T to participate in construction of this line. It is my intent to seek a resolution from City Council supporting this funding plan after further discussions with the PMC, Southeast Conference, etc. Recommended Motion: I move that the City Council direct the KPU General Manager to seek funding from the State of Alaska generally as set forth in the attached Legislative Liaison project document. JAM:klo Atachment G:\USER\KORRYO\WINWORD\COUNCIL\007-A8MM.DOC Cunmmmu Nit f OF KETCHIKAN SOUTHEAST ALASKA - ELECTRIC INTERTIE Funding Sources Requested $ 4,400,000 Matching/Local Total - Annual $ 4,400,000 PROJECT SUMMARY: The SE Alaska Intertie is a proposed 57 mile transmission line connecting the Four Dam Pool hydroelectric projects at Swan Lake on the Upper Carroil Inlet and Lake Tyee on the Bradfield Canal. STATEMENT OF NEED AND SUPPORT: e The SE Intertie has been rated the number one regional priority by the community of Ketchikan since the late 1980s. The electrical power so badly needed by Ketchikan is readily available as surplus at Lake Tyee. e Surplus energy sold at Lake Tyee will directly benefit utility rate payers in the Four Dam Pool communities of Kodiak, Copper Valley, Petersburg, Wrangell and Ketchikan. e It will help reduce dependence on back-up diesel generation and the attendant air emissions. e It is universally supported by southeast Alaska operating utilities and communities, by the Southeast Conference, by the Four Dam Pooi operating utilities and communities, by Ketchikan Electric Company which is the co-venture firm of Cape Fox Corporation and Alaska Power & Telephone. e It is the first leg in a regional electrical grid that will provide efficient and reliable electrical power to the residents of southeast Alaska from Juneau, to Sitka, Petersburg, Kake, Wrangell, Ketchikan, Metlakatla, and eventually Prince of Wales Island communities. PRO. STATUS: The EIS for the SE Intertie is complete and the US Forest Service has issued its Record of Decision which has withstood appeal. Design work is complete. Other permits from the Corps of Engineers, Coastal Zone Management and other regulatory agencies are in the final stages. The two-year construction phase can begin as soon as a complete funding program is in place - as early as the summer of 1999. . FUNDING STATUS: Estimated Intertie Cost with Domestic Timber Credit $73,200,000 State Grants Authorized/Received $11,200,000 Federal Grants Authorized/Received 9,900,000 State Loan Authorized (has not been accepted by voters) 20,000,000* Federal Grant Anticipated in FY99 Budget 7,500,000 Total Funding Available/Anticipated 48.600.000 Funding Needed $24,600,000 *Funding Needed (If $20 million loan declined by Ketchikan) $44,600,000 r ( PROPOSED FUNDIN ON: | Only the funding shortfall is standing in the way of SE Intertie construction. Ketchikan is asking the state to bond for the $45 million to build the intertie and to utilize 40% of the Four Dam Pool debt service payment (approximately $4.4 million per year) to create a revenue stream for payment of this bond. (This is not new funding. In 1993 the Alaska State Legislature passed and the governor signed into law legislation allocating 40% of the Four Dam Pool debt service payments to fund the SE Intertie). The state has set aside $20 million as a low interest loan for the construction of the SE Intertie. Ketchikan will not need or accept this loan if the state assumes bonding responsibility for the SE Intertie; and, the $20 million can be put to other state efforts. ‘ Raytheon infrastructure Py Center Building 206 451 4500 kK ¥76 Services Incorporated it N.E. 8th Street FAX 206 451 4980 C Suite 500 SZ3F92X Bellevue WA 98004-4405 = 1995 neR ee April 26, 1995 KP4) Managar’s Cffica HETEMIMAN PUBLIC UTHLATIES RK0001.LTR Mr. Richard Trimble Ketchikan Public Utilities 2930 Tongass Avenue Ketchikan, Alaska 99901 Dear Mr. Trimble: SUBJECT: | SWAN LAKE INTER TION: Yy The following is our analysis of the operations of the combined Ketchikan and Petersburg/Wrangell systems with particular focus on the combined operations of the Swan Lake and Tyee Lake hydroelectric projects. For purposes of comparison, the projects were also considered in isolation within their respective systems. The focus of the study was the determination of the amount of energy that could be transmitted between the existing Petersburg/Wrangell electrical system and that of the Ketchikan system with the intertie. Other issues considered were the time frame in which the Petersburg/Wrangell system load would largely utilize the full capacity of the Tyee Project as well as a verification of average annual and firm energy for the Tyee Project. The following pages present the results of the study and the assumptions used. ASSUMPTIONS AND DATA USED IN THE ANALYSIS Data used in the analysis was based on previously performed studies as well as more recently recorded electrical load and generation data. Hydrologic information was taken from the evaluation report for the Swan Lake Project and from the license application for the Tyee Lake Project. Historical and projected load growth data was obtained from the 1990 report prepared by the Institute of Social and Economic Research (ISER Report). ™~ Based on proj id equipment descriptions, the Swan Lake units we simulated with a total capacities were estimated to be 1,100 cfs and 240 cfs respectively. Turbine efficiencies were assumed to be 90% throughout the analysis. Further discussion with the utilities indicates that slightly lower ratings are probable, soneve the > energy results are not materially affected by the capacity value. a The Crystal Lake Project, which serves only Petersburg, was assumed to have an annual average generation of 10,000 MWh. -This is the same assumption as was used in the 1992 report on the intertie "Lake Tyee-Swan Lake Transmission Intertie, Final Report" (R.W. Beck & Associates, 1992). =< = at ‘ / Vg ‘7 capacity of 26 MW and the Tyee Lake units a capacity of 25 MW, Associated peak hydraulic ‘ ? Mr. Richard Trimble April 26, 1995 Page 2 The monthly pattern of energy available from the Crystal Lake Project was assumed to be distributed similar to the three KPU hydroelectric projects. The three KPU hydroelectric projects are assumed to contribute 62,700 MWh to the Ketchikan system based on the 1992 R.W. Beck report. Evaluation of the hydroelectric operations for the two projects was based on flows developed during feasibility studies for the projects. Overlapping periods of record available were those for water years 1952 through 1960 and were used in this study as the base water years for determining the generation expected from each project. Because of this limited overlap period, the period used in the evaluation was compared to the longer term records developed for the individual projects to characterize the overlapping records used in the evaluation. Table 1 provides the flows used in the analysis as well as a comparison to the longer term average flows available for each project. As can be seen in Table 1, the eight year period used closely approximates the long term record on an annual basis with some differences occurring in the averages for individual months. The January through April periods were generally found to be the more critical months in the operations study, corresponding to generally lower than average estimated-inflows. The-operation study is thus based on a variety of water conditions. such as will be encountered over a longer term period of record. Of particular note is the somewhat critical low inflow occurring between January 1956 and December 1958. HISTORICAL AND PROJECTED LOADS The electric load forecast report prepared by the Institute of Social and Economic Research in 1990 (SER Report) provided historical load data as well as load projections through the year 2010. Projected and historical loads for the Petersburg/Wrangell system as presented in that report are shown in Table 2. Historical and projected loads for the Ketchikan system, including the load utilized by the mill, also as presented in the report are shown in Table 3. The combined system loads as developed from the ISER report are shown in Table 4. Projected loads beyond the year 2010 in each of the tables were extrapolated using an average annual load growth of 1.3 percent, a value consistent with growth rates for that time frame in the ISER report. Based on the projected loads, Figure 1 depicts the distribution of loads within the combined regional system in the year 2013, the year projected to have the greatest potential for the net transmission of energy over the intertie. METHOD OF ANALYSIS The Swan Lake, Tyee Lake, and combined electrical systems were evaluated using a linear programming model (ACRES Reservoir Simulation Program) suitable for analyzing both isolated projects as well as combined or parallel systems. Inflows into the project were those discussed Mr. Richard Trimble April 26, 1995 Page 3 previously for the overlapping period of record available for water years 1952 through 1960. The simulation was based on monthly periods with average system loads for the combined Ketchikan, Petersburg and Wrangell service areas imposed by month. Successive computer runs were then made with the historical load shape imposed in order to determine average annual and firm energy and performance during a critical period. For purposes of evaluating the combined system, essentially all of the existing resources were considered. These other resources, in addition to the Tyee and Swan Lake projects, included the three existing hydro units within the KPU system, KPU diesel, and the Crystal Lake Project at Petersburg. The combined systems operation model utilized an imposed load and shape as a generation target. Target generation levels were developed by using the existing loads as an indicator of required monthly generation, projected total annual loads, and reducing the monthly requirements by the estimated energy from other sources such as the three KPU hydros and the Crystal Lake Project. Successive model runs were then made at increasing demands in order to determine a critical period and the ultimate load that could be served by the combined Swan Lake and Tyee Lake projects. RESULTS OF ANALYSIS Table 5 shows the projected Lake Tyee net energy transmission to Ketchikan through the year 2072. As isolated projects, potential average annual energy generation was found to be consistent with past studies and reports. Swan Lake was found to have average annual energy potential of approximately 84 Gwh and the Tyee Project approximately 128 GWh. R.W. Beck estimated (R.W. Beck, 1992), average generation for the Swan Lake Project to be 82 GWh and average generation at the Tyee Lake Project to be 134.4 GWh. Through evaluation of the Tyee Project in isolation, it was determined that the Tyee Project alone could supply approximately 200 percent of the existing Petersburg/Wrangell load. Based on projected loads this would result in the project being capable of supplying the power for that system until the year 2072. Until that time, unused generation potential at Lake Tyee would result in greater spill and less than best use of the available water resource. Evaluation of the combined system, considering all generating resources, allowed for the determination of the energy generation and utilization by resource and load. Figure 2 provides a graphical depiction of the resource mix that is projected for the year 2013. This generation allocation can be compared to the projected demands shown in Figure 1. Based on the combined system, Figure 3 presents the projected energy mix for Ketchikan, with the intertie, from the present to the year 2015. Table 5 shows the projected Lake Tyee net energy transmission to Ketchikan through the year 2072. Figure 4 presents the projected regional energy mix with the intertie in place. Mr. Richard Trimble April 26, 1995 Page 4 Of the nine years used in the analysis, a three year period was found to be a possible critical period for the generation from the combined Swan Lake and Tyee Lake projects. This period of limited reservoir inflow would result in substantial reservoir drawdowns, thereby limiting generation for that period. Figure 5 presents the reservoir response over this critical period and depicts the changes in the combined reservoir system storage. The results of the analysis provide a good indication of the benefits of an integrated Swan Lake- Tyee Lake System. Further, benefits in real time operation (as opposed to the monthly simulation model contained herein) may be realized. With the addition of stream gaging and lake level monitoring equipment at Tyee Lake, performance benefits may be able to be improved. Integrating the hydraulic information with snowpack data (collected by the Soil Conservation Service) will permit a forecaster to include the implicit water storage in the snowpack in the planned operation of the project. The reservoirs would be drawndown in anticipation of spill to capture additional generating opportunities. Under drier conditions, the reservoirs could be maintained at higher levels than simulated in order to provide incremental benefits to the net head and hence to the overall energy generation per unit volume of water. This reservoir management practice is referred-to-as hedging. A side benefit of hedging is increased insurance for meeting a drought more severe than that which occurred in the 1950’s as well as additional reliability in the event of a forced outage elsewhere in the integrated system. Operation under higher heads may also enable operation of both projects closer to optimal and increase the overall efficiency. INCLUSION: With the intertie in place, the existing potential of the Tyee Project would result in a net transfer of 42,415 Mwh into the Ketchikan system under 1999 estimated demands. Energy delivered to the Ketchikan area could continue to rise to a peak of 73,739 MWh in 2013 under the ISER Base forecast. Under a projected load growth scenario of 1.3 percent per year for the combined system a net transmission of energy could continue to occur until the year 2072, at which time the Petersburg/Wrangell loads would require the full energy output of the project. Sincerely, capi Jeff Project Manager Attachments: Tables 1-5 Figures 1-5 (Color - Figure 3 is 2 pgs) Analysis Output (8 sheets) JP:kk\kpu\rk0001.Itr | / Table 1. Hydrologic Record used in analysis. Water Year 1952 1953 1954 1955 1956 1957 1958 1959 1960 Average Long-term Average 1/ % of Long-term Average Water Year 1952 1953 1954 1955 1956 1957 1958 1959 1960 Average Long-term Average 2/ % of Long-term Average Oct 526 641 1081 874 1008 660 366 1130 832 790.9 764.9 103.40% 93.25% 110.28% 65.89% 114.39% Oct 150 325 361 242 198 192 176 475 348 274.1 275.2 99.60% 107.00% 111.01% 83.94% 86.15% 72.10% 100.21% 116.58% 95.08% 99.65% 102.39% 90.31% 99.73% ‘Swan Lake Inflows (cfs) Nov Dec Jan 393 367 147 483 341 151 666 487 12 996 nT 277 353 129 55 605 S47 164 542 244 536 586 510 222 700 1020 7 591.6 484.7 211.2 634.4 439.5 320.6 Lake Tyce Inflows (cfs) Nov Dec Jan W 55 22 14 44 25 101 66 28 198 at st 4 29 18 132 133 31 155 55 87 113 84 34 12 186 56 121.1 84.8 39.1 113.2 76.4 46.6 Feb 275 297 959 249 120 89 268 229 270 306.2 267.7 Feb 4 16 122 30 it 4 22 20 33 31.3 36.4 Mar 116 296 87 134 39 95 77 44 428 200.7 247.2 Mar 15 21 16 21 i 13 24 25 34 20.0 27.7 Apr 505 327 164 341 359 298 43 349 588 371.6 359.4 Apr 58 53 MW 39 48 42 7 55 88 52.7 52.6 May ns 924 638 533 885 694 707 607 620 702.6 633.7 May 215 303 138 129 338 236 249 2.4 205 225.2 193.2 1/ Based on water year 1921 to 1960 data from "Swan Lake Project Evaluation Report", R.W. Beck, 1978. 2 Based on water year 1952 to 1978 data from "Tyce Lake Hydroclectric Project - Application for License, Vol. 1", IECO, 1979. Jun 810 576 761 782 632 618 337 824 702 671.3 618.8 Jun 321 338 329 328 277 371 327 376 324 332.3 349.5 Jul 646 505 4166 608 322 4156 131 646 656 492.9 447.1 Jul 338 244 261 301 273 268 207 395 338 291.7 292.7 Aug 502 231 213 740 534 186 68) 387 354 425.3 370.0 Aug 260 170 156 345 350 158 256 225 216 244.0 238.3 Sep 613 17 361 500 311 268 376 428 517 454.6 494.2 Sep 279 230 167 231 150 198 124 77 214 196.7 217.8 Avg 468.1 457.8 501.4 563.9 399.1 391.6 398.9 529.6 573.6 476.0 467.2 81.19% 103.37% 110.87% 108.50% 110.25% 114.96% 91.98% 101.88% Ag 150.5 157.7 146.7 169.5 150.8 149.6 147.2 184.0 185.6 160.2 160.6 Table 2. Forecast and actual loads for Petersburg - Wrangell. Fiscal Year 1987 1988 1989 1990 1991 1992 1993 1988 1989 1990 1991 1992 1993 1994 Petersburg Petersburg Petersburg Petersburg Wrangell From Tyee From Crystal (MWh) 15,461 18,022 19,298 20,891 19,154 22,956 22,713 Lake (MWh) 12,425 12,348 9,783 10,563 13,330 11,287 9,552 From Diesel (MWh) 553 160 1,252 451 587 413 3,188 Subtotal (MWh) 28,439 30,530 30,333 31,905 33,071 34,656 35,453 From Tyee Lake (MWh) 18,341 19,594 19,311 20,537 17,405 18,041 16,803 Wrangell From Diesel (MWh) 1/ 292 186 169 1,944 Wrangell From Mill (MWh) 0 0 0 TIS! 1,653 1,356, 1,178 Wrangell Mill From Tyee (MWh) 6,503 13,218 10,622 1,737 3,501 3,846 5,805 1/ Fiscal year data on Wrangell diesel generation is not available prior to 1990-91. Error should be negligible. 2/ ISER load forecasts are for the calendar year in the second column. Wrangell Subtotal 24,844 32,812 29,933 29,344 22,745 23,412 25,730 Total Wrangell Wrangell & ISER 2/ (MWh) Petersburg Forecast (MWh) 53,283 63,342 60,266 61,249 55,816 58,068 61,183 (MWh) 30,060 31,074 23,885 17,989 16,857 16,947 17,077 Petersburg ISER 2/ Forecast Wrangell & Total ISER 2/ (MWh) Petersburg 29,410 30,368 31,121 31,460 31,477 31,756 32,117 Forecast (MWh) 59,470 61,442 55,006 49,449 48,334 48,703 49,194 Percent of Forecast 89.6% 103.1% 109.6% 123.9% 115.5% 119.2% 124.4% Table 3. Forecast and actual loads for Ketchikan Fiscal Year 1987 1988 1989 1990 1991 1992 1993 1988 1989 1990 1991 1992 1993 1994 3 KPU Hydros (MWh) 70490 72348 61276 62667 76647 68830 65107 Swan Lake (MWh) 55373 63091 55238 74093 73114 83405 70426 KPU Diesel (MWh) 1,567 1,993 17,177 2,361 452 605 12,167 Subtotal KPU (MWh) 127430 137432 133692 139120 150212 152840 147699 1/ ISER Load forecasts are for the calendar year in column 2. KPU ISER Forecast (MWh) 132716 136172 147463 164767 167520 174134 178937 Percent of Forecast 96.02% 100.93% 90.66% 84.43% 89.67% 87.77% 82.54% Table 4. Projected Combined Loads for Ketchikan Public Utilities, Wrangell Electric Department and Petersburg Municipal Power and Light. (source: ISER, 1990) Year Wrangell Petersburg Subtotal Ketchikan Grand Electric Municipal Public Utility Total Department Power and Light 1995 17,081 32,200 49,281 182,172 231,453 1996 17,263 32,597 49,860 183,714 233,574 1997 17,436 33,053 50,489 185,302 235,791 1998 17,651 33,514 51,165 187,978 239,143 1999 17,902 34,041 51,943 189,068 241,011 2000 18,154 34,578 oie 191,196 243,928 2001 18,379 35,056 53,435 193,051 246,486 2002 18,557 35,444 54,001 194,415 248,416 2003 18,744 35,849 54,593 195,692 250,285 2004 18,959 36,319 55,278 197,333 252,611 2005 19,228 36,895 56,123 199,543 255,666 2006 19,539 37,564 57,103 202,148 259,251 2007 19,880 38,294 58,174 205,077 263,251 2008 20,245 39,071 59,316 208,279 267,595 2009 20,603 39,833 60,436 211,476 271,912 2010 20,941 40,547 61,488 214,482 275,970 2011 1/ 21,217 41,081 62,297 217,304 279,601 2012 21,496 41,621 63,117 220,164 283,280 2013 21,779 42,169 63,947 223,061 287,008 2014 22,065 42,724 64,789 225,996 290,784 2015 22,355 43,286 65,641 228,969 294,611 2016 22,650 43,855 66,505 231,982 298,487 2017 22,948 44,432 67,380 235,035 302,415 2018 23,250 45,017 68,267 238,127 306,394 2019 23,556 45,609 69,165 241,261 310,426 2020 23,866 46,210 70,075 244,435 314,510 1/ Energy demand growth at 1.3% beyond 2010, the end of the ISER forecast. Table 5. Projected sources of generation based on the Swan Lake - Lake Tyee Intertie with a 1999 on-line date. Year 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 2016 2017 2018 2019 2020 2021 2022 2023 2024 Total Integrated System — Energy Demand Ketchikan Energy Demand (MWh) (MWh) 202,469 214,216 215,854 222,837 228,131 231,453 233,574 235,791 239,143 241,011 243,928 246,486 248,416 250,285 252,611 255,666 259,251 263,251 267,595 271,912 275,970 279,601 283,280 287,008 290,784 294,611 298,487 302,415 306,394 310,426 314,510 318,649 322,842 327,090 331,394 147,463 164,767 167,520 174,134 178,937 182,172 183,714 185,302 187,978 189,068 191,196 193,051 194,415 195,692 197,333 199,543 202,148 205,077 208,279 211,476 214,482 217,304 220,164 223,061 225,996 228,969 231,982 235,035 238,127 241,261 244,435 247,652 250,910 254,212 257,557 Petersburg Crystal & Wrangell Lake Energy Demand Hydro (MWh) (MWh) 55,006 10,000 49,449 10,000 48,334 10,000 48,703 10,000 49,194 10,000 49,281 10,000 49,860 10,000 50,489 10,000 51,165 10,000 51,943 10,000 52,732 10,000 53,435 10,000 54,001 10,000 54,593 10,000 55,278 10,000 56,123 10,000 57,103 10,000 58,174 10,000 59,316 10,000 60,436 10,000 61,488 10,000 62,297 10,000 63,117 10,000 63,947 10,000 64,789 10,000 65,641 10,000 66,505 10,000 67,380 10,000 68,267 10,000 69,165 10,000 70,075 10,000 70,997 10,000 71,931 10,000 72,878 10,000 73,837 10,000 Wrangell & Petersburg Ketchikan Energy Demand From Tyee Hydro (MWh) (MWh) 45,006 39,449 38,334 38,703 39,194 39,281 39,860 40,489 41,165 41,943 42,732 43,435 44,001 44,593 45,278 46,123 47,103 48,174 49,316 50,436 51,488 $2,297 53,117 53,947 $4,789 55,641 56,505 57,380 58,267 59,165 60,075 60,997 61,931 62,878 63,837 147,463 164,767 167,520 174,134 178,937 182,172 183,714 185,302 187,978 189,068 191,196 193,051 194,415 195,692 197,333 199,543 202,148 205,077 208,279 211,476 214,482 217,304 220,164 223,061 225,996 228,969 231,982 235,035 238,127 241,261 244,435 247,652 250,910 254,212 257,557 3 KPU Hydros (MWh) 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 Ketchikan From Swan Lake Hydro (MWh) 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 Ketchikan From Other Sources (MWh) 810 18,114 20,867 27,481 32,284 35,519 37,061 38,649 41,325 cecocooeoecooocoocco x g 6,445 10,272 14,148 18,076 22,053 26,087 30,171 34,310 38,503 42,751 47,055 Surplus Tyce Lake Tyce to Energy (MWh) Ketchikan Available (MWh) 82,680 0 88,237 0 89,352 0 88,983 0 88,492 0 88,405 0 87,826 0 87,197 0 86,521 o 85,743 42,415 84,954 44,543 84,251 46,398 83,685 47,762 83,093 49,039 82,408 50,680 81,563 52,890 80,583 55,495 79,512 58,424 78,370 61,626 77,250 64,823 76,198 67,829 75,389 70,651 74,569 73,511 73,739 73,739 72,897 72,897 72,045 72,045 71,181 71,181 70,306 70,306 69,419 69,419 68,521 68,521 67,611 67,611 66,689 66,689 65,755 65,755 64,808 64,808 63,849 63,849 Table 6 Sheet 1 of 3 Table 5. Projected sources of generation based on the Swan Lake - Lake Tyee Intertie with a 1999 on-line date. Year 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 2058 2059 Total Integrated System Energy Demand (MWh) 335,754 340,172 344,648 349,183 353,778 358,433 363,149 367,928 372,169 377,674 382,644 387,679 392,780 397,948 403,185 408,490 413,865 419,311 424,828 430,418 436,082 441,820 447,633 453,523 459,491 465,537 471,663 477,869 484,157 490,528 496,982 503,522 $10,147 516,860 $23,661 Ketchikan Energy Demand (MWh) 260,946 264,380 267,858 271,383 274,954 278,572 282,237 285,951 289,714 293,526 297,388 301,301 305,266 309,283 313,352 317,476 321,653 325,885 330,173 334,518 338,920 343,379 347,898 352,475 357,113 361,812 366,573 371,397 376,284 381,235 386,251 391,334 396,483 401,700 406,986 Petersburg, Crystal & Wrangell Lake Energy Demand Hydro (MWh) (MWh) 74,808 10,000 75,793 10,000 16,790 10,000 77,800 10,000 78,824 10,000 79,861 10,000 80,912 10,000 81,977 10,000 83,056 10,000 84,148 10,000 85,256 10,000 86,377 10,000 87,514 10,000 88,666 10,000 89,832 10,000 91,014 10,000 92,212 10,000 93,425 10,000 94,655 10,000 95,900 10,000 97,162 10,000 98,440 10,000 99,736 10,000 101,048 10,000 102,378 10,000 103,725 10,000 105,090 10,000 106,473 10,000 107,874 10,000 109,293 10,000 110,731 10,000 112,188 10,000 113,664 10,000 115,160 10,000 116,675 10,000 Wrangell & Petersburg Ketchikan Energy Demand From Tyee Hydro (MWh) (MWh) 64,808 65,793 66,790 67,800 68,824 69,861 70,912 11,977 73,056 74,148 15,256 16,377 71,514 78,666 79,832 81,014 82,212 83,425 84,655 85,900 87,162 88,440 89,736 91,048 92,378 93,725 95,090 96,473 97,874 99,293 100,731 102,188 103,664 105,160 106,675 260,946 264,380 267,858 271,383 274,954 278,572 282,237 285,951 289,714 293,526 297,388 301,301 305,266 309,283 313,352 317,476 321,653 325,885 330,173 334,518 338,920 343,379 347,898 352,475 357,113 361,812 366,573 371,397 376,284 381,235, 386,251 391,334 396,483 401,700 406,986 3 KPU Hydros (MWh) 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 62,700 Ketchikan From Swan Lake Hydro (MWh) 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 83,953 Ketchikan From Other Sources (MWh) $1,415 55,833 60,309 64,844 69,439 74,094 78,810 83,589 88,430 93,335 98,305 103,340 108,441 113,609 118,846 124,151 129,526 134,972 140,489 146,079 151,743 157,481 163,294 169,184 175,152 181,198 187,324 193,530 199,818 206,189 212,643, 219,183 225,808 232,521 239,322 Surplus Tyce Lake Tyce to Energy (MWh) Ketchikan Available (MWh) 62,878 62,878 61,893 61,893 60,896 60,896 59,886 59,886 58,862 58,862 57,825 57,825 56,774 56,774 55,709 55,709 54,630 54,630 53,538 53,538 52,430 52,430 51,309 51,309 50,172 50,172 49,020 49,020 47,854 47,854 46,672 46,672 45,474 45,474 44,261 44,261 43,031 43,031 41,786 41,786 40,524 40,524 39,246 39,246 37,950 37,950 36,638 36,638 35,308 35,308 33,961 33,961 32,596 32,596 31,213 31,213 29,812 29,812 28,393 28,393 26,955 26,955 25,498 25,498 24,022 24,022 22,526 22,526 21,011 21,011 Table 6 Sheet 2 of 3 Table 5. Projected sources of generation based on the Swan Lake - Lake Tyee Intertie with a 1999 on-line date. Year Total Ketchikan Petersburg Crystal Wrangell & Ketchikan 3 KPU Ketchikan Ketchikan Surplus Tyee Lake Integrated System Energy Demand = & Wrangell Lake Petersburg Energy Demand — Hydros From Swan From Other Tyee to Energy Demand (MWh) Energy Demand Hydro From Tyce Hydro (MWh) (MWh) Lake Hydro Sources Energy (MWh) Ketchikan (MWh) (MWh) (MWh) (MWh) (MWh) (MWh) Available (MWh) 2060 530,551 412,341 118,210 10,000 108,210 412,341 62,700 83,953 246,212 19,476 19,476 2061 537,533 417,767 119,766 10,000 109,766 417,167 62,700 83,953 253,194 17,920 17,920 2062 544,606 423,264 121,342 10,000 111,342 423,264 62,700 83,953 260,267 16,344 16,344 2063 $51,772 428,833 122,939 10,000 112,939 428,833 62,700 83,953 267,433 14,747 14,747 2064 559,032 434,476 124,556 10,000 114,556 434,476 62,700 83,953 274,693 13,130 13,130 2065 566,388 440,193 126,195 10,000 116,195 440,193 62,700 83,953 282,049 11,491 11,491 2066 573,841 445,985 127,856 10,000 117,856 445,985 62,700 83,953 289,502 9,830 9,830 2067 581,392 451,854 129,538 10,000 119,538 451,854 62,700 83,953 297,053 8,148 8,148 2068 589,042 457,799 131,243 10,000 121,243 457,799 62,700 83,953 304,703 6,443 6,443 2069 596,792 463,823 132,969 10,000 122,969 463,823 62,700 83,953 312,453 4,717 4,117 2070 604,645 469,926 134,719 10,000 124,719 469,926 62,700 83,953 320,306 2,967 2,967 2071 612,601 476,110 136,492 10,000 126,492 476,110 62,700 83,953 328,262 1,194 1,194 2072 620,662 482,374 138,288 10,000 128,288 482,374 62,700 83,953 335,721 (602) 0 1/ Load forecasts taken from "Electric Load Forecast for Ketchikan, Metlakatla, Petersburg and Wrangell, Alaska: 1990-2010, Final Report (Institute of Social and Economic Research, 1990). Table 6 Sheet 3 of 3 |Integrated KPU, Wrangell and Petersburg System | (Under Year 2013 Demand) 223,061 (77.7%) Ketchikan 42,169 (14.7%) Petersburg | 21,779 (7.6%) Wrangeil Total Demand is 287,009 MWh| FIGURE 1 COMBINED SYSTEM DEMAND Integrated KPU, Wrangell and Petersburg System (Under Year 2013 Demand) 83,953 (29.3%) Swan Lake Total Demand is 287,009 MWh| 10,000 (3.5%) Crystal Lake 62,700 (21.8%) 3 KPU Hydros 2,669 (0.9%) Diesel 127,686 (44.5%) Tyee Lake FIGURE 2 COMBINED SYSTEM GENERATION ~~ i KETCHIKAN ENERGY MIX WITH SWAN LAKE - LAKE TYEE INTERTIE 250 | 200 + | | | | | | I 150 i = | | s a | \| = 3 i ee | | c 3 Ye | ai | | 100 + | | | | | so | | | | | | | | 0 | | Ba ea aes 1995 1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 | 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 | | 33 KPU HYDROS @ SWAN LAKE 0 KPU OTHER 8 LAKE TYE= TO KPU FIGURE 3 - pg.1 KETCHIKAN ENERGY MIX ENERGY MWh Thousands 500 KETCHIKAN ENERGY MIX WITH SWAN LAKE - LAKE TYEE INTEATIE! 400 - 300 200 + 2016 2021 2026 2031 2036 2041 2046 2051 2056 2061 2066 2071 8 3KPU HYDROS a SWAN LAKE 0 KPU OTHER & LAKE TYEE TO KPU FIGURE 3 - pg. 2 KETCHIKAN ENERGY MIX Cc ENERGY MWh Thousands INTEGRATED KPU, WRANGELL & PETERSBURG MIX WITH SWAN LAKE - LAKE TYEE INTEATIE 300 200 100 | 1995 1997 1999 2001 2003 2005 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2007. 2009 «2011 2013 2015 CRYSTAL LAKE @ SWAN LAKE @ KPU OTHER & LAKE TYEE TO KPU 0 TYEE TO WML? & PMPL FIGURE 4 COMBINED SYSTEM ENERGY MIX ( ( COMBINED SWAN LAKE TYEE LAKE Sine (UNDER YEAR 2013 DEMAND CONDITIONS) 250 200 | 150 : $Y a -_ 100 I — o ———— co ? t a a os COMBINED STORAGE KAF 9 a _ a = =~ ao Sa a 50 + | | | | | | ey neo ie WA] |e RE es De AT | Jan-56 Mar-56 May-S6 Jul-S6 Sep-56 Nov-56 Jan-57 Mar-S7 May-57 Jul-S7 Sep-57 Nov-57 Jan-58 Mar-58 May-S8 Jul-S8 Sep-58 Nov-58 Feb-56 Apr-56 Jun-S6 Aug-56 Oct-56 Dec-56 Feb-57 Apr-S7 Jun-57 Aug-57 Oct-S7 Dec-57 Feb-58 Apr-S8 Jun-S8 Aug-58 Oct-58 Dec-58 DATE m COMBINED STORAGE SWAN LAKE a LAKE TYEE FIGURE 5 COMBINED SYSTEM CRITICAL PERIOD RESERVOIR RESPONSE { / ACRES INTERTEL LIMITED ACRES ER RESOURCES SIMULATION PROGRAM ( # AQ1025_3. d 1995-03-25 16:05:40 Tyee Lake and Swan Lake Combined System March 1995 by Bill Shaffer and Mark Killgore PERIOD-END RESERVOIR VOLUME (1000 ac-ft) : 1 Swan Lake Reservoir YEAR OF SIM HYD OTH Oct Nov Dec Jan Feb Mar Apr May June July as Sept 1 1952 1952 123.600 115.131 105.215 89.070 75.505 67.515 50.296 63.026 83.377 101.863 110. 79 123.600 2 1953 1953 123.600 119.077 108.621 92.881 80.221 66.433 66.426 75.576 93.051 102.583 100.490 111.663 3 1954 1954 123.600 120.745 114.731 99.746 104.170 88.420 75.367 81.431 100.913 111.284 108.113 109.391 4 1955 1955 123.600 123.600 122.200 112.082 100.325 85.583 77.093 80.728 100.468 116.106 123.600 123.600 5 1956 1956 122.200 115.745 100.029 86.217 70.599 40.000 40.000 65.910 80.190 88.640 104.350 103.527 6 1957 1957 111.285 109.971 108.604 93.519 82.344 65.402 42.419 56.678 77.733 88.052 87.834 83.426 7 1958 1958 84.619 82.947 71.430 65.077 61.875 40.000 40.000 55.760 75.813 75.697 77.700 75.063 8 1959 1959 110.875 107.885 102.207 88.062 74.756 63.076 62.201 60.070 84.719 107.458 112.107 115.279 9 1960 1960 123.600 121.851 123.600 111.185 99.913 90.872 90.177 100.961 119.145 123.600 123.400 123.555 AVERAGE 116.331 112.995 106.293 93.093 83.301 67.478 60.219 71.127 90.601 101.698 105.399 107.678 MAXIMUM 123.600 123.600 123.600 112.082 104.170 90.872 90.177 100.961 119.145 123.600 123.600 123.600 MINIMUM 86.619 82.947 71.430 65.077 61.875 40.000 40.000 55.760 75.813 75.697 77.700 75.063 ACRES INTERTEL LIMITED ACRES WATER RESOURCES SIMULATION PROGRAM ( # AQ1025_3.05 ) 1995-03-25 16:05:40 Tyee Lake and Swan Lake Combined System March 1995 by Bill Shaffer and Mark Killgore PERIOD-END RESERVOIR ELEVATION (ft.) 3 1 Swan Lake Reservoir YEAR OF SIM HYD OTH Oct uoy ace Jan fe Mar May June uly: a Sept 1 1952 1952 329.000 322. 951 315. 346 306. 248 296. 504 288. 764 276.396 285.540 300.158 313. 137 319. 856 329.000 2 1953 1953 329.000 325.769 318.291 306.985 297.891 287.987 286.544 294.554 307.107 313.954 312.451 320.474 3 1954 1954 329.000 326.961 322.665 311.916 315.094 303.780 294.404 298.760 312.755 320.203 317.926 318.844 4 1955 1955 329.000 329.000 328.000 320.773 312.332 301.743 295.644 298.255 312.435 323.647 329.000 329.000 5 1956 1956 328.000 323.389 312.119 302.198 290.979 269.000 269.000 287.611 297.869 303.939 315.223 314.632 6 1957 1957 320.203 319.261 318.279 307.443 299.416 287.246 270.738 280.980 296.104 303.516 303.359 300.193 7 1958 1958 301.050 299.849 291.576 287.013 284.713 269.000 269.000 280.321 294.725 294.642 296.081 294.186 8 1959 1959 319.910 317.763 313.684 303.524 293.966 285.575 284.947 283.417 301.122 317.456 320.791 323.057 9 1960 1960 329. wat 327.751 329.000 320.132 312.036 305.542 305.043 312.789 325.818 329.000 329.000 328.968 AVERAGE 323. 796 321.410 316.607 307.137 300.103 288.737 283.526 291.359 305.344 313.310 315.965 317.595 MAXIMUM 329.000 329.000 329.000 320.773 315.094 305.542 305.043 312.789 325.818 329.000 329.000 329.000 MINIMUM 301.050 299.849 291.576 287.013 284.713 269.000 269.000 280.321 294.725 294.642 296.081 294.186 ACRES INTERTEL LIMITED PERIOD-END RESERVOIR VOLUME YEAR OF SIM HYD 1952 1953 1954 1955 1956 1957 1958 1959 1960 WONAUE UN AVERAGE MAXIMUM MINIMUM OTH 1952 1953 1954 1955 1956 1957 1958 1959 1960 ACRES WATER RESOURCES SIMULATION PROGRAM ( # A01025_3.05 ) 1995-03-25 16:05:40 Tyee Lake and Swan Lake Combined System March 1995 by Bill Shaffer and Mark Killgore (1000 ac-ft) : 2 BEEEER 3 8 AARIIIIYY nN iy o i # x ~ A t N - a ‘9 - wu tg & BB $s x o & iy x 4 Z 52.016 67.438 32.125 Tyee Lake Reservoir May 42.769 54.463 65.996 71.581 49.879 60.488 66.446 65.138 53.227 65.402 71.883 69.902 52.807 65.124 74.879 79.688 79.688 44.387 52.501 57.732 67.550 67.036 39.1463 51.105 57.365 52.385 54.473 38.621 44.563 42.766 51.086 49.588 41.070 55.281 69.492 72.394 74.366 65.432 77.260 79.688 79.688 79.688 47.479 58.461 65.139 67.712 69.705 65.432 77.260 79.688 79.688 79.688 38.621 44.563 42.766 51.086 49.588 Sept 79.688 72.118 70.701 PAGE 1 AVE 92.548 94.982 103.168 107.487 84.900 84.013 67.195 90.836 93.099 112.765 67.195 PAGE 2 AVE 306.736 308.487 314.365 317.454 301.2466 300.615 288.534 305.514 321.2460 307.132 321.240 288.534 PAGE 3 AVE 59.764 61.125 66.906 69.648 55.021 53.620 43.416 58.571 72.971 ACRES INTERTEL LIMITED ACRES / TR RESOURCES SIMULATION PROGRAM ( # A01025_3/— 1995-03-25 Tyee Lake and Swan Lake Combined System March 1995 by Sill Shaffer and Mark Killgore PERIOO-END RESERVOIR ELEVATION (ft.) : 2 Tyee Lake Reservoir YEAR OF SIM HYD OTH Oct Nov Dec Jan Feb Mar Apr May June July 1 1952 1952 1390.00 1378.02 1361.16 1333.64 1310.52 1269.80 1267.55 1289.25 1323.93 1355.44 2 1953 1953 1390.00 1384.71 1366.96 1340.13 1318.55 1295.05 1262.63 1310.64 1340.42 1356.67 3 1954 1954 1390.00 1387.53 1377.34 1351.83 1359.38 1332.53 1310.28 1320.62 1353.82 1371.50 4 1955 1955 1390.00 1390.00 1390.00 1372.85 1352.82 1327.70 1313.22 1319.42 1353.07 1379.67 5 1956 1956 1390.00 1379.06 1352.32 1314.64 1277.11 1250.00 1250.00 1294.16 1318.50 1332.91 6 1957 1957 1371.50 1369.26 1366.93 1341.22 1305.88 1264.88 1254.12 1278.43 1314.31 1331.90 7 1958 1958 1326.05 1323.20 1303.57 1292.74 1256.82 1250.00 1250.00 1276.86 1294.63 1289.30 8 1959 1959 1370.80 1365.71 1356.03 1331.92 1309.24 1289.33 1256.79 1284.21 1326.22 1364.98 9 1960 1960 1390.00 1371.33 1352.12 1336.71 1384.82 1390.00 AVERAGE 1362.70 1338.92 1315.83 1290.67 1334.42 1352.49 MAXIMUM 1390.00 1372.85 1359.38 1336.71 1384.82 1390.00 MINIMUM 1326.05 1323.20 1303.57 1292.74 1256.82 1250.00 1296.63 1289.30 ACRES INTERTEL LIMITED ACRES WATER RESOURCES SIMULATION PROGRAM ( # A01025_3.05 ) 1995-03-25 Tyee Lake and Swan Lake Combined System March 1995 by Bill Shaffer and Mark Killgore PERIOD CAPACITY POTENTIAL (MW) 3 1 Swan Lake Powerhouse YEAR OF SIM HYD OTH Oct Nov Dec Jan Feb Mar Apr May June July 1 1952 1952 26.000 25.893 25.054 23.878 22.558 21.615 20.532 20.342 21.763 23.473 2 1953 1953 26.000 26.000 25.389 26.202 22.934 21.776 21.081 21.485 22.736 23.938 3 1954 1954 25.735 26.000 25.745 24.787 26.311 23.802 22.523 22.217 23.344 24.685 4 1955 1955 25.631 26.000 26.000 25.690 26.696 23.505 22.477 22.261 23.293 24.882 5 1956 1956 26.000 25.858 26.846 23.515 22.217 20.225 18.961 20.026 21.750 22.746 6 1957 1957 26.803 25.097 26.975 26.230 23.049 21.822 20.108 19.739 21.264 22.611 7 1958 1958 22.711 22.690 22.111 21.404 20.920 19.856 18.961 19.599 21.122 21.985 8 1959 1959 23.504 26.983 264.590 23.698 22.539 21.391 20.851 20.723 21.693 23.783 9 1960 1960 25.900 25.995 26.000 25.713 26.636 23.723 23.287 23.738 25.043 26.000 AVERAGE 25.163 25.391 26.968 26.124 23.095 21.968 20.971 21.125 22.443 23.789 MAXIMUM 26.000 26.000 26.000 25.713 26.694 23.802 23.287 23.738 25.043 26.000 MINIMUM 22.711 22.690 22.111 21.404 20.920 19.856 18.941 19.599 21.122 21.985 ACRES INTERTEL LIMITED ACRES WATER RESOURCES SIMULATION PROGRAM ( # A01025_3.05 ) 1995-03-25 PERIOD AVERAGE ENERGY (MW CONTINUOUS) : YEAR OF SIM = HYD 1952 1953 1956 1955 1956 1957 1958 1959 1960 CONAURWNH AVERAGE MAXIMUM MINIMUM OTH 1952 1953 1954 1955 1956 1957 1958 1959 1960 12.057 16.347 16.976 Tyee Lake and Swan Lake Combined System March 1995 by Bill Shaffer and Mark Killgore E88 erSveSvee NOOO AESES ak oN 0 aS o 1 Swan Lake Powerhouse 9.443 12.527 5.038 16:05:40 1370.67 1390.00 1372.14 1368.27 1390.00 1358.28 1324.02 1309.76 1353.10 1366.10 1390.00 1359.68 1318.16 1314.26 1372.89 1390.00 1359.43 1390.00 1314.26 16:05:40 Aug 26.273 25.012 25.938 23.820 23.057 22.066 25.020 26.000 26.432 26.000 22.066 16:05: Sept 24.683 24.926 26.000 26.489 22.853 22.040 25.375 26.000 24.674 26.000 22.040 40 8.112 14.291 4.054 9.348 12.077 7.230 PAGE 4 AVE 1336.84 1341.11 1357.44 1364.18 1323.40 1320.22 1290.84 1334.09 PAGE 5 PAGE 6 AVE 10.049 10.353 11.2468 12.285 9.155 8.918 8.319 10.167 12.800 12.800 8.319 ACRES INTERTEL LIMITED ACRES PERIOD CAPACITY POTENTIAL (MW) YEAR OF SIM YO 1952 1953 1954 1955 1956 1957 1958 1959 1960 CANOE UNM = AVERAGE MAXIMUM MINIMUM ACRES INTERTEL LIMITED OTH 1952 1953 1954 1955 1956 1957 1958 1959 1960 ACRES WATER RESOURCES SIMULATION PROGRAM ( # AQ1025_3.05 ) IR RESOURCES SIMULATION PROGRAM ( # A01025_3/— 26.762 246.916 25.000 25.000 24.633 24.700 23.195 24.500 25.000 PERIOO AVERAGE ENERGY (MW CONTINUOUS) 3 YEAR OF SIM HYD 1952 1953 1954 1955 1956 1957 1958 1959 1960 WCOENOUEUN= AVERAGE MAXIMUM MINIMUM ACRES INTERTEL LIMITED OTH 1952 1953 1954 1955 1956 1957 1958 1959 1960 ACRES WATER RESOURCES SIMULATION PROGRAM ( # AQ1025_3.05 ) PERIOD CAPACITY POTENTIAL (MW) YEAR OF SIM HYD 1952 1953 1954 1955 1956 1957 1958 1959 1960 DANONE UN AVERAGE MAXIMUM MINIMUM OTH 1952 1953 1954 1955 1956 1957 1958 1959 1960 1995-03-25 Tyee Lake and Swan Lake Combined System March 1995 by Bill Shaffer and Mark Killgore 2 Tyee Lake Powerhouse Mar 22.566 23.017 26.087 23.932 21.852 22.437 21,582 22.813 26.046 Apr 21.989 22.261 2.414 23.389 21.492 21.764 21.492 22.107 23.817 Tyee Lake and Swan Lake Combined System March 1995 by Bill Shaffer and Mark Killgore 2 Tyee Lake Powerhouse May 9.232 4.078 7.972 9.326 10.197 10.313 10.576 6.447 9.529 8.630 10.576 4.078 26.549 26.652 23.532 23.460 22.615 26.078 25.000 1995-03-25 16:05:40 16:05:40 12.745 14.431 21.700 12.008 Tyee Lake and Swan Lake Combined System March 1995 by Bill Shaffer and Mark Killgore Qo TOTAL INTEGRATED POWER SYSTEM 42.592 43.956 45.468 45.537 42.106 41.664 41.449 42.761 47.791 1995-03-25 Sept 14.649 11.411 15.604 23.872 16.020 15.979 14.530 14.710 22.116 16.543 23.872 11.611 16:05:40 49.267 48.607 49.732 50.938 47.917 46.570 44.945 49.743 51.000 50.695 49.231 49.601 51.000 48.937 46.258 45.198 50.283 51.000 PAGE 7 PAGE & AVE 47.269 47.649 48.804 49.170 46.349 46.228 43.885 46.865 49.858 47.342 49.858 43.885 * ACRES INTERTEL LIMITED PERIOO AVERAGE ENERGY (MW CONTINUOUS) YEAR OF SIM CONOUERUN HYD 1952 1953 1954 1955 1956 1957 1958 1959 1960 AVERAGE MAXIMUM MINIMUM ACRES INTERTEL LIMITED OTH 1952 1953 1954 1955 1956 1957 1958 1959 1960 ACRES "R RESOURCES SIMULATION PROGRAM ( # A01025_3./ ACRES WATER RESOURCES SIMULATION PROGRAM ( # A01025_3.05 ) PERIOD AVERAGE CHANNEL FLOW SIM 1 WaANRUPUD YEAR OF HYD 1952 1953 1954 1955 1956 1957 1958 1959 1960 AVERAGE MAXIMUM MINIMUM ACRES INTERTEL LIMITED OTH 1952 1953 1954 1955. 1956 1957 1958 1959 1960 30.658 43.685 29.030 Tyee Lake and Swan Lake Combined System Tyee Lake and Swan Lake Combined System 0 4 March 1995 by Bill Shaffer and Mark Killgore TOTAL INTEGRATED POWER SYSTEM March 1995 by Bill Shaffer and Mark Killgore Swan Mar 245.95 520.24 343.15 373.74 556.64 370.55 532.77 603.99 ACRES WATER RESOURCES SIMULATION PROGRAM PERIOO AVERAGE CHANNEL FLOW (cfs) YEAR OF SIM WANOUNEUNS HYD 1952 1953 1954 1955 1956 1957 1958 1959 1960 AVERAGE MAXIMUM MINIMUM Tyee Lake and Swan Lake Combined System 2 1995-03-25 June 21.700 21.700 21.700 21.700 21.700 21.700 21.700 21.700 21.700 1995-03-25 Lake Power Channel ( # A01025_3.05 ) March 1995 by Bill Shaffer and Mark Killgore 450.26 392.02 264.16 0.00 409.76 583.54 1995-03-25 Swan Lake Spill Channel 16:05:40 Aug Sept 25.120 23.792 25.120 23.250 25.120 23.250 39.291 35.536 25.120 23.250 27.567 23.250 25.120 23.250 25.120 23.250 33.259 34.193 27.871 25.891 39.291 35.536 25.120 23.250 16:05:40 Aug 356.66 265.04 264.58 618.12 278.50 189.55 648.42 311.38 354.00 365.14 648.42 189.55 16:05:40 Aug Sept 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 PAGE 10 AVE 25.062 26.455 26.279 28.056 25.827 25.321 23.129 26.976 30.117 26.133 30.117 23.129 PAGE 11 PAGE 12 ACRES INTERTEL LIMITED acres IR RESOURCES SIMULATION PROGRAM ( # aoto2s 3 1995-03-25 16:05:40 PAGE 13 Tyee Lake and Swan Lake Combined System March 1995 by Bill Shaffer and Mark Killgore PERIOD AVERAGE CHANNEL FLOW (cfs) : 3 Tyee Power Channel YEAR OF SIM HYD OTH Oct Nov Dec Jan Feb Mar Apr May June July Aug Sept AVE 1 1952 1952 150.000 161.983 155.557 186.094 160.960 235.729 70.635 97.350 126.484 150.109 169.167 142.763 150.595 2 1953 1953 261.914 155.698 157.632 184.986 157.598 148.404 234.657 42.721 159.704 147.108 191.276 112.690 161.179 3 1954 1954 237.898 120.422 139.299 180.097 72.217 176.086 145.653 81.629 124.379 155.605 188.219 153.571 148.676 4 1955 1955 95.845 198.000 111.000 169.872 162.235 170.831 124.382 95.407 120.997 142.344 242.837 231.000 155.195 5 1956 1956 198.000 178.578 188.465 239.763 236.266 148.481 48.000 108.076 140.654 187.918 190.322 158.644 168.448 6 1957 1957 113.170 145.776 146.900 184.328 238.845 235.280 96.487 109.818 169.967 166.197 238.982 162.907 167.059 7 1958 1958 163.875 172.564 163.154 145.699 234.281 54.491 77.000 112.859 227.479 235.899 120.681 149.182 154.091 8 1959 1959 116.556 144.398 141.710 177.771 163.280 132.962 234.118 137.164 163.878 177.804 143.873 149.890 9 1960 1960 116.661 181.490 183.937 15 95.296 125.229 262.376 261.911 214.000 169.161 AVERAGE 154.898 153.912 183.616 176.168 158.682 125.136 147.784 176.826 195.689 163.181 158.255 MAXIMUM 198.000 188.465 239.763 238.845 235.729 234.657 112.859 227.479 242.376 242.837 231.000 169.161 MINIMUM 95.845 116.661 111.000 145.699 72.217 54.491 48.000 42.721 120.997 142.344 120.681 112.690 148.676 ACRES INTERTEL LIMITED ACRES WATER RESOURCES SIMULATION PROGRAM ( # AQ1025_3.05 ) 1995-03-25 16:05:40 PAGE 14 Tyee Lake and Swan Lake Combined System March 1995 by Bill Shaffer and Mark Killgore PERIOO AVERAGE CHANNEL FLOW (cfs) 3 4 Tyee Lake Spill Channel YEAR OF SIM HYD OTH Oct Nov Dec Jan Feb Mar Apr May June July Aug Sept AVE 1 1952 1952 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 2 1953 1953 83.086 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 7.057 3 1954 1954 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 90.000 0.000 4 1955 1955 0.000. 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 23.967 0.000 2.036 5 1956 1956 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 6 1957 1957 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 7 1958 1958 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 8 1959 1959 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 9 1960 1960 18.485 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 56.144 34.089 0.000 9.236 AVERAGE 11.286 0.000 .! 0.000 0.000 0.000 0.000 0.000 0.000 6.238 6.451 0.000 036 234 0.000 2 MAXIMUM 83.08 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 56.144 34.089 0.000 9. MINIMUM 9.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 QO ACRES INTERTEL LIMITED ACRES WATER RESOURCES SIMULATION PROGRAM ( # A01025_3.05 ) 1995-03-25 16:05:40 PAGE 15 Tyee Lake and Swan Lake Combined System March 1995 by Bill Shaffer and Mark Killgore PERIOD AVERAGE CHANNEL FLOW (cfs) 3 5 General Flow Channel below Swan Lake YEAR OF SIM HYD OTH Oct Nov Dec Jan Feb Mar Apr May June July Aug Sept AVE 1 1952 1952 503.23 535.32 528.28 409.56 519.25 265.95 796.41 507.93 467.99 345.36 356.66 397.88 466.34 2 1953 1953 641.00 559.01 511.05 406.99 526.96 520.26 360.76 742.63 282.32 349.97 265.04 529.23 476.47 3 1954 1954 886.86 713.97 5846.82 415.71 879.34 343.15 383.37 539.37 433.59 297.33 264.58 339.51 504.17 4 1955 1955 642.92 996.00 739.77 441.56 460.70 373.74 483.69 473.87 450.26 353.67 618.12 500.00 544.52 5 1956 1956 1030.77 461.49 384.59 279.63 401.22 556.64 359.00 463.62 392.02 184.56 278.50 324.83 427.07 6 1957 1957 533.846 627.07 569.246 409.34 290.20 370.55 686.23 462.10 264.16 288.18 189.55 342.07 419.61 7 1958 1958 346.60 570.10 431.31 639.32 325.65 532.77 413.00 450.68 0.00 132.88 648.42 420.32 410.58 8 1959 1959 547.58 636.24 602.34 452.06 468.59 603.99 363.68 641.65 409.76 276.19 311.38 374.70 476.36 9 1960 1960 696.68 729.39 991.55 378.92 472.95 575.06 599.67 444.61 396.42 583.54 354.00 517.76 562.45 AVERAGE 647.72 647.62 593.66 425.90 482.54 458.01 493.56 525.16 344.06 312.41 365.14 416.26 475.95 MAXIMUM 1030.77 996.00 991.55 639.32 879.34 603.99 794.41 742.63 467.99 583.54 648.42 529.23 562.45 MINIMUM 346.60 461.49 384.59 279.63 290.20 245.95 359.00 444.61 0.00 132.88 189.55 324.83 410.58 . " ACRES INTERTEL LIMITED mCwes Peee RESOURCES SIMULATION PROGRAM ( # A01025_3.05—) 1995-03-25 16:05:40 Tyee Lake and Swan Lake Combined Systu March 1995 by Bill Shaffer and Mark Killgore PERIOD AVERAGE CHANNEL FLOW (cfs) 3 8 Lower River Tyee YEAR OF SIM HYD OTH Oct Dec Jan Feb Mar Apr May June July Aug Sept 1 1952 1952 150.000 155.557 186.094 160.960 235.729 70.635 97.350 124.484 150.109 169.167 142.763 2 1953 1953 325.000 157.632 184.986 157.598 148.404 234.657 42.721 159.704 147.108 191.276 112.690 3 1954 1954 237.898 120.422 139.299 180.097 72.217 176.086 145.653 81.629 126.379 155.605 188.219 153.571 4 1955 1955 95.845 111,000 169.872 162.235 170.831 124.382 95.407 120.997 142.344 266.805 231.000 5 1956 1956 198.000 188.465 239.763 236.266 148.481 48.000 108.076 140.654 187.918 190.322 158.644 6 1957 1957 113.170 146.900 184.328 238.845 235.280 96.487 109.818 169.967 166.197 238.982 162.907 7 1958 1958 163.875 163.154 145.699 234.281 54.491 77.000 112.859 227.479 235.899 120.681 149.182 8 1959 1959 116.556 141.710 177.771 163.280 9 1960 1960 261.448 181.490 183.937 159.829 276.000 214.000 AVERAGE 184.644 153.912 183.616 176.168 202.140 163.181 MAXIMUM 325.000 188.465 239.763 238.845 235.729 234.657 112.859 276.000 231.000 MINIMUM 95.845 116.661 111.000 145.699 72.217 54.491 48.000 42.721 120.681 112.690 ACRES INTERTEL LIMITED ACRES WATER RESOURCES SIMULATION PROGRAM ( # AQ1025_3.05 ) 1995-03-25 16:05:40 Tyee Lake and Swan Lake Combined System March 1995 by Bill Shaffer and Mark Killgore PERIOD AVERAGE CHANNEL FLOW (cfs) 3 4 Power Control Channet YEAR OF SIM HYD OTH Oct Nov Aug Sept 1 1952 1952 653.23 697.31 525.83 540.64 2 1953 1953 966.00 714.71 456.32 641.92 3 1954 1954 1124.76 834.40 452.80 493.08 4 1955 1955 738.76 1194.00 884.93 731.00 5 1956. 1956. 1228.77. 640.07 468.82 483.43 6 1957 1957 647.01 772.84 428.54 504.98 7 1958 1958 510.47 742.67 769.11 569.50 8 1959 1959 664.14 780.64 489.19 518.57 9 1960 1960 958.12 846.05 630.00 731.76 AVERAGE 832.36 802.52 567.28 579.44 MAXIMUM 1228.77 1194.00 884.93 731.76 MINIMUM 510.47 640.07 573.05 519.39 529.05 481.68 407.00 540.00 227.48 368.78 428.54 483.48 ACRES INTERTEL LIMITED ACRES WATER RESOURCES SIMULATION PROGRAM ( # AQ1025_3.05 ) 1995-03-25 16:05:40 Tyee Lake and Swan Lake Combined System March 1995 by Bill Shaffer and Mark Killgore PERIOO AVERAGE CHANNEL FLOW (cfs) 3 15 Swan Lake Inflow Channel YEAR OF SIM HYD OTH Oct Nov Dec Jan Feb May June July Aug Sept 1 1952 1952 526.00 393.00 367.00 147.00 275.00 116.00 505.00 715.00 810.00 646.00 502.00 613.00 2 1953 1953 641.00 483.00 341.00 151.00 297.00 296.00 327.00 924.00 576.00 505.00 231.00 717.00 3 1954 1954 1081.00 666.00 487.00 172.00 959.00 87.00 164.00 638.00 761.00 466.00 213.00 361.00 4 1955 1955 874.00 996.00 717.00 277.00 249.00 134.00 341.00 533.00 782.00 608.00 740.00 500.00 5 1956 1956 1008.00 353.00 129.00 55.00 120.00 59.00 359.00 885.00 632.00 322.00 534.00 311.00 6 1957 1957 660.00 605.00 547.00 164.00 89.00 95.00 298.00 694.00 618.00 456.00 186.00 268.00 7 1958 1958 366.00 542.00 244.00 536.00 268.00 177.00 413.00 707.00 337.00 131.00 681.00 376.00 8 1959 1959 1130.00 586.00 510.00 222.00 229.00 414.00 349.00 607.00 824.00 646.00 387.00 428.00 9 1960 1960 832.00 700.00 1020.00 177.00 270.00 428.00 588.00 620.00 702.00 656.00 354.00 517.00 AVERAGE 790.89 591.56 486.67 211.22 306.22 200.67 371.56 702.56 671.33 492.89 425.33 454.56 MAXIMUM 1130.00 996.00 1020.00 536.00 959.00 428.00 588.00 924.00 824.00 656.00 740.00 717.00 MINIMUM 366.00 353.00 129.00 55.00 89.00 59.00 164.00 533.00 337.00 131.00 186.00 268.00 PAGE 16 AVE 150.595 168.236 148.676 157.231 168.448 167.059 154.091 149.890 160.291 178.394 148.676 PAGE 17 AVE 616.93 642.71 652.84 701.76 595.52 586.467 564.67 626.25 740.85 PAGE 18 ACRES INTERTEL LIMITED ACRES eo 2 RESOURCES SIMULATION PROGRAM ( # a0t025_3.( 1995-03-25 16:05:40 PAGE 19 Tyee Lake and Swan Lake Combined System March 1995 by Bill Shaffer and Mark Killgore PERIOO AVERAGE CHANNEL FLOW (cfs) 3 16 Tyee Lake Inflow YEAR OF SIM HYD OTH Oct Nov Dec Jan Feb Mar Apr May June July Aug Sept AVE 1 1952 1952 150.000 71.000 55.000 22.000 14.000 15.000 58.000 215.000 321. 000 338.000 260.000 279.000 150.595 2 1953 1953 325.000 114.000 44.000 25.000 16.000 21.000 53.000 303.000 338.000 244.000 170.000 230.000 157.781 3 1954 1954 361.000 101.000 66.000 28.000 122.000 16.000 14.000 138.000 329.000 261.000 156.000 167.000 146.718 4 1955 1955 262.000 198.000 111.000 51.000 30.000 21.000 39.000 129.000 328.000 301.000 345.000 231.000 169.644 5 1956 1956 198.000 94.000 29.000 18.000 11.000 11.000 48.000 338.000 277.000 273.000 350.000 150.000 150.973 6 1957 1957 192.000 132.000 133.000 31.000 14.000 13.000 42.000 236.000 371.000 268.000 158.000 198.000. 149.707 7 1958 1958 176.000 155.000 55.000 87.000 22.000 24.000 77.000 269.000 327.000 207.000 256.000 124.000 147.342 8 1959 1959 475.000 113.000 84.000 34.000 20.000 25.000 55.000 214.000 376.000 395.000 225.000 177.000 184.115 9 1960 1960 348.000 112.000 186.000 56.000 33.000 34.000 88.000 205.000 324.000 338.000 276.000 214.000 185.745 AVERAGE 276.111 121.111 86.778 39.111 31.333 20.000 52.667 225.222 332.333 291.667 244.000 196.667 160.291 MAXIMUM 475.000 198.000 186.000 87.000 122.000 34.000 88.000 338.000 376.000 395.000 350.000 279.000 185.745 MINIMUM 150.000 71.000 29.000 18.000 11.000 11.000 14.000 129.000 277.000 207.000 156.000 124.000 146.718 ACRES INTERTEL LIMITED ACRES WATER RESOURCES SIMULATION PROGRAM ( # AO1025_3.05 ) 1995-03-25 16:05:40 PAGE 20 Tyee Lake and Swan Lake Combined System March 1995S by Bill Shaffer and Mark Killgore RESERVOIR WATER BALANCE NET EVAP LOCAL REGULATED TOTAL POWER SPILL OTHER TOTAL STORAGE CHANNEL WATER (EVAP-PREC) INFLOW INFLOW INFLOW OUTFLOW OUTFLOW OUTFLOW OUTFLOW ADJUSTMENT STORAGE BALANCE NAME (cfs) (cfs) (cfs) (cfs) (cfs) (cfs) (cfs) (cfs) (cfs) (cfs) (cts) Swan Lake Reser 0.00 476.16 0.00 476.16 475.95 0.00 0.00 4675.95 0.21 0.00 0.00 Tyee Lake Reser 0.00 160.29 0.00 160.29 158.25 2.04 0.00 160.29 0.00 0.00 0.00 POWER STATION ENERGY ADJUSTMENT INSTALLED AVERAGE ANNUAL ENERGY ENERGY ADJUSTED CAPACITY ENERGY COEFFICIENT ADJUSTMENT ENERGY NAME (MW) (GWH) (GWH/(cfs)) (GWH) (GWH) Swan Lake Power 26.0 90.8 0.000 0.000 90.8 Tyee Lake Power 25.0 138.1 0.000 0.000 138.1 TOTAL SYSTEM 51.0 228.9 0.0 228.9 integrated Systam Eneray Coneereee Avs: tny Cc Nov Dec 1951 1952 27.22 29.03 1952 1953 39.95 29.03 1953 1954 44.82 29.03 1954 1955 24.57 43.69 1955 1956 44.46 29.03 1956 1957 23.46 29.03 1957 1958 23.46 29.03 1958 1959 23.46 29.03 1959 1960 41.09 29.03 Average 32.50 30.66 Minimum 23.46 29.03 Energy Demand Avg. MW Nov Dec 1951 1952 23.46 29.03 1952 1953 23.46 29.03 1953 1954 23.46 29.03 1954 1955 23.46 29.03 1955 1956 23.46 29.03 1956 1957 23.46 29.03 1957 1958 23.46 29.03 1958 1969 23.46 29.03 1959 1960 23.46 29.03 Average 23.46 29.03 Maximum 23.46 29.03 Minimum 23.46 29.03 Shortage of Energy Avg. MW Oct Nov Dec 1951 1952 0.00 0.00 1952 1953 0.00 0.00 1953 1954 0.00 0.00 1954 1955 0.00 0.00 1955 1956 0.00 0.00 1956 1957 0.00 0.00 1957 1958 0.00 0.00 1958 1959 0.00 0.00 1959 1960 0.00 0.00 Average 0.00 0.00 Maximum 0.00 0.00 Minimum 0.00 0.00 Surplus of Energy Avg. MW Nov Dec 1951 1952 3.76 0.00 1952 1953 16.49 0.00 1953 1954 21.36 0.00 1954 1955 1.11 14.66 1955 1956 21.00 0.00 1956 1957 0.00 0.00 1957 1958 0.00 0.00 1958 1959 0.00 0.00 1959 1960 17.63 0.00 Average 9.04 1.63 Maximum 21.36 14.66 Minimum 0.00 0.00 27.77 27.77 27.77 28.70 27.77 27.77 24.88 27.77 41.82 29.11 41.82 24.88 27.77 27.77 27.77 27.77 27.77 27.77 2777 27.77 27.77 27.77 27.77 27.77 0.00 0.00 0.00 0.00 0.00 0.00 2.90 0.00 0.00 0.32 2.90 0.00 0.00 0.00 0.00 0.93 0.00 0.00 0.00 0.00 14.05 1.66 14,05 0.00 Jan 27.59 27.59 27.59 27.59 29.80 27.59 27.01 27.59 27.59 27.77 29.80 27.01 Jan 27.59 27.59 27.59 27.59 27.59 27.59 27.59 27.59 27.59 27.59 27.59 27.59 Jan 0.00 0.00 0.00 0.00 0.00 0.00 0.58 0.00 0.00 0.06 0.58 0.00 0.00 0.00 0.00 0.00 2.21 0.00 0.00 0.00 0.00 0.25 2.21 0.00 Feb Feb Feb 26.74 26.74 26.74 26.74 31.09 29.68 28.68 25.86 26.74 27.67 3.09 25.86 26.74 26.74 26.74 26.74 26.74 26.74 26.74 26.74 26.74 26.74 26.74 26.74 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.88 0.00 0.10 0.88 0.00 0.00 0.00 0.00 0.00 4.35 2.94 1.94 0.00 0.00 1.03 4.35 0.00 27.60 25.10 25.10 25.10 24.82 15.37 25.10 25.10 24.82 30.07 18.37 25.10 25.10 25.10 25.10 25.10 25.10 25.10 25.10 25.10 25.10 25.10 25.10 0.00 0.00 0.00 0.00 0.28 0.00 9.73 0.00 0.00 1.11 9.73 0.00 2.50 0.00 0.00 0.00 0.00 4.97 0.00 0.00 0.00 0.83 4.97 0.00 29.53 22.36 22.36 11.18 236 14.88 29.38 22.36 21.86 23.53 11.18 0.00 0.00 9.00 0.00 11.18 0.00 7.48 0.00 0.00 2.07 11.18 0.00 0.00 7.17 0.00 0.00 0.00 0.00 0.00 7.02 0.00 1.58 7.17 0.00 19.22 19.22 19.22 19.22 19.22 19.22 19.22 19.22 19.22 19.22 19.22 19.22 19.22 19.22 19.22 19.22 19.22 19.22 19.22 19.22 19.22 19.22 19.22 19.22 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Jun Jun Jun Jun 21.70 21.70 21.70 21.70 21.70 21.70 21.70 21.70 21.70 21.70 21.70 21.70 21.70 21.70 21.70 21.70 21.70 21.70 21.70 21.70 21.70 21.70 21.70 21.70 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Jul Jul Jul Jul 22.41 22.41 22.41 22.41 22.41 22.41 25.37 22.41 38.54 24.53 38.54 22.41 22.41 22.41 22.41 22.41 22.41 22.41 22.41 22.41 22.41 22.41 22.41 22.41 0.00 0.00 0.00 0.00 0.00 9.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2.96 0.00 16.13 2.12 16.13 0.00 25.12 25.12 25.12 39.29 25.12 27.57 25.12 25.12 33.26 27.87 39.29 25.12 25.12 25.12 25.12 25.12 25.12 25.12 25.12 25.12 25.12 25.12 25.12 25.12 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 14.17 0.00 2.45 0.00 0.00 8.14 2.75 14.17 0.00 23.79 23.25 35.54 23.25 23.25 23.25 23.25 34.19 25.89 35.54 23.25 23.25 23.25 23.25 23.25 23.25 23.25 23.25 23.25 23.25 23.25 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 9.00 0.00 Sep 0.54 0.00 0.00 12.29 0.00 0.00 0.00 0.00 10.94 2.64 12.29 0.00 Year 25.04 26.46 26.28 28.06 25.83 25.32 23.13 24.97 0.12 26.13 0.12 23.13 Year 24.48 24.48 24.48 24.48 24.48 24.48 24.48 24.48 24.48 24.48 24.48 24.48 Year 0.00 0.00 0.00 0.00 0.96 0.00 1.72 0.07 0.00 0.31 1.72 0.00 Year 0.57 1.97 1.78 3.60 0.86 0.41 0.58 5.57 1.96 5.57 0.41 A November 9, 1998 [RECEIVE [D) Mr. John Magyar, General Manager Ketchikan Public Utilities 2930 Tongass Avenue NOV 1 ~ 1998 Ketchikan, Alaska 99901 KPU Managers Office KETCHIKAN PUBLIC UTILITIES Dear John: Subject: Transmittal of Avoided Costs Please find enclosed the avoided costs prepared for KPU incorporating the comments recently received from KPU. We have prepared the avoided cost materials in the form of a brief report which includes written documentation and several tables identifying the basis of the calculation. Based on our past experience, these materials provide all the information KPU is required to provide in response to the request from a potential developer for avoided costs. The primary differences between the attached avoided costs and those submitted to you in draft form dated August 27, 1998 are noted as follows: m The 1998 diesel fuel cost used in the analysis has been adjusted from $0.60 to $0.63 per gallon reflecting more recent fuel purchase experience. m The repayment period for debt financing of new hydro projects has been reduced to 25 years from 30 years per comments from Ron Settje and Bob Newell. m Actual debt service on existing debt issued to finance the new diesel generator (1997 Series T) has been included in Table 6 for the calculation of total power cost. m Other comments noted by KPU have been addressed in the documentation. I appreciate the opportunity to have assisted KPU on this assignment. If you have any questions or would like to discuss the issue further, please call me at (206) 695-4418. Sincerely, R. W. BECK, INC. 7 1@ Ake Executive Engineer JLH:bb File: _1560/11-00171-10202-0101 _ 1001 Fourth Avenue, Suite 2500 Seattle, WA 98154-1004 Phone ‘206) 695-4700 Fax (206) 695-4764 3 KETCHIKAN PUBLIC UTILITIES 1998 AVOIDED COST DOCUMENTATION INTRODUCTION Ketchikan Public Utilities (KPU) has prepared its estimated avoided costs for both firm and non-firm power supply for the ten-year period 1998 through 2007. KPU supplies the majority of its power requirements with hydroelectric generation from KPU-owned hydroelectric resources and the State-owned Swan Lake hydroelectric project. Diesel generation is used to supplement hydroelectric generation. KPU has recently completed installation of a new 10,530-kW diesel generating unit at its Bailey power plant. The new diesel unit began operation in October 1998. For the past several years, KPU has pursued development of a transmission interconnection (the “Intertie”) between the Swan Lake hydroelectric project and the Lake Tyee hydroelectric project. The Intertie would be used to transmit generation from the Lake Tyee project surplus to the needs of Wrangell and Petersburg to KPU. It would also serve as a vital component of a Southeast Alaska transmission grid that has been envisioned for many years by the various communities in the region. KPU is presently seeking federal and state moneys to fund a portion of the costs to construct the transmission line. In addition to the Intertie, KPU has investigated the feasibility of developing two small hydroelectric projects, a 4,600-kW project at Whitman Lake (Alternative C) and a 1,900-kW project using water from Connell Lake. KPU is presently preparing license applications to the Federal Energy Regulatory Commission (FERC) for these two projects. If the Whitman Lake and Connell Lake projects are developed, the earliest they would be expected to be on-line is 2002. Although KPU has not committed to proceed with development of these projects, they are presently considered to be KPU’s least cost near-term power supply option, particularly when considering the uncertainty associated with financing the Intertie. The calculation of avoided costs included herein is based upon the definition of “avoided cost” set forth in 3 AAC 50.770. As such, the estimated avoided energy costs are provided for 1998 through 2003. KPU’s plans for the addition of firm capacity are provided for each of the next ten years. Pursuant to 3 AAC 50.770(d)(1), the calculation of KPU’s avoided energy costs specifically excludes the costs and kilowatt-hours sold associated with hydroelectric generation since KPU relies upon hydroelectric generation for more than 25 percent of its total power requirements. Further, KPU is committed to aa File: 1560/11-00256-10202-0101 1998 AVOIDED Cost DOCUMENTATION purchasing the power generation output of the Swan Lake project through a long-term contract with the State. This document presents KPU’s estimated avoided costs and provides documentation on the assumptions and methodology used in preparing the estimated avoided costs. Estimated avoided energy costs in accordance with 3 AAC 50.770(e)(1)(A) are provided in Table 1. KPU’s plans for additional capacity by amount and type are shown in Table 2, as required by 3 AAC 50.770(e)(1)(B). The estimated capacity costs at completion of the planned capacity additions are shown in Table 3 in accordance with 3 AAC 50.770(e)(1)(C) . The avoided costs presented herein are provided for informational purposes only and are subject to change. LOADS AND RESOURCES In June 1998, the Institute of Social and Economic Research of the University of Alaska (ISER) completed an Electric Load Growth Study for KPU that includes projections of KPU’s power requirements through 2025. This is the first forecast of KPU’s power requirements since the closure of the Ketchikan Pulp Company pulp mill in early 1997. The ISER forecast includes alternative base, low and high load growth scenarios. The base case of the ISER forecast, which has been used in the development of KPU’s avoided cost, projects total energy requirements to remain below 1996 levels through 2005 and then increase at an average annual rate of approximately 1.2% through 2025. Total annual energy requirements for 1998 are presently forecasted to be 147,607 MWh and peak load in 1998 is forecasted to be 27,000 kW. Actual net energy requirements in 1997 were 145,528 MWh whereas between 1994 and 1996 actual net energy requirements averaged 158,600 MWh per year. At the present time, KPU relies upon the 22,500-kW Swan Lake hydroelectric project for approximately 50% of its energy supply on average. KPU-owned hydroelectric resources provide an additional 44% of the total energy requirement on average with diesel generation providing the remainder of the total requirement. Energy generation from the hydroelectric facilities, however, can vary significantly from year to year depending on local precipitation. In wet years, KPU’s need for diesel generation is significantly lower whereas in dry years more diesel generation is needed. In addition to its hydroelectric facilities, KPU operates the Bailey diesel power plant in Ketchikan. The Bailey power plant includes three diesel-fueled generating units presently in operation with a combined capacity of 12,500 kw and a recently installed 10,530-kW unit which went on-line in October 1998. The total installed capacity of KPU’s generating resources, following completion of the new diesel unit, is 57,230 kW. R. W. Beck 2 1998 AVOIDED Cost DOCUMENTATION KPU uses the diesel generating units primarily to supplement hydroelectric generation. The diesel units also serve as backup to the hydroelectric generating facilities, particularly the Swan Lake project which is interconnected to Ketchikan through a 35-mile transmission line. KPU has maintained adequate local capacity (i.e., generating units located in Ketchikan) to back up the capacity of the Swan Lake project in case the transmission line or the Swan Lake project itself fails. This generating reserve requirement continues to be an element of KPU’s power supply planning efforts. Table 4 shows the forecasted peak demand and capacity resources for KPU for the base case resource scenario. In the base case, as shown in Table 4, KPU plans to retire one of its 3,500-kW diesel generating units in 2005. (This unit is rated at 4,500 kW but operation is limited to 3,500 kW.) With the addition of its new 10,530-kW diesel generating unit in 1998, no new generating units are shown to be needed through 2007 for the base case. As previously indicated, however, KPU is presently pursuing licensing of the 4,600-kW Whitman Lake and 1,900-kW Connell Lake hydroelectric projects. These two hydroelectric projects are expected to be developed in the future if loads continue to increase and the Intertie is not constructed. For the purposes of the calculation of avoided costs, it has been assumed that the Whitman Lake project will be constructed and on-line in 2005. Table 5 shows the forecasted energy requirements and base case generating resources for KPU for the years 1998 through 2007. The energy generation capabilities shown for the hydroelectric projects in Table 5 are based on average hydrologic conditions. It should be noted that in recent years, generation at the Swan Lake project has been below the projected long-term average due primarily to below normal precipitation levels. As can be seen in Table 5, most of KPU’s energy requirements are forecasted to be supplied from Swan Lake and KPU- owned hydroelectric projects. CALCULATION OF AVOIDED COST KPU’s avoided firm energy cost has been calculated for the base case with the premise that all energy generation forecasted to be from diesel generators is avoidable. The avoided firm energy costs are shown in Table 6. Avoided energy costs are calculated to include fuel costs and variable operations and maintenance expenses for diesel generators. Avoidable firm capacity costs have been calculated based on KPU’s current plans for new generation plant as previously described. Table 2 shows the specific resource plans over the next ten years for the addition of firm capacity resources by unit and type. The estimated capital cost of the planned additional capacity units, on both a total and cost per kW basis, is also shown in Table 3. Firm capacity must be available to KPU during its period of peak demand, typically December or January. R. W. Beck 3 1998 AVOIDED COsT DOCUMENTATION In calculating the avoided costs, several assumptions have been made. If alternative assumptions were used, the estimated avoided costs would vary. The principal assumptions used in the calculation are as follows: Le ow Forecasted KPU power requirements through 2007 are from the base case scenario of the load forecast developed by ISER, dated June 1998. Total annual average energy generation available from the Swan Lake hydroelectric project is estimated to be 74,600 MWh net of station service requirements. Usable energy generation from the Swan Lake project is projected to increase slightly each year over the next ten years as KPU’s loads are forecasted to increase. As the loads increase, a greater amount of the average energy generation capability of the Swan Lake project is projected to be usable. Future costs of KPU operation (exclusive of fuel costs), maintenance and construction are assumed to increase at the assumed rate of general inflation in the Consumer Price Index (CPI). The annual rate of increase in the CPI is projected to be 2.7% per year over the next ten years, pursuant to the Blue Chip Consensus economic projections provided in the “Blue Chip Economic Indicators” dated March 10, 1998. Diesel fuel prices at the beginning of the projection period are based on late summer 1998 delivered prices of approximately $0.63 per gallon. Fuel oil costs are assumed to increase or decrease at the real escalation rate (exclusive of inflation) forecasted by the State Department of Revenue in its Spring 1998 Revenue Sources Book for the years 1999 and 2000, Table 17 for ANS Market price. After 2000, real escalation in fuel oil prices is projected to be 0.3% per year through 2005 and 0.5% per year thereafter. The assumed rate of general inflation is further applied to fuel costs to obtain nominal fuel costs. The projected fuel costs for the years 1998 through 2007 are shown in Table 7. The fuel usage rate for diesel generation is assumed to be 17.6 kWh per gallon based on the expected fuel consumption for KPU’s new diesel generating unit as reported to KPU by the unit’s vendor. Average fuel consumption per kWh in the past has been higher, however, KPU anticipates that most diesel generation in the future will be provided by its new unit which is significantly more efficient than the older units. The variable operations and maintenance cost (excluding fuel) associated with diesel generation is estimated to be $0.013 per kWh (1.3 cents per kWh) based approximately on the categorization of fixed and variable 1997 actual expenditures as shown in Table 8. Fixed costs of diesel generation will be incurred regardless of the quantity of kWh generated and are not avoidable. Station service power usage for the diesel power plants is assumed to be 3.0% of the total amount of diesel generation. R. W. Beck 4 1998 AVOIDED COsT DOCUMENTATION 8. The Whitman Lake hydroelectric project will be constructed to include two turbines with a combined capacity of 4,600 kW (Alternative C) as described by Wescorp in its draft report entitled “Whitman Lake Hydroelectric Project Feasibility Study for KPU” dated January 1998. Total average annual energy generation of the project is estimated to be 20,100 MWh and the total capital cost is estimated to be $7,642,000 in 1998 dollars. Annual O&M expenditures are estimated to be $175,000 in 1998 dollars. File: AvoidCost98.doc R. W. Beck 5 1998 AVOIDED COST DOCUMENTATION TABLES Table 1 Ketchikan Public Utilities Estimated Avoided Firm Energy Costs Reference: 3 AAC 50.770(e)(1)(A) Energy Cost Year (¢/kWh) 1998 5.0 1999 4.8 2000 Sail 2001 SZ. 2002 53 2003 5.4 2004 5.6 2005 = 2006 - 2007 - See Table 6 for derivation and description of calculation methodology. 11/9/98 Table 2 Ketchikan Public Utilities Planned Firm Capacity Additions (1998 - 2007) Reference: 3AAC50.770(e)(1)(B) Annual Energy Firm Generation Generating Capacity Capability Estimated Capital Cost (1) Year Location Unit (KW) (MWh) ($000) ($/KW) Whitman Lake ; a 42 Ketchikan Hydroelectric Proje ,600 20,100 $ 7,642 $ 1,660 (1) Includes estimated cost of equipment and installation. Costs are shown in 1998 dollars. 11/9/98 Table 3 Ketchikan Public Utilities Estimated Capacity and Firm Energy Costs for Planned Firm Capacity Additions At Year of Completion (1998 Dollars) Reference: 3AAC50.770(e)(1)(©) Annual Total Fixed Energy Energy Generating Cost (1) Cost (2) Cost (3) Year Location Unit ($000/yr) (¢/kWh) (¢/kWh) 2005 Ketchikan cen s 802 (4) 4.0 Hydroelectric Project (1) Includes debt service associated with new plant assuming 100% debt financing with tax-exempt bonds at a 6.5% annual interest rate and 25 year repayment period. Also includes estimated fixed O&M costs. Costs are shown in 1998 dollars. (2) The energy cost includes variable costs of fue! and O&M. (3) Total energy and capacity cost in the first year of operation based on the amount of generation shown for the particular project in Table 2. Costs are shown in 1998 dollars. (4) There are no variable costs of operation associated with the Whitman Lake hydroelectric project. 11/9/98 Peak Demand (kW) Reserve Requirement Total Capacity Requirements Capacity Resources (kW) KPU Flydro KPU Diesel Diesel Additions Diesel Retirements Total Diesel Swan Lake Whitman Lake Total Resources Capacity Surplus (Deficit) Ketchikan Public Utilities Table 4 Estimated Peak Demand and Capacity Resources (kW) Medium Load Growth Scenario 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 27,000 27,200 27,400 27,700 28,100 28,300 28,600 28,900 29,200 29,400 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500 49,500 49,700 49,900 50,200 50,600 50,800 51,100 51,400 51,700 51,900 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 16,300 16,300 12,500 23,030 23,030 23,030 23,030 23,030 23,030 23,030 19,530 19,530 10,530 : : - - s 7 7 2 : - : : : - . (3,500) : E 23,030 23,030 23,030 23,030 23,030 23,030 23,030 19,530 19,530 19,530 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500 : : : : : : : 4,600 - s 57,230 57,230 57,230 57,230 57,230 57,230 57,230 58,330 58,330 58,330 7,730 7,530 7,330 7,030 6,630 6,430 6,130 6,930 6,630 6,430 11/9/98 Total Energy Requirements (MWh; Energy Resources (MWh) KPU Hydro KPU Diesel Swan Lake Whitman Lake Total Resources Table 5 Ketchikan Public Utilities Estimated Energy Requirements and Energy Resources (MWh) Medium Load Growth Scenario 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 146,200 146,300 147,500 149,400 151,900 153,700 155,500 157,300 ~=—-159,200~—- 161,000 64,600 64,600 64,600 64,600 64,600 64,600 64,600 64,600 64,600 64,600 7,000 7,000 8,100 9,700 11,900 13,400 15,000 - 7 : 74,600 74,700 74,800 75,100 75,400 75,700 75,900 76,200 76,400 76,700 : 3 : : : : E 16,500 18,200 19,700 146,200 146,300 147,500 149,400. ~—*'151,900 —*:153,700 +-155,500 157,300 159,200 161,000 11/9/98 15 16 ESTIMATED AVOIDABLE ENERGY COSTS Fuel - Diesel Variable O&M Total Avoidable Energy (MWh) Avoidable Energy Cost (¢/kWh) ESTIMATED COST OF POWER Purchased Power Fuel & Variable O&M Fixed O&M - Diesel Fixed O&M - Hydro Debt Service on Existing Plant Debt Service on New Plant Total Power Cost Total Energy Regs. (MWh) Total Cost of Power (¢/KWh) Table 6 Ketchikan Public Utilities Calculation of Estimated Avoided Energy Cost Medium Load Growth Scenario (Nominal $000) FUEL AND PURCHASED POWER PRICE ASSUMPTIONS Four Dam Pool Rate (¢/kWh) Diesel Fuel Cost (¢/gallon) GENERAL ASSUMPTIONS Four Dam Pool Fixed Rate (¢/kWh) Four Dam Pool O&M Rate (¢/kWh) Diesel Station Service Fuel Use (kWh/gallon) Diesel O&M (¢/kWh) lnflation 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 $ 258 §$ 243 $ 303 $ 374 $ 472 §$ 548 $ 632 $ - i. $ - 94 94 109 130 159 180 201 - - - $ 352 $ 337 $ 412 §$ 504 $ 631 §$ 728 $ 833 $ - §$ - 7,000 7,000 8,100 9,700 11,900 13,400 15,000 - - - 5.0 4.8 5.1 5.2 5.3 5.4 5.6 - - -_ | $ 5,073 5,136 5,201 5,282 5,365 5,450, 5,530 5,619 5,703 5,798 352 337 412 504 631 728 833 - - - 587 603 619 636 653 671 689 919 944 969 o13) 527 541 556 571 586 602 618 635 652 852 731 731 731 731 1,361 1,354 1,346 1,342 1,335 - a = - : - - 716 716 716 $ 7,377 $ 7,334 $ 7,504 $ 7,709 $ 7,951 $ 8,796 $ 9,008 $ 9,218 9,340 $ 9,470 146,200 146,300 147,500 149,400 151,900 153,700 155,500 157,300 159,200 161,000 5.0 5.0 5A Od we | 5.7 5.8 5.0) So 59 6.80 6.88 6.95 7.03 7.11 7.20 7.29 4:37 7.47 7.56 63.0 59.1 63.8 65.8 67.7 69.8 71.9 74.0 76.4 78.9 4.00 2.80 3.0% 17.60 1.30 2.7% 11/9/98 CALCULATION NOTES TO TABLE 6 (Line number references are to Table 6 unless noted otherwise.) 1 Diesel energy generation (see Table 5) adjusted for Station Service divided by Diesel Fuel Use (kWh/gal) times Diesel Fuel Cost (Line 19). Diesel energy generation (see Table 5) adjusted for Station Service times Diesel O&M (¢/kWh) adjusted for inflation and escalation. 5 Total Avoidable Energy Cost (Line 4) divided by Avoidable Energy (Line 3) times 100. Swan Lake energy generation (see Table 5) times Four Dam Pool Power Rate (see Line 15). Total Avoidable Energy Cost (see Line 5). Fixed O&M cost associated with diesel generation based on 1997 actual costs. 9 Fixed costs of hydroelectric generation. 10 Total debt service on existing KPU debt which is allocated to power production costs. (1997 Series T Bonds.) 11 Estimated debt service on new generation additions (see Table 2) assuming a 6.5% interest rate and 25 year repayment. CoN D 13 Total energy generated and purchased (see Table 5). 14 Total Power Cost (Line 12) divided by Total Energy Requirements (Line 13) times 100. 11/9/98 Table 7 Ketchikan Public Utilities Estimated Cost of Fuel ANS Nominal Market Fuel Price (1) Real Estimated Nominal Price (5) Year ($/barrel) Escalation(2) Inflation (3) Escalation(4) (S/gallon) 1998 $ 16.30 $ 0.63 (6) 1999 $ 14.90 -8.6% 2.7% -6.1% 0.59 2000 $ 15.66 5.1% 2.7% 7.9% 0.64 2001 0.3% 2.7% 3.0% 0.66 2002 0.3% 2.7% 3.0% 0.68 2003 0.3% 2.7% 3.0% 0.70 2004 0.3% 2.7% 3.0% 0.72 2005 0.3% 2.7% 3.0% 0.74 2006 0.5% 2.7% 3.2% 0.76 2007 0.5% 2.7% 3.2% 0.79 (1) Source: Alaska Dept. of Revenue, Spring 1998 Revenue Sources Book. Prices in 1998 dollars. (2) Implied escalation in ANS Market Price through 2000. Thereafter, increases are based on average annual increase in ANS Market Prices as forecasted in the DOR Fall 1997 Revenue Sources Book. (3) Assumed average annual inflation as forecasted in the March 1998 Blue Chip Economic Indicators. (4) Real escalation multiplied by annual inflation. (5) 1998 prices multiplied by nominal escalation rate. (6) 1998 diesel fuel prices are based on KPU's fuel purchases in late summer 1998. 11/9/98 30 31 35 45 46 47 48 System Operator Cost Alloc System Operator Cost Alloc Dispatch Labor Salaries & Wages Overtime Fringe Benefit Costs Transfers to Other Funds Inter-Dept. Equip Charge Subtotal Other Costs Warehouse Issue Costs Materials & Service Subtotal Bailey - Oper. Supv. Eng Salaries & Wages Overtime Temporary Salaries Fringe Benefit Costs Department Supplies Janitorial Supplies Office Supplies Education & Training Safety Program Advertising & Publishing Contractual Services Ques & Publications Maintenance Services Postage Professional Services Rentals - Space Telephone Service Administration Inter-Dept. Equip Charge Warehouse Issue Costs Materials & Service Subtotal Fuel Salaries & Wages Overtime Temporary Salaries Fringe Benefit Costs Heating Oil Motor Fuel & Lubricants Inter-Dept. Equip Charge Warehouse Issue Costs Materials & Service Subtotal Generation Expense Salaries & Wages Overtime Temporary Salaries Fringe Benefit Costs Office Supplies Table 8 Ketchikan Public Utilities Allocation of 1997 Diesel O&M Costs to Fixed and Variable 1997 Actual $ $ 74,638 (121,974) 345,314 26,514 144,900 (516,729) (1) 2,592 60 1,293 3,122 4,581 56 977 8,750 1,161 2,016 261,465 237 250 4,225 290,785 217 265 iS. 967,837 44 968,518 66,686 7,741 27,482 Page 1 Allocation Fixed % Var % 100% 0% $ 100% 0% 100% 0% 100% 0% 100% 0% 100% 0% 100% 0% 100% 0% $ 50% 50% 50% 50% 0% 100% $ 100% 0% 0% 100% 0% 100% 100% 0% 100% 0% 100% 0% 100% 0% 100% 0% 100% 0% 100% 0% 100% 0% 100% 0% 100% 0% 100% 0% 100% 0% 100% 0% 100% 0% 100% 0% 100% 0% 30% 50% 50% 50% 99% 1% $ 100% 0% 0% 100% 0% 100% 100% 0% 0% 100% 0% 100% 100% 0% 50% 50% 30% 50% 0% 100% $ 100% 0% 0% 100% 0% 100% 100% 0% 50% 50% Allocated Amounts Fixed Variable 74,638 $ - (121,974) 5 345,314 ; 26,514 : 144,900 : (516,729) zi (1) $ - 8,750 - 1,161 - 2,016 - 261,465 - 237 - 125 125 2,113 2,112 288,488 $ 2,297 217 - = 265 155 - = 967,837 44 - 416 $ 968,102 66,686 - - 7,741 27,482 - 11/9/98 49 51 52 53 Table 8 Ketchikan Public Utilities Allocation of 1997 Diesel O&M Costs to Fixed and Variable Telephone Service Utilities Inter-Dept. Equip Charge Warehouse Issue Costs Materials & Service Subtotal Misc Diese! Generation Expense Salaries & Wages Overtime Temporary Salaries Fringe Benefit Costs Inter-Dept. Equip Charge Warehouse Issue Costs Materials & Service Subtotal Bailey Maint Supv. Eng Salaries & Wages Overtime Temporary Salaries Fringe Benefit Costs Medical Exams Janitorial Supplies Office Supplies Education & Training Safety Program Plant Engr - Clearing Advertising & Publishing Contractual Services Dues & Publications Maintenance Services Postage Inter-Dept. Equip Charge Warehouse Issue Costs Materials & Service Subtotal Maint. Structures Salaries & Wages Overtime Temporary Salaries Fringe Benefit Costs Warehouse Issues Safety Program Advertising & Publishing Contractual Services Utilities Inter-Dept. Equip Charge Warehouse Issue Costs Materials & Service Subtotal Maint. Electric Plant Salaries & Wages Overtime Temporary Salaries Allocation Allocated Amounts 1997 Actual Fixed % Var% Fixed Variable 9,915 100% 0% 9,915 - 3,247 50% 50% 1,624 1,623 6,902 50% 50% 3,451 3,451 - 50% 50% - - : 50% 50% : : $ = 121,973 89% 11% $ 109,158 $ 12,815 2,086 100% 0% 2,086 - 1,658 0% 100% - 1,658 - 0% 100% - - 1,626 100% 0% 1,626 - 342 50% 50% 171 171 - 50% 50% - - - 50% 50% : : $ 5,712 68% 32% $ 3,883 $ 1,329 32,367 100% 0% 32,367 - 60 0% 100% - 60 216 0% 100% - 216 13,881 100% 0% 13,881 - 75 100% 0% 75 : - 100% 0% - : 2,782 50% 50% 1,391 1,391 900 100% 0% 900 - - 100% 0% - - - 100% 0% - : 112 100% 0% 112 - - 100% 0% : = 65 100% 0% 65 - - 100% 0% - - 11 100% 0% 11 - 2,814 50% 50% 1,407 1,407 244 50% 50% 122 122 4,125 50% 50% 2.063 2,062 $ $7,652 91% 9% $ 52,394 §$ 5,258 14,077 100% 0% 14,077 - - 0% 100% - - 1,133 0% + 100% - 1,133 5,284 100% 0% 5,284 - : 100% 0% : : 489 100% 0% 489 - : 100% 0% - : : 100% 0% - - 1,052 50% 50% 526 526 1,243 50% 50% 622 621 190 50% 50% 95 95 3,218 50% 50% 1,609 1.609 $ 26,686 85% 15% $ 22,702 $ 3,984 131,237 40% 60% 32,495 78,742 7,930 0% 100% - 7,930 3,954 0% 100% - 3,954 Page 2 11/9/98 Table 8 Ketchikan Public Utilities Allocation of 1997 Diesel O&M Costs to Fixed and Variable Allocation Allocated Amounts 1997 Actual Fixed % Var % Fixed Variable Fringe Benefit Costs 52,247 40% 60% 20,899 31,348 Motor Fuel & Lubricants 49,198 0% 100% - 49,198 Small Tools & Equipment 49 50% 50% 25 24 Education & Training 960 50% 50% 480 480 Warehouse Issues : 100% 0% - - Safety Program - 100% 0% - - Advertising & Publishing : 100% 0% = - Contractual Services 120 100% 0% 120 - Postage 102 100% 0% 102 - Rentals & Equipment - 100% 0% - - Licenses & Fees 660 100% 0% 660 - Inter-Dept. Equip Charge 12,114 50% 50% 6,057 6,057 Warehouse Issue Costs 3,440 50% 50% 1,720 1,720 Materials & Service 60,938 50% 50% 30,469 30,469 Operating Equipment : 50% 50% : : Subtotal $ 322,949 35% 65% $ 113,027 $ 209,922 54 Maint. Misc Diesel Plant Salaries & Wages 13,752 100% 0% 13,752 - Overtime 259 0% 100% : 259 Temporary Salaries 8,283 0% 100% - 8,283 Fringe Benefit Costs 6,267 100% 0% 6,267 : Office Supplies - 50% 50% - - Small Tools & Equipment 89 50% 50% 45 44 Contractual Services 23,652 50% 50% 11,826 11,826 Postage - 100% 0% : - Professional Services 10,339 50% 50% 5,170 5,169 Licenses & Fees 3,000 100% 0% 3,000 - Transfers to Other Funds 2,513) 50% 50% 1,257 1,256 Inter-Dept. Equip Charge 1,238 50% 50% 619 619 Warehouse Issue Costs 279 50% 50% 140 139 Materials & Service 5,139 50% 50% 2,570 2.569 Subtotal $ 74,810 60% 40% $ 44,646 $ 30,164 Total - Bailey Plant $ 1,821,748 $ 587,377 $ 1,234,371 Less: Fuel and Lubricants : (1,017,300) Net: O&M $ 387,377 $ 217,071 Diese! Generation (MWh) 16,142 Cost per kWh (cents/kWh) 1.34 Page 3 11/9/98 (7) Nie \ q h\ (SS Ver ie TD 43157 { =) i i i ‘ j , if Wye i? + F i| [A [t 7B) * ) iA 2) 2-3 TONY KNowLes, advance SU ApS jhe os) NS) Bes Ea CF 410 Willoughby Ave., Suite 105 NE Juneau, AK 99801-1795 Phone: (907) 465-5100 DEPT. OF ENVIRONMENTAL CONSERVATION i) iS FAX: (907) 465-5129 Division of Air and Water Quality - Air Quality Maintenance i hetp://www.state.ak.us/dec/home.htm June 4, 1998 " (RECEIVE [D) JUN 8 1998 Mr. John Magyar Ketchikan Public Utilities mimeo L 2930 Tongass Avenue Ketchikan, AK 99901 Subject: Construction Permit No. 9813-AC013 for the Bailey Street Power Plant; Bailey Powerhouse Upgrade; Application No. X13 Dear Mr. Magyar: Under the authority of AS 46.14.170, the Department is taking action to issue a construction permit for the Bailey Street Power Plant. The permit allows you to install a new Wartsila internal combustion (IC) engine and a new 185,000 gallon diesel storage tank, and requires you to raise the exhaust stacks of three existing IC engines, in accordance with the terms and conditions of the permit, and as described in the original permit applications and subsequent submittals. Enclosed, you will find the following documents relevant to this action: 1. Construction Permit No. 9813-AC013, which contains the requirements of AS 46.14 and 18 AAC 50 applicable to this action. N The Technical Analysis Document, which explains the Department’ s regulatory and technical basis for the permit action. The Analysis and Response to Public Comment, which contains a summary of public comment received during this permit action and the Department’s analysis of the public comment. w 4. A memorandum modifying the Department’s Best Available Control Technology decision. The terms and conditions of this construction permit remain effective until modified or revoked by the Department, regarcless of any change in ownership of the facility or its sources. The responsibilities imposed by this construction permit may not be transferred without the written consent of the Department. Mr. John Magyar -2- June 4, 1998 The regulations listed in 18 AAC 50.320 describe the special circumstances under which the Department will reopen a construction permit to assure the Best Available Control Technology limits in this permit remain current. Please note that Alaska’s air quality statutes, regulations, and permit application information can be obtained from the Department’s Web Page at the following address: http://www.state.ak.us/local/akpages/EN V.CONSER V/dawa/aqm/mainair.htm The project authorized by this permit action was reviewed under the provisions of the Alaska Coastal Management Program (ACMP). No additional terms or conditions were stipulated as a result of this review. The terms and conditions of this permit ensure the operation of the facility is consistent with the ACMP, and this permit action serves as the final consistency determination. Department regulations provide that if you disagree with this decision, you may request an adjudicatory hearing in accordance with 18 AAC 15.200-910. The request should be mailed to the Commissioner, Alaska Department of Environmental Conservation, 410 Willoughby Avenue, Suite 105, Juneau, AK 99801-1795, by Certified Mail, Return Receipt Requested. Ifa hearing is requested, one copy of the request should be sent to the undersigned. Failure to submit a request within thirty days of service of this letter shall constitute a waiver of your right to an administrative review of this permit action by the Department. In addition, any other person who has a private, substantive, legally protected interest under state law that may be affected by the permit action, or a person who participated in the public process, may request an adjudicatory hearing within thirty days of service of the action. If a hearing is granted, it will be limited to the issues related to this permit action. You are reminded that, even if a request for an adjudicatory hearing has been granted, all permit terms and conditions remain in full force and effect. Sincerely, ze ki John M. Stone, Air Quality Maintenance Section JMS/JFK/pai (r:\airfacs\kpu\x13\final\const perm lett 9813-ac013.doc) Enclosures: 4 ce: ADEC/AQM, Juneau, Anchorage, Fairbanks aed Air Quality Control Construction Permit 9713-AC017 June 4, 1998 ALASKA DEPARTMENT OF ENVIRONMENTAL CONSERVATION AIR QUALITY CONSTRUCTION PERMIT Permit No. 9713-AC017 Date: June 4, 1998 The Department of Environmental Conservation, under the authority of AS 46.03, AS 46.14, 18 AAC 50, 18 AAC 15, and 6 AAC 50, issues this Air Quality Control Construction Permit to: Owner: Ketchikan Public Utilities (KPU) Facility: Bailey Powerhouse 2930 Tongass Avenue Ketchikan, AK 99901 Designated Agent: Mr. John Magyar, General Manager Location: UTM Coordinates Northing 5535.79 km, Easting 131.70 km. The project consists of - installing a new Wartsila internal combustion (IC) engine, and a 185,000 gallon diesel fuel storage tank, and - raising the exhaust stacks of three existing IC engines. The Department authorizes KPU to modify the facility in accordance with the terms and conditions of this permit, and as described in the original permit application and subsequent submittals listed in Exhibit C. This permit also authorizes KPU to operate the facility as provided by AS 46.14.120. WAI b/afa9 John F. Kuterbach, Supervisor Date AQM Program Development G:\AIRFACS \kpu\X13\FINAL\9713AC13.doc page 1/19 Air Quality Control Construction Permit 9713-AC017 June 4, 1998 TABLE OF CONTENTS esStandard Permit! Comdiithoms -axsscscscacscscscicscecsaswsansdstzcscccssscscosesssesevsnsvatcnosoeseetscctsavessusecesstuceses 3 Il. Standard Record Keeping, Reporting, and Testing Conditions... =D (Weert fa eat h On eae cctctc acc tnsacace cacao soot co savectecestctcsctctatescectecssscsetetetetctesercescstccevorsvaseroonaeesea 5 De ParteTeMt ACCICSS sesccereresnseaseceec ante reneaesmete esarees cerenmeateeeenstceerenesessveraersesevesterenseseeetetttverewens 5 RECOrd Retention: Schedule rxcsscccccnctctecetoresecscsoccestctsreretssedececescststonetetatataescstscecessassascesees=ord 5 EMISSION SOULCE TL OSUS cr sses ane ase cc sascscent cv cnotoveesstescnescnsosecttesast sovsachcttteastsscectrscestetessascseress 5 VA OM IECOTAA Geert rctetct crt eeteeate tan cestst ct cteteteacesererstoestercasees sdadesat ates acesusssneaessuocevsecouesoeos 6 (Alternative! MOMILOTIN Gs scesececesensuaceretetecsesscseacsescoztcvstsesacese aasbbst saatataticnt siasvsvaneecnceeasneas 6 Facility Operating Repott............. <0 EXCeSs PMmission Facsimile: REPOLE scsessccsscecesocsoterceotsssestasrsssscseratecstverevterccrsnctossrseceeneeseoscesa 6 (ATE POLUTION EMerPeNCY/REPOLt csasesacstssccecsctoretatatensaecnereteressentcietceeessasceecesiocsvsrsvecesssescserd 6 Il. Notification and Operating Conditions ..0.0..............eeseeeseseeeeseeeeeee al IV. 18 AAC 50.010--Ambient Air Quality Standards and Increments . 8 Process Monitoring and Recording .. =O) REPOTTING.......--.cscecsescsenenensenseeasenses oo) Ambient Air Quality Monitoring ...........:scscsssseeerseseeseeeeees V. 18 AAC 50.040--Federal Standards Adopted by Reference ...0.0............esssceseceseeceeeeeeeeeees VI. 18 AAC 50.055--Industrial Processes and Fuel-Burning Equipment Emission Limits—Unit Nos. 1-4. ........ssscsssssssssssssesesesssessssesseseeeneneeeees Monitoring (and! recorcl tng cassie at asnc cc ncac aces sasovenotestsssvasussasusssronassvesoswsusasorososvensscusceesecectaaces 12 RRS DONC eeeeesctastenecestecsetectessseseeteteccersensttescstartceressassccorensectstranstrcrastststetarevetsrcttecenstveceessesee? 12 Vil. 18 AAC 50.110--Air Pollution Prohibited .0.0..........eessesssssessteseseeeeeeeees lS Vill. 18 AAC 50.315(e)(3)(A)--Best Available Control Technology (BACT).. .14 MSGI NAS feces ia sctstccscnactcsatescscesa soresesecers 14 Monitoring and Record Keeping... 14 FREDOLEII Gg ceccasetesecccocscacestcnsteecsesetarectetrecenstaraters 14 EXHIBIT A FACILITY OPERATING REPORT... tS EXHIBIT B SUBMITTAL LIST... ccecescsssssseesesseeeeseees .. 16 EXHIBIT C PERMIT APPLICATION DOCUMENTATIO sce EXHIBIT D EXCESS EMISSION REPORTING FORM.......0.....c.cssssessesessssesssseseseeeseseeeees 18 G:\AIRFACS\kpu\X13\FINAL\9713AC13.doc page 2/19 Air Quality Contro! Construction Permit 9713-ACO17 June 4, 1998 3h A. Standard Permit Conditions The Permittee shall comply with each permit term and condition; noncompliance constitutes a violation of AS 46.14, 18 AAC 50, and the Clean Air Act, and is grounds for: 1. Anenforcement action; 2. Permit termination, revocation and reissuance, or modification in accordance with AS 46.14.280; or j 3. Denial of an operating permit application. It is not a defense in an enforcement action to claim that it would have been necessary to halt or reduce the permitted activity in order to maintain compliance with a permit term or condition. Each permit term or condition is independent of the permit as a whole and remains valid regardless of a challenge to any other part of the permit; Compliance with the permit terms and conditions is considered to be compliance with those requirements that are: 1. Inciuded and specifically identified in the permit; or 2. Determined in writing in the permit to be inapplicable. The permit may be modified, reopened, revoked and reissued, or terminated for cause; a request by the Permittee for modification, revocation and reissuance, or termination, or a notification of planned changes or anticipated noncompliance does not stay any permit condition; The permit does not convey any property rights of any sort, nor any exclusive privilege. The Permittee shall allow an officer or employee of the Department, or an inspector authorized by the Department, upon presentation of credentials and at reasonable times, with the consent of the owner or operator, to: 1. enter upon the premises where a source subject to the construction permit is located or where records required by the permit are kept; G:\AIRFACS \kpu\X 13\FINAL\9713AC13.doc page 3/19 Air Quality Control Construction Permit 9713-AC017 June 4, 1998 2. have access to and copy any records required by the permit; 3. inspect any facilities, equipment, practices, or operations regulated by or referenced in the permit; and 4. sample or monitor substances or parameters to assure compliance with the permit or other applicable requirements. H. The Permittee shall furnish to the Department, within a reasonable time, any information the Department requests in writing to determine whether cause exists to modify, revoke and reissue, or terminate the permit, or to determine compliance with the permit; upon request, the Permittee shall furnish to the Department copies of records required to be kept; the Department, in its discretion, will require the Permittee to furnish copies of those records directly to the federal administrator. G:\AIRFACS\kpu\X 13\FINAL\9713AC13.doc page 4/19 Air Quality Control Construction Permit 9713-AC017 ff, rf June 4, 1998 fi0OATE I. Standard Record Keeping, Reporting, and Testing Conditions A. Certification--The Permittee shall certify all reports, compliance certifications, or other documents submitted to the Department under this permit as required by 18 AAC 50.205. B. Department Address--The Permittee shal] submit test plans, reports, certifications, and notices required under this permit to the Department’s Air Quality Maintenance Section, Compliance Assurance Group, 410 Willoughby Avenue, Suite 105, Juneau, AK 99801-1795; telephone (907) 465-5022, facsimile (907) 465-5129. C. Record Retention Schedule--The Permittee shall keep records of required monitoring data and support information for at least five years after the date of the collection; support information includes calibration and maintenance records, original swip-chart recordings for continuous monitoring instrumentation, and copies of reports required by this permit. The Permittee shall keep monitoring and compliance records as required by the Clean Air Act and applicable federal air quality regulations. D. Emission Source Tests--The Permittee shall conduct source testing as requested by the Department, required by this permit, and 18 AAC 50.220. The Permittee shall comply with all applicable federal Air Quality requirements, and shall: 1. use the applicable test methods set out in 40 CFR Part 60, Appendix A, and 40 CFR Part 61, Appendix B, effective December 16, 1996, to ascertain compliance with applicable standards and permit requirements; 2. conduct source tests of unit exhausts and report the results as described. The Permittee may propose alternative test methods if it can be shown to be of equivalent accuracy, and will ensure compliance with the applicable standards or limits. The Permittee shall obtain Department approval before using an alternative test method. , 0 2 e Nitrogen Oxides, NOx, expresses as NO2 (ppm, 1b/MMBtu, and Ibs/hr): Reference Method 7E or Method 20 specified in 40 CFR, Part 60, Appendix A. ¢v/ \e Oxygen, O (percent): Reference Method 3 or 3A as specified in 40 CFR,— 7 ret Part 60, Appendix A. [par te Stack Velocity and Volumetric Flow Rate: Reference Methods 14 as ~~“, --_ specified in 40 CFR, Part 60, Appendix A. (Pert ns dia ~~ Particulate Matter (grains/dscf, Ib/MMBtu, and lb/hr): Reference Method 5 as x th specified in 40 CFR, Part 60, Appendix A. ¥ “<e ~~ Sulfur dioxide (SO2) (ppm, Ib/MMBtu, and Ibs/hr): Reference Method 6 or 6C as specified in 40 CFR, Part 60, Appendix A. _» “© Visible Emission Surveillance (Percent): Reference Method 9 as specified in eS 40 CFR, Part 60, Appendix A. G:\AIRFACS \kpu\X 13\FINAL\9713AC13.doc page 5/19 Air Quality Control Construction Permit 9713-AC017 June 4, 1998 3. submit to the Department, within 60 days after receiving a request and at least 30 days before the scheduled date of the tests, a complete plan for conducting the source tests; 4. give the Department written notice of the test dates 10 days before each series; and 5. Within 45 days after completion of the set of tests, submit the results, to the extent practical, in the format set out in Source Test Report Outline in Volume III, Section IV.3, of the State Air Quality Control Plan, adopted by reference in 18 AAC 50.030(8). Monitoring--The Permittee shall: 1) install; 2) calibrate; 3) conduct applicable continuous monitoring system performance tests listed in 40 CFR 60, Appendix B, effective December 16, 1996, and certify test results; 4) operate; and 5) maintain air contaminant emissions and process monitoring equipment on the sources as described herein and in documents provided by the Permittee, listed in Exhibit C. The applicant shall submit monitoring equipment siting, operation, and maintenance plans and procedures for approval by the Department. Alternative Monitoring-- Until the Department approves an alternative monitoring, record keeping, or reporting requirement, the Permittee shall comply with the requirements listed in this permit. The Permittee may request approval of an alternative requirement by submitting a written request to the Department. Facility Operating Report--Permittee shall submit two copies of a quarterly Facility Operating Report, as described in Exhibit A of this permit, to the Department by January 30th, April 30th, July 30th, and October 30th, each year for operations during the preceding calendar quarter. Excess Emission Facsimile Report--Within 24 hours of discovering emissions that exceed permit conditions, State emission standards, or federal emission standards, the Permittee shall FAX a completed and signed “Excess Emission Notification Form” to the Department at (907) 465-5429. Exhibit D contains a copy of the applicable form. . 1649-1508 fax [1577 wire] Air Pollution Emergency Report--Upon discovery of any emission in quantity or duration that is potentially injurious to human health, the permittee shall immediately contact the Department's Division of Spill Prevention and Response (SPAR) by telephone at (907) 465-5340 during normal working hours, and at (800) 478-9300 after normal working hours, to fully explain the nature of the emergency. Permittee shall also report the incident in accordance with Condition I(H). G:\AIRFACS\kpu\X 13\FINAL\9713AC13.doc page 6/19 Air Quality Control Construction Permit 9713-AC017 Ye / Z, : June 4, 1998 If. Notification and Operating Conditions A. The Permittee is authorized to install and operate the following new emission sources at the Ketchikan Public Utilities Bailey Powerhouse: Tag # Description Rated Capacity Unit #4 Wartsila Model 12V46 Diesel Engine 10.5 MW, 14,546 Horsepower None Fuel Oil Storage Tank 185,000 Gallon The Permittee is authorized to operate the following existing emission sources at the Ketchikan Public Utilities Bailey Powerhouse Facility: Tag # Description Rated Capacity Unit # 1 Worthington 4.5 MW, 6,035 Horsepower Unit #2 Worthington 4.5 MW, 6,035 Horsepower Unit #3 Colt Pielstik 6.45 MW, 8,650 Horsepower None Fuel Oil Storage Tanks No Size listed B. The Permittee shall operate each source in compliance with the applicable emission standards specified by 18 AAC 50.040-.070, by an applicable federal New Source Performance Standard (NSPS) or National Emission Standard for Hazardous Air Pollutants (NESHAP), by limits established as the result of a BACT or LAER determination, or the owner-requested emission limits, standards, fuel specifications, and operating limits. C. The Permittee shall develop and implement standard operating and maintenance procedures for each fuel burning equipment source listed in Condition III(A) of this permit. The Permittee shall keep a copy of the procedures available at a location within the facility that is readily accessible to operators of the equipment and to authorized representatives of the Department. The Permittee shall install, maintain, and operate, in accordance with standard operating procedures, fuel-burning equipment, process equipment, emission control devices, and testing equipment and monitoring equipment to provide an opimum control of air contaminant emissions during all operating periods. D. The Permittee shall record the date construction commences, stops, and when construction is completed for installing Unit #4. If subject to 18 AAC 50.320(c)(1) or (2), the Permittee shal] notify the Department and submit a new Best Available Control Technology assessment for review before commencing or continuing construction. E. The Permittee shall clearly display the cover page of this permit and keep a copy of this permit and State Air Quality Control Regulations 18 AAC 50 at the permitted facility. G:\AIRFACS\kpu\X13\FINAL\97 13AC 13.doc page 7/19 Air Quality Control Construction Permit 9713-AC017 June 4, 1998 IV. 18 AAC 50.010--Ambient Air Quality Standards and Increments A. The Permittee shall not interfere with the attainment or maintenance of the Ambient Air Quality Standards listed in 18 AAC 50.010, and shall not cause or contribute to a violation of the maximum allowable ambient concentrations (the PSD increments) listed in 18 AAC 50.020 as follows: 1. Except as provided for in Condition IV(A)(2), the Permittee shall construct and operate the facility in accordance with the application and subsequent submittals listed in Exhibit C of this permit. 2. The Permittee shall notify the Department prior to making any change at the facility that deviates from the application and subsequent submittals listed in Exhibit C, such as changes in equipment size, configuration, or location. The Permittee shall ask the Department if additional ambient impact assessment modeling is warranted for the proposed change. Within 60 days upon receiving written Department notice that modeling is warranted, the Permittee shall prepare and submit to the Department an ambient impact assessment for the specified air contaminant and averaging period. The Permittee shall not make the change until the Department concurs the change will not interfere with attainment or maintenance of ambient standards and increments. 3. The Permittee shall extend the exhaust stacks of Unit No. 1 and 2 to 55 feet above ground level, and the stack of Unit No. 3 to 70 feet above ground level before commissioning Unit No. 4. 4. Limitations on fuel type and quality. Permittee shall use as fuel in all fuel-oil fired equipment only No. 1 or No. 2 fuel oil with no greater than 0.25% sulfur by weight. d 5. Permittee shall limit the operation of: e Unit Nos. 1 and 2 to a combined total of no more than 1650 hours per 12-month period; ¢ Unit No. 3 to no greater than 2900 hours per 12-month period; e Unit No. 4 to no greater than 4450 hours per 12-month period; and e Unit 2 to no more than 10 hours a day concurrent with Units 1, 3, and 4 operating at full load. G:\AIRFACS\kpu\X13\FINAL\9713AC13.doc page 8/19 Air Quality Control Construction Permit 9713-ACO17 June 4, 1998 B. Process Monitoring and Recording--The Permittee shall: i Maintain a written record for completion of the stack extension construction tasks and Unit No. 4 commission date. Measure the amount of fue! consumed in each of Unit Nos. 14. The fuel use may be estimated by calculations approved by the Department. Fuel meters, if used, must be calibrated and certified to be accurate to =5%; submit a copy of the manufacturer’s certification of accuracy for each fuel meter within 90 days after installation or replacement; Maintain a log of the operation time, duration, fuel consumption, and power production for each Engine Unit listed in Condition I(A); and Measure the fuel sulfur content of distillate fuel oil in accordance with sulfur measurement methods incorporated by reference under ASTM D 196 no less than once a month, or obtain a vendor certification documenting the fuel sulfur content of each delivery to the facility. C. Reporting--The Permittee shall report or attach to the Facility Operating ing required by Condition I(G): Ls 4. The date each stack extension is completed; and the date Unit No. 4 is commissioned; The duration of operations (hours), fuel consumption, and the total power production (kW-hr) for each unit each month; Fuel Oil Quality: Sulfur content (in weight percent) of each sample covering one or more distillate fuel oil shipments received. List the name of the supplier of each shipment. Report any change in the type of fuel, test method, or analysis performed. Attach a copy of analyses. If the Permittee elects to document fuel sulfur content by means of vendor certification as set out in Condition IV(B)(4), then attach the vendor certification; and A copy of each fuel meter certification conducted during the period reported. D. Ambient Air Quality Monitoring--If Unit No. 4 exceeds 3340 hours of operation during any consecutive 12-month period, then the Permittee shall operate, maintain, and calibrate one ambient air contaminant monitoring station within six months. The station must be sited within the zone of maximum predicted sulfur dioxide and nitrogen dioxide impact for which the Bailey Powerhouse Facility has a significant contribution. The station must be operated, maintained, and calibrated as follows: G:\AIRFACS\kpu\X 13\FINAL\9713AC13.doc page 9/19 Air Quality Control Construction Permit 9713-AC017 June 4, 1998 1. Permittee shal] submit to the Department, for approval, an ambient monitoring plan for sulfur dioxide, oxides of nitrogen, and nitrogen dioxide, prepared in accordance with Alaska Quality Assurance Manual for Ambient Air Quality Monitoring, dated August 1996. The plan will identify the monitoring site and rationale for site selection, and will be submitted not later than three months after Unit No. 4 exceeds 3340 hours of oepration. 2. Permittee shall equip the station to continuously measure sulfur dioxide, oxides of nitrogen, nitrogen dioxide, wind speed, and wind direction. 3. Permittee shall operate the station in accordance with the procedures specified in the Alaska Quality Assurance Manual for Ambient Air Quality Monitoring, dated August 1996, and as outlined in Ketchikan Public Utilities’ approved Ambient Air Quality Monitoring Plan to collect no less than one year of ambient data. 4. The Permittee shall operate the station to obtain a minimum of 80% data capture per calendar quarter for all parameters measured. 5. The Permittee shall submit within sixty days after the end of each calendar quarter to the Department's Air Quality Maintenance Section, Compliance Assurance Group, an ambient monitoring report summarizing monitoring data collected during the calendar quarter. Permittee shall include quarterly monitoring system quality assurance/quality control or calibration audit results as part of the report. G:\AIRFACS\kpu\X13\FINAL\9713AC13.doc page 10/19 Air Quality Control Construction Permit 9713-AC017 June 4, 1998 V. 18 AAC 50.040--Federal Standards Adopted by Reference The Permittee shall comply with the requirements of 40 CFR 60, New Source Performance Standards (NSPS), and 40 CFR 61, National Emission Standards for Hazardous Air Pollutants (NESHAP), as they apply to the equipment specified below. A. The Permittee shall submit a copy of all NSPS and NESHAPS reporting to the U.S. Environmental Protection Agency (EPA) Region 10 and the Department, as required by the applicable Federal standards. The Permittee may attach periodic federal reporting to the Facility Operating Report required by Condition I(G). The Permittee shall notify the Department of any EPA-granted waivers of NSPS or NESHAP emission standards, record keeping, monitoring, performance testing, or reporting requirements within 30 days after the Permittee receives a waiver. B. 40 CFR 60, Subpart Kb, Affected Facility--new 185,000-gallon fuel oil storage tank. 1. Applicabiliry and designation of affected facility, 40 CFR 60.110b. Volatile organic liquid storage tanks greater than 40 cubic meters in volume are subject to this Subpart as listed in 40 CFR 60.110b(a). N Standard for volatile organic compounds (VOC), 40 CFR 60.112b. The storage tank is exempt from 40 CFR 60.112b, provided the Permittee stores liquids with a true vapor pressure less than 3.5 kilopascals (kPa). 3. Testing and procedures, 40 CFR 60.113b. The storage tank is exempt from 40 CFR 60.113b, provided the Permittee stores liquids with a true vapor pressure less than 3.5 kilopascals (kPa). 4. Reporting and record keeping requirements, 40 CFR 60.115b. The storage tank is exempt from 40 CFR 60.115b, provided the Permittee stores liquids with a true vapor pressure less than 3.5 kilopascals (kPa). 5. Monitoring of operations, 40 CFR 60.116b. e Pursuant to 40 CFR 60.116b(a) and (b), the Permittee shall keep readily accessible records showing the dimension of the storage vessels. The Permittee shall keep readily available an analysis showing the capacity of the storage vessel for each affected facility (storage tank) greater than equal to 40 cubic meters for the life of the tank. G:\AIRFACS\kpu\X 13\FINAL\97 13AC13.doc page 11/19 Air Quality Control Construction Permit 9713-AC017 June 4, 1998 VL 18 AAC 50.055--Industrial Processes and Fuel-Burning Equipment Emission Limits—Unit Nos. 1-4. A. The Permittee shall comply with 18 AAC 50.055(a)(1) and 18 AAC 50.055(b)(1), which state that visible emissions, excluding condensed water vapor, from an industrial process or fuel-burning equipment may not reduce visibility through the exhaust effluent by greater than 20 percent, for a total of more than three minutes in any one hour, and particulate matter emitted from an industrial process or fuel-burning equipment may not exceed, per cubic foot of exhaust gas corrected to standard conditions and averaged over three hours, 0.05 grains. B. The Permittee shall comply with 18 AAC 50.055(c), which states that sulfur compound emissions, expressed as sulfur dioxide, may not exceed 500 ppm averaged over a period of three hours. The Permittee shall ensure compliance with this requirement by using only distillate fuel oil with a fuel sulfur content not to exceed 0.25 percent by weight. C. Monitoring and recording: The Permittee shall: J & ~~ L see cue 1. In accordance with Condition I(D) and wii day er beginning operation of Unit No. 4, conduct the following emission tests z(t? one visible emission surveillance on the exhaust stack oféachAnternal Sen U combustion engine while the engine is operating ater than 70% load:, and \ i one particulate matter source test onUnitNo while the unit is operating at greater than 70% load. Pier ’” ‘2. If requested by the department, conduct additional particulate matter emission tests fam 7 or visible emission surveillance, as set out in Condition II(D); and 3. Monitor and record fuel sulfur content in accordance with Condition IV(B)(4). D. Reporting--The Permittee shall: cue 1. Attach to the Facility Operating Report required under Condition I(G), each vt visible emission surveillance form for surveillances conducted during the reporting \e a ; x r ( period; ° NV Submit emission source test requirements in accordance with Condition I(D); 3. Report fuel sulfur content in accordance with Condition IV(C)(3); and 4. Report to the Department in accordance with Permit Condition I(H) when fuel with a maximum sulfur content of 0.25% by weight is not available. In the report, list the reason for the fuel oil unavailability. G:\AIRFACS\kpu\X 13\FINAL\9713AC13.doc page 12/19 Air Quality Control Construction Permit 9713-AC017 June 4, 1998 Vil. 18 AAC 50.110--Air Pollution Prohibited All Sources The Permittee shall comply with 18 AAC 50.110, which states that no person may permit any emission which is injurious to human health or welfare, animal or plant life, or property, or would unreasonably interfere with the enjoyment of life or property. To comply with this requirement, the Permittee shall: A. Install, maintain, and operate, in accordance with standard operating procedures, fuel-buring equipment, process equipment, emission control devices, and testing equipment and monitoring equipment to provide a optimum control of air contaminant emissions during all operating periods; B. Keep a log of all public complaints received regarding air emissions and the Bailey Powerhouse Facility, including the date, time, and nature of complaint. Attach a copy of the complaint log to the facility operating report required by Condition I(G); C. Take reasonable actions to address air pollution complaints resulting from emissions at the facility; and D. The Permittee shall notify the Department prior to selecting other equipment make, models, and size, to determine the applicability of Air Quality Control regulatory requirements. The Permittee shall notify the Department no less than 30 days in advance of any planned modification or replacement of the fuel burning equipment, which might result in increased potential air contaminant emissions. The notification must be in writing and must include a description of the proposed change and an estimate of any change in the quantity of emissions of each regulated air contaminant that may occur as the result of the modification or replacement. 3 G:\AIRFACS\kpu\X 13\FINAL\9713AC13.doc page 13/19 Air Quality Control Construction Permit 9713-AC017 June 4, 1998 VI. 18 AAC 50.315(e)(3)(A)—Best Available Control Technology (BACT) The Permittee shall install emission or operational controls as BACT for Unit No. 4. A. Limits--Best Available Control Technology limits: 1. Emissions of NOx from Unit No. 4 may not exceed 9.5 grams per brake-horse power- hour at full load. 2. Visible emissions from Unit No. 4, excluding condensed water vapor, may not reduce visibility through the exhaust effluent by greater than 10 percent, for a total of more than three minutes in any one hour, except for the initial half-hour after start-up. B. Monitoring and Record Keeping--The Permittee shall 1. Conduct an emission source test on Unit 4 in accordance with Condition I(D) to ascertain compliance with the emission limits listed in Condition VII(A)(1) no e ox Nee later than’90 days after the engine is commissioned; and Aik Pow Ba C —— _. ed 7 3 2. If requested by the department, conduct an emission source test on Unit 4 in ee ce foye” -% 7 accordance with Condition I(D) to ascertain the emission limits listed in 8 Condition VIM(A)(1). 3. Conduct a visible emission surveillance of Unit 4 in accordance with Condition VIL-C(1) and (2). C. Reporting—The Permittee shall 1. Submit the results of the source test on unit 4 as described in Condition I(D). 2. Submit visible emission surveillance records in accordance with Condition VI.C(1). G:\AIRFACS\kpu\X 13\FINAL\9713AC13.doc page 14/19 Air Quality Control Construction Permit 9713-AC017 June 4, 1998 EXHIBIT A " FACILITY OPERATING REPORT Submit to the Department two copies of the quarterly Faciliry Operating Reports, no later than the 30th day of April, July, October, and January for operations during the preceding calendar quarter as required in Condition II(G) of this permit. This report shall include the following information (all quantities must be reported, even if zero): 1. Facility Identification: Name of company, facility name, location, and permit number; Ketchikan Public Utilities Bailey Powerhouse 2930 Tongass Avenue Ketchikan, Alaska 99901 Air Quality Control Permit No. 9713-AC013 2. The report date and time-period covered by the report; 3. Operations Condition I(C) Sources Nos. 14 Total hours of operation for each diesel unit each month. 4. Fuel Consumption Condition IV(C) Sources Nos. 1-4 Total gallons of Diesel Oil combusted each month. 5. Fuel Quality Condition IV(C) Fuel Oil Sulfur content and date of each fuel delivery. Total Facility power production each month. 6. Public Complaint Log Condition VIB) 7. Unless submitted to the Department under separate cover, the Permittee shall attach or include reports as listed below in accordance with the Conditions cited below: Condition I(D), Source Testing Reports Condition I(H) and (1), Excess Emission Report Condition IV(C)(1), Construction Project Mileposts Condition IV(C)(4), Fuel Meter Certifications Condition VI(D)(1), Visible Emission Surveillance Forms 8. Certify and submit to the Department in accordance with Condition II(A). G:\AIRFACS\kpu\X 13\FINAL\9713AC13.doc page 15/19 Air Quality Control Construction Permit 9713-AC017 June 4, 1998 EXHIBIT B SUBMITTAL LIST 1. Certify and submit all notifications in accordance with Conditions II(A) and IB). 2. Submit reports and notices required under Conditions II(D)(2)-(5), for source tests. 3. Submit monitoring notices and requests set out under Condition I[(E) and (F). 4. Submit excess emission reports as set out in Conditions II(H) and I(]), and Exhibit D. 5. Submit facility change and modification notices as set out in Condition VI(D). 6. Submit quarterly ambient monitoring reports in accordance with Condition IV(D)(5) 7. Submit fuel injection timing retard notice in accordance with Condition VIM(C)(1). 8. Submit source testing measuring NOx emissions in accordance with Condition II(D) and VIO(C)(3). G:\AIRFACS\kpu\X 13\FINAL\9713AC13.doc page 16/19 Air Quality Control Construction Permit 9713-AC017 March 6, 1998 December 12, 1997 December 3, 1997 December 1, 1997 November 14, 1997 November 10, 1997 October 16, 1997 September 2, 1997 November 15, 1996 EXHIBIT C PERMIT APPLICATION DOCUMENTATION KPU response to comments. Supplemental information submitted from KPU to ADEC . Engine operating parameters from KPU to ADEC. Engine performance parameters from Wartsila to ADEC. Engine emission performance from Wartsila to ADEC. Engine performance parameters from Wartsila to ADEC. KPU response to ADEC Completeness review comments. PSD Application from KPU to ADEC. Diesel Power Plant Technical Specifications. G:\AIRFACS\kpu\X 13\FINAL\9713AC13.doc page 17/19 June 4, 1998 Air Quality Control Construction Permit 9713-ACO17_—- June 4, 1998 Excess Emission Notification Form, Exhibit D Please Note: ALL entries MUST be printed ALL time enties in military time Company. Facility. _ Permit Source Event Begin (Date & Time) __/__/_ Ls Event End (Date & Time) __/ / ___s_ (Include additional start end times if appropriate to event) 2a. Cause of Event (Check All that apply) © START UP O SCHEDULED MAINTENANCE 0 UPSET CONDITION 0 SHUT DOWN © BYPASS OF CONTROL EQUIPMENT O OTHER Describe the event and its cause (use additional sheets as necessary): 2b. Emission Standard Exceeded. Identify the emission standard or permit condition exceeded by the event. If a permit condition, state the permit number and condition exceeded. 2c. Actions taken to minimize excess emissions: G:\AIRFACS \kpu\X 13\FINAL\9713AC13.doc page 18/19 Air Quality Control Construction Permit 9713-AC017 June 4, 1998 Excess Emission Notification Form, (Cont.) Please Note: ALL entries MUST be printed ALL ume entries in military time Permit. Event Begin Date / / | 2d. Describe All corrective action taken to restore normal operation. 2e. Describe All actions taken (or to be taken) to prevent future occurrence of this type of event. Based on information and belief formed after reasonable inquiry, I certify that tke statements and information in and attached to this document are true, accurate, and complete. Printed Name: Signature. Date / / G:\AIRFACS\kpu\X 13\FINAL\9713AC13.doc page 19/19 LAKE TYEE - SWAN LAKE TRANSMISSION LINE INTERTIE PROJECT CAPITAL COST ESTIMATES (1997$) COST ITEM Construction Costs A. Transmission Line (57.5 miles) Segment 1: Tyee Lake - Bell Arm Segment 2: Bell Arm - Behm Narrows Segment 3: Behm Narrows - Shrimp Bay Segment 4: Shrimp Bay - Swan Lake Subtotal of A. B. Switchyards / Substations Tyee Lake Switchyard Swan Lake Switchyard Bailey Substation Subtotal of B. Subtotal 1 (construction costs A + B) C. Potential credit for timber Subtotal 2 (construction costs A + 8 +C) Other Costs Licensing/Permitting Engineering/Investigations Const. Mgmt. at 5.0% of Const. Cost: Right of Way Costs (Stumpage) Contingency at 15.0% of Const. Cost: Subtotal 3 (construction + other costs) Owner's Cost at 4.5% of Subtotal 3 Subtotal 4 (constr. + other + owner costs) TOTAL ESTIMATED PROJECT COST With no timber credit $20,203,988 $4,213,145 $9,665,300 $18,955,976 $53,038,410 $300,000 $1,200,000 $750.000 $2,250,000 $55,288,410 $55,288,410 $2,000,000 $5,500,000 $2,764,420 $48,000 $8,293,261 $73,894,092 $3,325,234 $77,219,326 $77,219,326 January 1998 Estimate With minimum domestic timber credit $20,203,988 $4,213,145 $9,665,300 $18,955,976 _ $53,038,410 $300,000 $1,200,000 $750,000 $2,250,000 $55,288,410 ($4,300,000) $50,988,410 $2,000,000 $5,500,000 $2,549,420 $48,000 $7,648,261 $68,734,092 $3,093,034 $71,827,126 $71,827,126 Assumes project is bid in spring of 1998 for two years of construction. Assumes work willbe done under four independent contracts. The four contracts would be broken down to three for the transmission line and one for the substation work. AS a ae PU Storer Oy Comme With maximum export timber credit $20,203,988 $4,213,145 $9,665,300 $18,955,976 $53,038,410 $300,000 $1,200,000 $750,000 $2,250,000 $55,288,410 ($11,300,000) $43,988,410 $2,000,000 $5,500,000 $2,199,420 $48,000 $6,598,261 $60,334,092 $2,715,034 $63,049,126 $63,049,126 Swan Lake- Lake February 1998 ae ees SWAN LAKE - LAKE TYEE INTERTIE REVISED CONSTRUCTION SEQUENCING & TIMBER HANDLING I. Introduction: Construction funds for the Swan Lake - Lake Tyee Intertie transmission line are not available in the amounts necessary to release the work for construction as originally planned. The sequence originally planned for procurement and construction must be revised to fit the available funds and environmental constraints. Originally it was expected that all of the project construction would be performed over a two year period under two separate construction contracts. The first contracting stage would have been for construction of the transmission line itself. That contract would have included all of the logging, clearing and installation of the transmission line elements. The scheduling of the work would have been at the contractor’s discretion to make the best use of his equipment as long as he met the required completion date. It would also make one contractor responsible for the fit and function of all equipment he installed. The second contract would have been for the construction of the terminal substation modifications and installation of the system control requirements to complete the project. In addition to the construction contracts, there would have been a number of individual material procurement contracts for major items let at the same time as the construction bidding. These would be for the transmission line towers, the conductor and hardware for the line, as well as the substation transformers, breakers and switches. The materials would have been purchased on a schedule to meet the construction contractor’s needs. The first year’s construction was expected to include all corridor logging and clearing and installation of some if not all of the foundations. It was expected that no materials to be procured by KPU for the project would be installed in the first construction season. The second construction season would include the completion of the foundations and installation of the towers, conductor etc., and the substation work. IL. Current Status: The cost of the total project in, 1997 doilars for the present design and work sequencing is currently estimated at $77 million including a 15% contingency. This estimate does not include any credit for the value of timber from the corridor. Of this, $53 million is for the direct cost of construction of the transmission line alone. The balance is for the necessary substation modifications and upgrades, KPU costs for permitting and engineering costs, construction inspection support and administrative costs. This estimate was prepared on the assumption that the transmission line construction contract would be issued as a single contract. It assumed two construction seasons with two mobilizations and de-mobilizations of field crews. To date KPU has received $11.2 million in grants for the project from the State of Alaska. KPU is in the process of applying for a $10 million federal appropriation for this project which is to be administered by the U. S. Department of Energy. This grant may lapse unless it’s funds are committed within a specific time frame. KPU is seeking an additional $30 million in grant funding Page | Raytheon Infrastructure Inc. February 1998 Swan Lake - Lake Tyee Intertie OY RY LLL ae from the Federal Government, as well as an additional $20.0 million low interest loan set aside by the State of Alaska for this project (3%, 15 year). In addition, KPU will continue to seek 40% of the Four Dam Pool debt service payments. In order to minimize risk to the City of Ketchikan, it has been proposed that this loan not be accepted until the remaining grants are in place. Table I presents a tabulation and total of these amounts. TABLE I Source of funds State grants to date 94-98 $11.2 million Secured and available Federal grant (FY98 $10.0 million Application being prepared Additional State funding requested: $ 2.0 million No current commitment Additional Federal funding $30.0 million No current commitment City of Ketchikan debt (State Loan $20.0 million No current commitment $73.2 million* [| * based upon the 1996 design level and construction plan I. Required Changes: Because of the limited funding available, and there exists some uncertainty as to when full funding may be made available, it is necessary that the work be sequenced in a way that uses the financial resources effectively and will best meet the following criteria: 1. Early environmental impacts on the forest will be minimized, 2. KPU can control the construction timing and payment schedule, 3. Restoration needs would be minimal at the early phases if further financing is not obtained, 4. Projections of the cost of each contract can be reasonably estimated for each phase. When changing the timing and sequence of the work it must be recognized that the overall cost of the project will be greater than originally anticipated. This will be true if: ¢ more than two construction seasons are required, ¢ construction contracting is broken down into multiple small packages, e fabrication and supply of the major materials is delayed. These increases in cost occur because each element of the work which is delayed will be impacted by inflation. The contractors will price their work to cover any elements of uncertainty. They will also have to increase costs to cover lower utilization factors for equipment and facilities i.e., helicopters, log processing barges and personnel camp facilities when doing only a small portion of the project at any time. Multiple requirements to mobilize and demobilize equipment and crews also drives up the costs. IV. Proposed Changes in Sequence to Meet Requirements: The impacts stated above can be minimized, but not éliminated, by changing the sequencing of the procurement and construction work. The following revised work sequence is suggested to accomplish this: Phase 1: Commence procurement of the major materials based upon the available funds. This would include the following steps: l Page2 980213SQ.D0C Raytheon Infrastructure Inc. Februarv 1998 Swan Lake - Lake TF q Le ae Lee Issuing bid documents for the towers, hardware and conductor, Issuing bids for the substation transformation equipment, Awarding these contracts to the limit of the financing available, Releasing the engineering work for designing the foundation pile caps that are a part of the tower supply contract, e Withholding release of the actual fabrication of the materials and the design and fabrication of the towers until further financing is assured, e Include an escalation and cancellation clause in each material procurement contract to allow computation of the price at the time of release for fabrication or contract cancellation should the latter be required. Phase 2: When sufficient additional funds are assured to allow work in the field to commence and be completed, proceed in the following manner: e Issue construction bidding documents for the level of construction which can be accomplished with the newly available funds. For this analysis, it is assumed that these amounts are in not less than $20 million increments. With this amount of funding, the work may be limited only to foundation work at the tower sites which, if priced acceptably and awarded, would allow the following work sequence to be carried out: e Release fabrication and delivery of the pile caps by the tower manufacturer as arranged in phase 1, e Issue the selected contractor a notice to proceed to commence the specified construction work which will include: Surveying of each tower site to set the clearing limits and the location of each tower leg and guy anchor, Logging and clearing of each tower site, Installation and testing of the foundation piling system and the guy anchors, Installation of the pile caps on the foundation piling, Surveying to record the “as-built” foundation elevations and guy locations so as to have the final information needed for release of the tower fabrication when ready. “e+e ¢ At completion of this phase, the field work remaining to complete construction of the transmission line is then reduced to clearing and logging of the balance of the corridor, the assembly and erection of the towers in the field, and installation of the hardware, insulators and conductor and testing the line. The substation work for connecting the terminals and receiving the power would still remain to be done. Phase 3: It is assumed that, by the third phase, the final financing needed from the State and/or Federal Government will have been secured and that the balartce of the funds needed for construction will have been financed by completion bonds issued by the City of Ketchikan. This being the case, the work to be authorized would then be: e Release the balance of the materials ordered under phase 1 for fabrication and delivery including the towers, insulators, hardware, conductor, transformers etc., Page3 ease Raytheon Infrastructure Inc. Februarv 1998 Swan Lake - Lake Tyee Intertie Construction Sequencing... ¢ Release bid documents and award a single construction contract for the balance of the logging and clearing of the corridor, installing the towers and stringing, clipping and tying in the conductors and testing the line. e Issue bidding documents and award a contract for the construction of the substation upgrades at Lake Tyee, Swan Lake and Bailey substations V. Timber Handling One of the areas of greatest uncertainty in the project is the work and cost of clearing and logging of the transmission line corridor. Depending upon what arrangements any contractor can make in timber marketing contracts, the net cost to KPU to log and clear the corridor can range from almost nothing to as much as $8 to $10 million dollars if little or no recovery is made through the sale of the timber. This variability is due largely on the timber yield, the mandatory removal requirements and the marketability of the timber removed. The uncertainty is further complicated because: e the cost of the work is heavily dependent upon the amount of clearing and logging that will be made available to the contractor under each contract phase the amount and type of timber that is required to be removed is uncertain the extent of the clearing required in the corridor could change the market value of the timber removed is constantly changing mobilizations for this work are expensive, their number is uncertain equipment utilization varies greatly depending upon the scenarios to be bid To reduce the uncertainties which are related to the logging aspect as much as possible, discussions are underway with the Forest Service to clarify, in the special use permit, the types and size of timber that must be removed. Because of the fact that this work must be done largely by helicopter, the logging will be a deficit operation, i.e., the logs will cost more to remove than they will produce in market value. It is important to keep in mind that this is not a logging sale but rather a transmission line construction project requiring the removal of the timber because it is in the way. Because of this, it may be possible to obtain some relief from the Forest Service on the extent of the removal required. An example of this is the utility logs which, largely because of the closure of the mill in Ketchikan, have virtually no market value in Southeast Alaska. Under Forest Service rules for a timber sale, their removal is required because, when they are of sufficient size, they are empirically defined as “merchantable”. If there is virtually no market for them the term “merchantable” losses its meaning. Discussions are underway to try to reduce the requirements for removal of logs that fall in this category. If successful, the cost of the logging and clearing operation may be substantially reduced. VL An Alternate Scenario to Improve Equipment Utilization and Logging Given the fact that the sequencing of the clearing and logging effort has such a large impact on the cost of the project, an alternative to the second phase of the work presented above is worthy of consideration. The objective of the alternate would be to maximize the utilization factor for the equipment used while installing the tower foundation systems. It may be possible to do this by combining the clearing of the corridor and installation of the tower foundations at the same contract. This would allow the helicopters that will be moving the construction equipment to and from the tower sites to be used also for transporting logs in the same work phase. Page 4 980213SQ.D0C Raytheon Infrastructure Inc. Sar Februarv 1998 Swan Lake - Lake ( “onstruction Sequence: If this were done, the first phase of material procurement as described previously would be retained. The second phase of the work would combine the work of logging, clearing and installing foundations into a bidding package. These would then be issued as packages for the geographical segments of the line, i.e., from the Bradfield Canal to Behm Canal, Behm Canal to Shrimp Bay, and Shrimp Bay to Carroll Inlet. The sequence which would apply to the field work uner this plan would be: Phase 2A: e Issue construction bidding documents for simultaneous logging and clearing of the corridor and the installation of foundation systems within selected corridor segments based upon the amount of financing available, e Ifacceptable bids are received, award a construction contract to perform this work in a single pass through each corridor segment rather than in the two step process identified earlier. Work to be done would include the following: Surveying of the corridor segments to mark the clearing limits, ¢ Logging and clearing of the corridor within those clearing limits, ¢ Surveying of the each tower site to set the clearing and grubbing limits and to set the location of each tower leg and guy anchor, ¢ Clearing and grubbing of each tower site within its clearing limits, ¢ Installation and testing of the foundation piling system and the guy anchors at the tower sites within the segment, Surveying each tower site after completion of the work to record the “as-built” pile locations and elevations to have information available for the tower suppliers in the next phase. Depending upon the timing of the release of funding for the project, this sequence may be required to be repeated two or more times. Once the financing is known and the work schedule can be set, the above sequence may prove to be more cost effective than the first sequence proposed. After this phase of the work in each corridor section has been completed, the work remaining would be the erection of the towers, stringing tying and clipping of the conductors and testing of the line. It is assumed that this work would be bid as a single contract for the final phase of construction of the line and would consist of the following: Phase 3A: e Issue bidding documents and award a contract for the balance of the transmission line construction including installation of the transmission line towers, stringing, clipping and tying the conductors etc. to complete the transmission line. e KPU release for fabrication of the towers for delivery and installation. e Issue bidding documents and award a contract for the construction of the substation upgrades at Lake Tyee, Swan Lake and Bailey substations. Other scenarios can be conceived. Doing so at this time is of little further value until a more specific plan of financing has been defined. Page 5 980213SQ.D0C Raytheon Infrastructure Inc. February 1998 Swan Lake - Lake Tyee Intertie Construction Sequencing... VI. Pros and Cons of the Scenarios Each of the above scenarios will result in increased costs to the project over the original project plan for the reasons described previously. These cost increases are indeterminate until the final financing scenario is known and the sequence of the work that can be done within this financing stream is finalized. The benefits and disadvantages of the above scenarios are enumerated below: First scenario Advantages: It will delay, to the maximum extent possible, entry into the forest resulting in the absolute minimum early forest impacts It will put at risk the lowest amount of money at the first phase It will allow the considerable latitude in subsequent phasing alternatives as additional financing is released regardless of the amount of future funding releases It will provide more time for resolution of financing issues before commencing field work It will minimize the restoration requirements should the project not proceed The construction funding currently available is close to the estimated material costs It would allow KPU to make better use of subsequent larger financing blocks if they were to materialize, i.e., the second contracting phase could be modified to allow better utilization of equipment Disadvantages: It will require that escalation factors and escape clauses be built into the material procurement contracts which will add uncertainty into the final cost of the materials during the balance of the financing. It will delay active field construction which may cause the project to lose momentum It will divide the responsibility between the contractors for fit of the foundations with the structures Second scenario (alternative) Advantages: Earlier entry into the field may better maintain the momentum of the project, It will increase the utilization factor of the construction equipment during installation of the foundations, The work packages can be tailored to the financing available if it is parceled out in small amounts while maximizing the utilization factors for the equipment, The final phase would be limited to a single concentrated effort which will specialize in the transmission line elements only. Disadvantages Impacts to the forest will occur earlier and be greater than for the base alternative, Restoration requirements, should the project not proceed, may be slightly greater, Re-growth of the forest in the corridor will commence earlier than if this was left to the very last element of work. This could be significant if the delay were substantial because of the rapid re-growth expected to occur. Page6 980213SQ.D0C Raytheon Infrastructure Inc. OTN Re Lae Februarv 1998 Swan Lake - Lake VU. Conclusions The sequence of construction that can be followed is dependent upon the money that will be available in each construction season. It can be expected that issuing construction packages in smaller increments than originally planned will result in higher costs for the overall project. Options that will minimize these impacts are available. The alternatives presented herein can allow the project to proceed with minimum risk to KPU while allowing time to secure final financing. Selecting early material procurement as the first step allows the greatest latitude to resolve these issues. Carefully sequenced bid packages can control the additional incremental cost and exposure to KPU. Once work commences in the forest, it is important that the work proceed to completion otherwise some of the work may be overrun by re-growth before it can be put to beneficial use which would be very undesirable. Completion of the discussions with the Forest Service to finalize the constraints that will be applied to clearing and logging is essential to reducing the cost of the logging and clearing and achieving the greatest return to KPU for the value of the timber. VII. Recommendation It is Raytheon’s recommendation that KPU proceed with the procurement of the material as presented in Phase 1 of this document. The selection of the option for Phase 2 of the work is best made when the clearing requirements are finalized by the Forest Service in their special use permit and the financing plan is known and proceeding successfully. Bidding of the field construction work is best done in the fall/winter time frame to secure the most competitive bidding by contractors for this work. The time frame for this decision would then be by the end of October with bidding to take place immediately thereafter. Page7 980213S8Q.D0C Raytheon Infrastructure Inc. KETCHIKAN PUBLIC UTILITIES Memorandum To: The Honorable Bob Weinstein & City Council From: John Magyar, KPU General Manager OF, ee Date: February 27, 1998 Subject: Power Supply Options—Staff Opinion There are two basic hydroelectric strategies that staff has been pursuing. One is construction of the Swan-Tyee Intertie which will allow us access to surplus energy at the Lake Tyee project. The other is a combination of local small hydroelectric projects. Staff recommends that Council continue to pursue the Intertie strategy while developing the small hydroelectric alternative. Pursuing licensing efforts for the Whitman, Connell and Carlanna projects, considering proposals for Metlakatla and Mahoney power sales and developing the most cost effective construction sequence for these options will provide us a backup pian if the Intertie fails to obtain necessary funding or voter approval. While this memorandum address staff opinion with regard to both Swan-Tyee Intertie and small hydroelectric strategies, action requested by staff at the March 5, 1998 Council meeting simply relates to the timing of initial construction activities of the Intertie using grant funds. Unless explicitly directed by Council to the contrary, staff will continue to pursue the Intertie as the primary strategy and small hydroelectric as an alternative strategy. If we are unable to proceed with fuil construction of the Intertie for lack of funding, we would be in a position to make a fuil commitment to the small hydroelectric alternative with a bond election for the Whitman project in the year 2000. Staff recommends that we use these next two years to seek a complete funding package for the Swan-Tyee Intertie. A discussion of the Intertie and small hydroelectric strategies follows. Swan-Tyee Intertie: Staff continues to consider the Swan-Tyee Intertie as the strategy that would best meet the energy needs of Ketchikan over the long term. In the early 1990’s, the Intertie was investigated as a means to make surplus available at Lake Tyee to meet the hydroelectric shortage in Ketchikan. In 1993 the State enacted legislation which provided a combination of annual grants and $60 million in loans and bonds to KPU for the project. This funding allowed us to begin the engineering and permitting efforts in 1994. The Swan—Tyee Intertie is an expensive project but provides unique opportunities to the community which cannot be overlooked. The sale of surpius Tyee energy is a win-win H:\USER\NANCYL\WP\DATA\007-D1.MEM Mayor and Council, Power Supply Options—Staff Opinion February 27, 1998 Page 2 proposition for Ketchikan as a customer and a member of the Four Dam Pool, allowing us to supply our ratepayers with low-cost hydroelectricity while enjoying a portion of those revenues through the Four Dam Pool. The Intertie will allow us the reliability and flexibility of sharing regional resources, giving us the same kind of benefits the Bonneville Power Administration has given the Pacific Northwest. Access to large regional hydroelectric resources will allow Ketchikan to avoid dependency on fossil fuel generation for decades into the furure. Finally, we would be taking advantage of our delegations’ strong position in Washington D.C. as well as a sympathy factor there for the harm done to the Southeast Alaska timber industry, a combination of events we are unlikely to ever see again. With the news of the pulp mill closure in September of 1996, we were no longer able to depend on enough revenue to fund the Intertie. What is worse, we also were losing the backup generating capacity that the mill was often able to offer us. Without the mill, the loss of Ketchikan’s single largest generation facility (Swan Lake) would put the community into a rotating blackout situation. The Ketchikan voters in October of 1996, the month after the mill closure was announced, voted to approve a $13.7 million bond issue for a diesel generator. This generator will allow us to provide sufficient backup power to avoid blackouts when Swan Lake is off-line. Ketchikan’s energy demand had not diminished but we had lost generating capacity and revenue to fund the Intertie with the closure of the pulp mill. With that in mind, City Council approved a lobbying plan to seek federal funding for the Intertie. Due to the efforts of Senators Stevens and Murkowski, and Representative Young, $10 million was provided for the Intertie in the FY98 federal budget. Another $30 million will be sought in FY99. Since this project became a regional priority im the late 1980’s, City Council has been asked on numerous occasions—Do we continue with the Intertie or stop now? We are at another decision point. Do we proceed with bidding first year construction? Senator Stevens and his staff were very clear when we visited last year—the federal government budgets one year at a ume, if you are seeking federal funding you’ve got to recognize that you must proceed on faith. In turn, our lobbying group responded that we can do that provided that we are not obligated to spend local dollars until the last year of construction. Staff believes that a decision not to proceed will result in the loss of the existing $10 million federal allocation. Senator Stevens needs to know by mid- March whether the Intertie is going forward in order to seek FY99 funding. If one is optimistic about the Ketchikan economy, the Swan-Tyee Intertie is clearly our most cost effective power strategy for the future. While we have commissioned and distributed an Electric Load Forecast that considers the closure of the pulp mill, there is significant difference between the high, base and low forecasts. Staff recommends that in planning for future power supply infrastructure that we act conservatively and consider how we might meet the higher demands. In particular, Council should note that the “base” case does not assume new demands from new industry at the pulp mill site, or our need to supply energy to the KPC saw mill resulting from their recently announced closure of their power house. H:\USER\NANCYL\WP\DATA\O07-D1.MEM Mayor and Council, Power Supply Options—Statf Opinion February 27, 1998 Page 3 Despite the advantages just noted, staff does have some unresolved concerns about the Intertie. One major concern is the risk associated with low load growth. Under our current proposal, a short-term loan through AIDEA would allow us to meet our expenses during years of low load in the first years of Intertie operations. But we are depending on load growth in later years to pay back that loan. If the load growth does not develop, we could be left with a significant debt at the end of the loan term. cost increases if the project is delayed for lack of additional grant funding. In addition, as with / AR any construction project, there is always the risk of cost overruns for other difficulties such as | unknown field conditions, weather, etc. In either case, KPU would bear the risk of cost overruns/ / or be forced to terminate the project after considerable expense of public funds. | Another concern is the risk associated with project cost overruns. We will definitely experience Unless otherwise directed, Staff will continue to seek loan and power sales terms that will mitigate these risks. In addition, staff suggests considering an escalation of lobbying efforts to seek State development of the Swan-Tyee Intertie. It has always seemed appropriate to have the owner of the Four Dam Pool (the State of Alaska) develop and own this improvement to their facilities. Smail Hydro Alternative: Staff opinion is that the most logical alternative to the Swan-Tyee Intertie is phased development of local small hydroelectric projects. These would include Whinman Lake, Lake Connell, Carlanna Lake, a Metlakatla Intertie, Mahoney Lake and upgrade of Beaver Fails. The recommended approach would be to develop the most cost effective projects first and proceed with future development as demand grows. Under the ISER medium load growth case for example, we could commission the Whitman Lake project in 2003 and the Lake Connell project in 2009. In 2016 we could seek a power purchase agreement with Metlakatla or Cape Fox since both offer similar energy capability. Under the medium load growth scenario, this combination would offer hydroelectric energy beyond the year 2030. An advantage of this strategy is that these projects could be developed as needed. So if Whitman Lake were the first to be developed, our only near term obligation would be the construction cost of $7.5 million. If in fact we experience the ISER forecast low load growth, we would have no additional capital requirements until 2025 when we would need to commission the next project. Therefore, if low loads are considered a possibility, this approach minimizes our risk. The primary disadvantage of this strategy is that we will eventually be in need of an Intertie when our local small hydroelectric resources are exhausted. Under the ISER high load growth case, all local hydroelectric options would be fully exhausted in 2022 (assuming development of Whitman, Connell, Carlanna, Metlakatla, Mahoney and an upgrade of Beaver Falls). At that H:\USER\NANCYL\WP\DATA\O07-D1.MEM Mayor and Council, Power Supply Options—Staff Opinion February 27, 1998 Page 4 point, we would need the Swan-Tyee Intertie to access the next major cost effective hydroelectric resource. With respect to the individual projects, staff offers the following comments. The Whitman Lake project turns out to be surprisingly cost effective under the design concept offered by WEScorp (4.8 cents per kWH). The Lake Connell project provides less energy at a slightly higher price (6.7 cents per kWH) but is the next most cost effective option. Staff is not as enthusiastic about Carlanna Lake as it is even smaller and more expensive (9.1 cents per kWH). However, we recommend that any hydroelectric option at a cost less than diesel not be abandoned at this point. The two largest local hydro options are the Metlakatla Intertie and Mahoney Lake. Our initial sense is that the Metlakatla Intertie offers the more cost effective energy of the two projects, but we lack firm data to support this. Our major concern is the lack of an independent review of the proposed improvements to the Metlakatla system. On the other hand, we have had substantial review of the Mahoney Lake data. It appears that Mahoney Lake energy would be more expensive than Whitman or Connell, but less expensive than Carianna. Statf has two noteworthy concerns regarding Mahoney at this point. The first is cost risk associated with the significant amount of underground work. Uniike our other alternatives, a lot of this project cost is loaded into underground work which is more difficult to estimate with certainty. The second is the highly encumbered license obtained by Cape Fox for this project. Pursuing this as a PURPA project has placed Cape Fox in a more difficult position with respect to negotiating terms with the regulatory agencies. If this project were to be pursued, KPU would probably be in a better position to have the existing license vacated and negotiate a new license with FERC. It should be noted however that both Metlakatla and Cape Fox have indicated an interest in negotiating a deal with KPU. Understanding that we may not realize the funding necessary to complete the Intertie, staff believes it is in the best interest of the rate payers to entertain proposals from both of these groups. Our view is that proceeding with the preparation of certain construction activities for the Swan-Tyee Intertie in no way interferes with our efforts to position the most cost effective small hydroelectric projects for development in the event they are needed. JAM:RDT:ail Attachment H:\USER\NANCYL\WP\DATA\O07-D1.MEM HYDROELECTRIC ENERGY SUPPLY AND DEMAND 300 250 |- HY|DRO SUPPLY 200 |- 150 |- MEGAWATT-HOURS (MWH) Thousands \ + 100 |- | /_| _ DEMAND al 50 |- 0 fotipt dtp dt dtp tp pp et tt tl 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 YEAR [SWAN-TYEE INTERTIE (2000) | 300 250 150 100 MEGAWATT-HOURS (MWH) Thousands 50 HYDROELECTRIC ENERGY SUPPLY AND DEMAND FOR LOW LOAD GROWTH 200 |}- SUPPLE : werent Pe yee | ¥ J nh ee a a | _ — \ p> = SN ST. DEMAND foi dtpptp ity t tp tp ppp tp ppp tt a ta tt 1975 Lo 1980 1985 1990 1995 2000 2005 2010 2015 2020 YEAR WHITMAN (2003), CONNELL (2025) | 2025 z HYDROELECTRIC ENERGY SUPPLY AND DEMAND FOR MEDIUM LOAD GROWTH 300 HIGH 250 |- nil = Bade tated Lt Ws HYDRO-~.| __ MEPIUM is an) SUPPLY | ~~~ Jo Til c ; | Low f B 150 |- 4 AN ee ey |e an) es nN = 100 |- Ha DEMAND = niin 50 |- OW bittttitiri tip a 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 YEAR |WHITMAN (2003), CONNELL (2009), METLAKATLA (2016) = & HYDROELECTRIC ENERGY SUPPLY AND DEMAND FOR HIGH LOAD GROWTH 300 HIGH 250 200 MEDIUM Low 150 100 MEGAWATT-HOURS (MWH#) . Thousands ttt 4 fidddppet pp yy tra yy Jot tt tt ttt} } 144 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 YEAR WHITMAN and CONNELL (2003), METLAKATLA (2006) MAHONEY (2015), CARLANNA and BEAVER FALLS (2022) JECEIVE D August 17, 1998 AUG 2 + 1998 MEMORANDUM KPU Manager's Office TO: Robert E. Newell, Jr., CPA sii sa dL John Magyar Rich Trimble FROM: Alan Dashen SUBJECT: Ketchikan Public Utilities Debt for the Tyee-Swan Lake Intertie Included in the financing plan developed for KPU to finance the Tyee-Swan Lake Intertie are two loans which would be secured by a pledge of revenues of KPU and would require a vote of the City. The first loan is for $20 million from the State of Alaska and is repayable over 15 years at an interest rate of three percent. The second loan, while not committed to, was planned to be from AIDEA and would be used as a start-up loan. This start-up loan would be used to finance a portion of the cost of the mtertie debt and operations during the first years of operation so that the net cost of power from the intertie would not exceed the cost of power that KPU curently is paymg for Four Dam Pool power from Swan Lake. As shown on Enclosure 1, using the City’s base load growth forecast, the AIDEA loan balance would increase annually to a maximum of $11,416,873 in 2014 and would not be repaid until 2020. This includes the assumption that the City would receive no “development charges” for proceeding with the intertie. It is, at best, unlikely that such a loan agreement would be agreed to by the City, AIDEA, and the Four Dam Pool Participants who must approve any power purchase agreement, and, when this was discussed with the Ketchikan City Council in February, we recommended that the City pursue additional grant money to reduce or eliminate the $20 million State loan and the AIDEA start-up loan. - These loans also will affect KPU’s ability to issue additional debt, and this memorandum is in response to your request of an analysis of this impact. While the intertie provides KPU with a good long term power supply, presumably at the same cost of power as Swan Lake, the financing pian as presented negatively impacts KPU and the Electric Utility. These negative impacts include the following: 203 BELLEVUE Way NE SUITE NO. 1+ BELLEVUE. WA 9800+ TeéL. 425-452-9550 Fax.+25-+52-9552 N we In the near term, the actual cost of power to the Electric Utility may increase with the Intertie. The Intertie power initially will offset diesel power, and, while diesels are not a good long term solution to the City’s power supply, the short term impact of utilizing Intertie power rather than the City’s diesels is slightly higher generation costs. The current Four Dam Pool power rate is approximately 6.8 cents/kWh, of which 4.0 cents/kWh is fixed. Since the variable portion was recently increased, we have assumed that the variable portion will escalate at 3.0% annually starting in 2000, The incremental diesel fuel cost to generate power currently is approximately 4.3 cents/kWh, based on 14.07 kWh/gailon of fuel and a fuel cost of $0.67/gallon. In addition, R.W. Beck estimates variable O&M at 1.3 cents per kWh. The projected KPU Intertie purchases range from 8,900,000 kWh in 2001 to 57,700,000 kWh in 2028. In 2002, the year used herein for comparison purposes, intertie purchases are projected to be 11,000,000 kWh. In that year KPU would pay $776,560 for intertie power compared to $671,000 for diesels. Note that this does not assume an increase in diesel fuel above $0.67 per gallon. As of December 31, 1997, KPU had outstanding $36,925,000 in debt. The $20 | million State loan significantly increases the debt of the system. A ratio used by Moody’s Investors Service to measure the leverage or a utility is long term debt to net utility plant plus current assets. Based on 1997 year end financial statements for KPU, this ratio (expressed as a percentage) currently is approximately 38%. If the debt is increased by $20 million, the ratio increases to 60%, which while still acceptable reflects a more highly leveraged utility. Under the financing plan, KPU would have outstanding both the $20 million State loan and the startup loan. However, as the start-up loan increases, the State loan decreases. Further, the startup loan probably would not be viewed as long term debt so it would not affect the above ratio. Consequently, only the long term State loan is included in this calculation. The additional borrowing will have an effect on debt service coverage, assuming that the State and AIDEA loans are on parity with KPU’s outstanding debt. Conceptually, the only portion of the State loan which should be inchided as debt service is that part not paid by the start-up loan. In practice, however, a rating or bond insurance analyst will be skeptical of a deal where a start-up loan is used to finance the intertie for so many years, with repayment based on continued load growth. A more conservative analytical approach would be to not consider the start-up loan and analyze the impact of the State loan assuming that it is repaid from revenues of KPU. Enclosure 2 shows the effect on debt service coverage for both approaches. Alternative (A) shows the income statement and debt service coverage for 2002 as forecast in the official statement for KPU’s 1997 revenue bonds. Alternative (B) assumes that only that portion of debt service not paid by the startup loan is included, and Alternative (C). assumes that all the State loan is included. Also included in Alternatives (B) and (C) is the slightly higher assumed power cost with the intertie. The original forecast of debt service coverage, Alternative (A) is 1.59. This decreases to 1.44 for Alternative (B) and 1.25 for Alternative (C). If KPU pursues these loans as part of the intertie financing, we would recommend that the loans be made junior in lien to the system’s outstanding debt. This will significantly mitigate the impact of these loans on the ability of KPU to issue additional debt. With the loans as junior lien, the debt service coverage on the senior lien debt would not be directly impacted. However, rating analysts typically will also calculate debt service coverage based on total debt outstanding, both junior and senior lien. Clearly, utilizing the State loan will have an impact on KPU’s ability to issue debt, both for the reasons outlined above and because of the potentially very long pay back of the startup loan. The intertie is a more viable power supply to the City if additional grant money is | available to reduce or eliminate the State and AIDEA loans. While this analysis has focused on the imtertie, any new power supply resources financed by KPU will affect fixture powering of the utility. However, because the intertie is a large investment with a slow pay back, other resources may have less of an impact on KPU future borrowing. SWAN-TYEE INTERTIE REVENUES & EXPENSES BASE LOAD GROWTH MEDIUM PMP&L INTERTIE FOUR DAM POOL RATE SALES PMC POWER RATE : INTERTIE EXPENSES NET REVENUES Additional Intertie | Debt Service O&M Tyee State Ending Net Payment Sales $0.04/kKWh $0.028/kWh Expense Intertle Loan Development Net Balance on to Year (MWh\1)] = Fixed = Escalated (2)} $.0026/hWh 08M(2) —$20,000,000(3) Charges(4) | Profit/oss AIDEA Joan Pool 2001 6,900] $ 356,000 264,376 | $ 22,250 $ 141,764 $ 1,675,332 $ - $ (1,218,970) $ 1,279,818 2002 = 11,000 440,000 336,560 27,500 146,017 1,675,332 - (1,072,289) 2,469,818 2003 12,600 504,000 397,080 31,500 219,609 1,675,332 - (1,025,361) 3,669,938 2004 = 14,100 664,000 457,681 35,250 154,909 1,675,332 - (843,810) 4,738,435 2005 = =15,600 624,000 621,562 39,000 159,656 1,675,332 - (728,326) 5,741,149 2006 =17,100 684,000 568,864 42,750 164,343 1,675,332 - (609,561) 6,668,246 2007 18,700 748,000 663,261 46,750 169,273 1,675,332 - (480,074) 7,605,737 2008 20,300 612,000 741,633 50,750 415,057 1,675,332 - (587,506) 8,497,905 2009 = 21,900 876,000 824,080 64,750 250,026 1,675,332 - (280,018) 9,216,619 2010 23,500 840,000 910,826 58,750 267,627 1,675,332 - (140,783) 9,825,482 2011 = 25,100 1,004,000 1,002,025 62,750 265,253 1,675,332 - 2,680 10,313,932 2012 26,800 1,072,000 1,101,988 67,000 273,210 1,675,332 - 158,446 10,663,261 2013 28,500 1,140,000 1,207,047 71,250 681,370 1,676,332 - (80,905) 11,281,374 2014 30,100 1,204,000 1,313,055 76,250 356,311 1,675,332 - 408,162 11,416,873 2015 31,800 1,276,000 1,433,324 79,750 369,060 1,675,332 - 585,161 11,373,276 2016 33,600 1,344,000 1,554,999 64,000 380,132 - 2,434,867 9,385,330 2017 += 35,400 1,416,000 1,687,452 88,500 391,636 - 2,623,416 7,100,010 2018 37,100 1,484,000 1,621,542 92,750 1,158,080 - 2,054,702 6,297,573 2019 38,800 1,556,000 1,967,216 97,250 617,627 - 2,808,139 2,508,905 2020 40,800 1,632,000 2,125,201 102,000 633,362 - 3,121,639 - 612,933 2021 42,700 1,708,000 2,280,693 106,750 649,363 - 3,342,781 3,342,781 2022 44,600 1,780,000 2,459,089 111,260 565,844 - 3,561,995 3,561,995 2023 46,600 1,864,000 2,652,390 116,500 1,557,850 - 2,842,040 2,842,040 2024 46,900 1,956,000 2,666,601 122,250 600,303 - 4,100,248 4,100,248 2025 51,100 2,044,000 3,085,651 127,750 618,312 - 4,383,589 4,383,589 2026 53,300 2,132,000 3,315,052 133,250 636,861 - 4,676,840 4,676,940 2027 = 5,500 2,220,000 3,555,440 138,750 655,967 - 4,980,722 4,980,722 2028 57,700 2,308,000 3,807,267 144,250 2,994,269 : 2,976,748 2,976,748 L aunsojsug Footnotes: (1) Net kWh energy which is available from Tyee after Wrangell & Petersburg loads. (2) Based on 6.8 cents/kWh In 1998, escalated at 3.0% annually starting in 2000. (3) $20,000,000 repaid over 15 years at an interest rate of 3%. (4) Estimated at 10% of PMC power rale. (5) State loan borrowing to maintain cost of power at Four Dam Pool Rate. Cumulative balance shown Is end of year and assumes a borrowing rale of 5%, an Operating Revenues Existing Revenues Electric Telephone Water Other Subtotai existing revenues Additional Operating Revenues Electric Water Subtotal additional revenues Total Operating Revenues Operating Expenses Electric O&M. Telephone O&M Water O&M Customer service Insurance Allocated City expense Total Operating Expenses Operating Income (Loss) Non-Operating Revenues Interest earnings Revenues available for debt service Debt Service Outstanding Bonds The Bonds Additionai Bonds State Debt Total Debt Service Available for other purposes Payments in lieu of taxes Net Cash Flow Debt Service Coverage on All Bonds Ketchikan Public Utilities Projected Operating Resuits @ As Forecast 2002 $14,430,230 10,030,660 1,567,539 $26,238,631 S$ 2597,441 282.157 $ 2379,598 $29,118,229 $11,183,049 3,549,000 1,226,160 T25,719 608,619 678,328 1,181,786 $19,153,161 $ 9,965,068 $ 472,704 $10,437,772 $ 3,322,375 730,315 2,528,000 Ss 3,580,390 $ 3,856,382 $ 710,635 $ 3,146,247 1.59 @®) With Portion of New State Loan 2002 $14,430,230 10,030,660 1,567,539 210.202 $26,238,631 S$ 2,597,441 282.157 $ 2,879,598 $29,118,229 $11,288,609 3,349,000 1,226,160 725,719 608,619 678,828 1.181.786 $19,258,721 $ 9,859,508 S 472,704 $10,332,212 SS 522-51. 730,515 2,528,000 603,043 5 7,183,933 $ 3,148,279 $ 710,635 S 2,437,644 L+4 (c) With All of New State Loan 2002 314,430,230 10,030,660 1,567,539 210,202 $26,238,631 $ 2,597,441 282,157 $ 2,379,598 $29,118,229 $11,288,609 3,549,000 1,226,160 725,719 608,619 678,828 $19,258,721 $ 9,859,508 $ 472,704 $10,332,212 $ 3,322;375 730,515 2,528,000 1.675.532 $ 8,256,222 $ 2,075,990 $ 710,635 S$ 1,365,355 1.25 Ketchikan Public Utilities Electric Load Growth Study KETCHIKAN PUBLIC UTILITIES ELECTRIC LOAD GROWTH STUDY 1. SUMMARY Ketchikan Public Utility (KPU) asked the Institute of Social and Economic Research to project electricity sales and generation requirements in Ketchikan in the coming years. Rather than one set of projections we have estimated a range of likely future growth, given different assumptions about important factors influencing the economy and electricity use. Throughout that range of likely growth--the LOW, BASE, and HIGH CASES— we project that electricity generation by KPU will temporarily drop but subsequently begin growing again, although at a slower rate than in the past. KPU asked for these projections because it is facing decisions about whether to increase its generating capacity, either through an intertie that would increase available hydropower, or through construction of more diesel-powered facilities. Estimating how electricity use in Ketchikan might grow in the future is complicated by the present uncertain status of the Ketchikan economy which will take several years to resolve through restructuring. During the transition it is natural to focus attention on immediate and often negative events. In this study we attempt not only to consider these near term events, but also what factors will be important in determining electricity use in the longer term. We believe that our projections are realistic since they are based on a conservative interpretation of historical patterns and trends in the Ketchikan economy and in electricity use patterns in Ketchikan. A number of factors will influence electricity generation requirements in the future, including: ° the health of the timber industry in the region : development of new large scale processing facilities for timber and seafood . extent to which new industry self generates electricity for their own needs : growth of other sectors of the economy including tourism, seafood, federal government, state government, regional center activities, and non-wage private income : relative attractiveness of electric space heating, and . potential expansion of the service territory We anticipate only a small reduction in electricity sales in response to the economic recession in all CASES. First, we anticipate that the support sector employment decline will be small as support businesses attempt to “tough it out” during this period of uncertainty. Second, (KETCHFIN.wpd) June 5, 1998 Page 1 Ketchikan Public Utilities Electric Load Growth Study we expect the percent decline in population to be less than that of employment as some people move out of the work force but remain in the community. Third, since residential sales are primarily a function of the housing stock which we do not expect to decline, we anticipate that residential sales will not fall significantly. Fourth, Commercial and Industrial electricity sales directly to the timber industry forms a very small share of the total, so the direct effect of a recession in the timber sector on electricity sales will be small. (Sales to Ketchikan Pulp Company (KPC) is a separate category and not included in Commercial or Industrial Sales.) Fifth, in a recession we expect commercial sales to be related to the number of businesses rather than jobs. . In the BASE CASE projection we adopt a set of conservative assumptions regarding the future direction of the factors influencing growth. We assume that after several years of uncertainty employment levels the timber industry stabilizes at 45 percent of the 1996 level and that non-timber employment grows at a 1 percent annual rate. The large scale processing facilities associated with the new uses of the pulp mill neither purchase nor sell electricity to KPU. Furthermore we assume no increase in the share of the housing stock heating with electricity and no extensions of the utility service territory. In the BASE CASE annual generation (combined generation of KPU diesel and hydroelectric capacity) falls from a peak in 1995 of 159 thousand MWH to 145 thousand MWH in 1997. This is the result of reductions in residential and non-residential sales as well as the termination of the sale of electricity to the KPC. Growth resumes in 1998 and averages about 1.2 percent annually after that. This rate of growth is below the historical growth rate in generation due to the drag on the economy imposed by the reduction in the timber industry. The 1995 level of generation is reached in 2006. (Table A.) In the HIGH CASE we assume that the timber industry stabilizes at an employment level 60 percent of the 1996 level, and that non-timber employment grows at an annual rate of 2 percent. As in the BASE CASE we assume that the large scale processing facilities associated with the new uses of the pulp mill neither purchase nor sell electricity to KPU. Consistent with the historical trend we assume in this case a modest increase in the share of the housing stock heating with electricity, but as with the BASE CASE that there are no extensions of the utility service territory. Generation in this CASE recovers to the 1995 level by 2002 as a result of more rapid economic growth and more intensive use of electricity. In the LOW CASE we assume that the timber industry stabilizes at an employment level only 15 percent of the 1996 level, and that non-timber employment grows at an annual rate of .5 percent. At this level of activity in the timber industry there are no large scale processing facilities associated with the pulp mill that could either purchase or sell electricity to KPU. We assume no increase in the share of the housing stock heating with electricity and no extensions of the utility service territory. In this CASE generation growth is very slow and only returns to the 1995 level in 2019. (KETCHFIN.wpd) June 5, 1998 Page 2 i a a 0 ee Ol ee Oh Ketchikan Public Utilities Electric Load Growth Study Projected peak demand is presented in Part 3. of Figure A. In the BASE CASE it falls from 31.4 MW in 1995 to 27 MW in 1998 and subsequently grows at a rate slightly below that of total generation. The same pattern occurs in both the HIGH and the LOW CASES. The projections of generation and peak load in Figure A. do not include new large-scale commercial or industrial load. In early 1998 Ketchikan Public Utility began supplying the Ketchikan Pulp Mill with all the electricity requirements for their sawmill and other facilities. The most current estimate of this load is 1.9 MW continuous (16,644 MWH per year) with a peak demand of 3.5 MW. Since the long-term health of the timber industry remains uncertain at this time we do not include this new industrial load is the CASES presented in Figure A. (KETCHFIN.wpd) June 5, 1998 Page 3 Ketchikan Public Utilities Electric Load Growth Study FIGURE A. (part 1.) KETCHIKAN PUBLIC UTILITIES PROJECTIONS OF ELECTRICITY GENERATION (MWh) KPU GENERATION RESIDENTIAL SALES NON-RESIDENTIAL SALES & UNACCOUNTED HIST BASE HIGH LOW HIST BASE HIGH Low HIST BASE HIGH Low 1970 0 27,128 1971 ° 29.246 1972 ° 30,797 1973 ° 30,958 1974 ° NA 1975 ° 32,838 1976 ° 35,059 1977 ° 35,082 1978 ° 36,754 1979 ° 37,462 1980 85,966 39,135 42.423 1981 87,512 42,834 44,771 1982 98,107 43,164 50,505 1983 99,228 44,961 49,040 1984 110,991 $1,292 48,867 1985 115,908 49,236 53,434 1986 109,120 46,795 $4,475 1987 114,297 46,904 $5,325 1988 © 137.879 49,269 63,872 1989 131,907 52,812 65,691 1990 140,311 54,115 70,304 1991 145,686 56,031 74,080 1992 152,980 54,277 73.371 1993 146,251 53,188 78,262 1994 158,347 58,594 84,005 1995 159,079 55,472 839,380 1996 158,383 59,360 89,170 1997 145,528 445.528 145.528__145.528 58.826 $8826 58.826 58.826 85.197 85,197 85.197 85,197 1998 > 146,17 747,607 145,794 = 55,440 56,000 56,000 85,057 85.930 62,186 1999 146,287 149,101 143,980 56,000 $6,640 $5,440 64,661 86.527 83,003 2000 447.466 153.182 143.236 56560 S8.8K 55.440 85,23: 88.457 82.287 2007 149,354 157,893 143,274 57.120 60,310 55,440 86,490 91.508 82,324 2002 151,883 162.687 143,645 58.257 81,824 $5,440 87,791 94,606 82,680 2003 153,743 187.222, 144,079 56.639 = 63.376 «= 55.440 88,990 97,415 83,097 2004 155,526 171,555 145,219 59,428 64,967 56,000 90,117 99,990 83,633 2005 457.332___175.873_ 146,362 60,022 66.597 56,560 91,258 102.511 84.173 2006 459,159 160,305 147,510 60,622 68,269 57,120 92.415 105,101 S716 2007 161,009 164,851 148,961 61.228 = 69,982 57,968 93,588 107.759 85,264 2008 162,682 189,518 149,835 61,841 71,739 58,258 94,777 110.490 85,814 2008 364,778 485,307 150,715 62459 73,540 58,550 95,981 113,294 86,369 2010 166,697 195.222 151.600 63,064 75,385 58.842 97,202 116.174 86,927 2017 168,640 205.265 152,491 63.715 77,278 59,136 96435 119.137 87,489 2012 470,607 153,387 64,352 79,217 $9,432 99,693 122.169 88,055 2013 172,598 154,288 64,995 81,206 59,729 100,96: 125.288 68,625 2014 174,613 155,195 65.645 83,244 60,028 102,252 128.491 89,198 2015 176,654 ; 156.108 66.302 85,333 60,328 403,558 131,781 89,776 2016 178,719 231,541 157,026 66.965 67,475 60.630 704,881 135.160 90.357 2017 180,810 237.433 157,950 67,634 89,671 60,933 106.222 138.630 90,933 2018 182,927 243.480 158,880 68,311 91,922 61.238 107,581 142,194 91,532 2019 185,070 249,686 159,816 68,994 94,229 61,544 108,958 145,854 92,125 2020 187.239 256,055 160,757 69.664 96,594 61.851 110,35: 149,613 92,722, 2027 189.435 252,592 161,704 70,381 99,018 62,167 711,765 153,474 93.324 2022 191,658 269,300 162,657 71,084 101,504 62,472 113,202 157.439 93,929 2023 193.909 276,185 163,615 71.795 104,052 62,764 114,656 © 161,511 94,539 2024 196,187 283.251 164,580 72.513 106,663 63,098 116.128 165,693 95,152 2025 198,494 290,502 165,551 73.238 © 109,341 63.413 117,621 169,988 95.770 ANNUAL GROWTH RATES 1970-1980 ERR 3.7% : 1980-1990 5.0% 3.3% 5.2% 1990-1995 2.5% 0.5% 4.9% 1995-2000 “1.5% 0.8% “2.1% 04% 1.2% 0.0% 0.9% 0.2% “1.6% 2000-2005 1.3% 2.8% 04% 1.2% 25% 04% 14% 3.0% 0.5% 2005-2010 1.2% 25% 07% 1.0% 2.5% 0.8% 1.3% 2.5% 0.6% 2010-2025 1.2% 2.5% 06% 1.0% 2.5% 0.5% 1.3% 2.6% 0.6% KPU GENERATION EQUALS THE SUM OF DIESEL AND HYDRO CONSISTENT WITH KPU GENERATION AND DISTRIBUTION REPORT HISTUS.WK4 (KETCHFIN.wpd) June 5, 1998 Page 4 Ketchikan Public Utilities Electric Load Growth Study FIGURE A. (part 2.) KETCHIKAN PUBLIC UTILITIES ~ PROJECTIONS OF ECONOMIC VARIABLES EMPLOYMENT (INC MILITARY & SELF EMP) POPULATION HIST BASE HIGH Low HIST BASE HIGH Low 1970 ° 10,200 1971 ° 10,200 1972 0 10,300 1973 0 10,500 1974 0 10,700 1975 ° 10,900 1976 0 11,200 1977 ° 11,400 1978 . 0 11,600 1979 ° 11,800 1980 7,048 14,316 1981 6,824 12,042 1982 7,103 12,268 1983 7,322 12.459 1984 7,214 12.438 1965 7.663 12,623 1966 8.128 12,729 1987 8.880 12,793 1968 9,372 12,594 1969 9,680 43.259 1990 10,397 13,828 1991 9,892 14,261 1992 9.874 14,536 1993 10.258 14,535 1994 10,419 14,638 1995 10,733 10,733 10.733 40,733 14,771 1996 10,600 10,600 10,600 14,701 1997 30.109 10.109 10,109 14,599 14.599 14,599 14,599 1996 9.894 9,919 9.719 14,210 14,228 14,089 1999 9,885 10.020 9.666 14,204 14,512 14,053 2000 40,009 10.335, 9.504 14.346 14,803 13,941 2001 10,1147 10.693 9.506 14,490 15,099 14,010 2002 10.228 10.953 9.538 14.635 15,401 14,080 2003 10.330 11,187 9.575 14,781 15.709 14,151 2004 10,425 11,399 9.621 14,929 16,023 14,221 2005 10,522 11,606 9.668 15,076 316,43 14,293 ‘2006 10,619 11,817 9.714 15,229 16.670 14,364 2007 10.718 12,032 9.761 15,381 17,004 14436 2008 10,817 42.252 ‘9,809 . 158.535 17.34 14,508 2009 10,918 12.475 9.856 15.690 17.690 14,581 2010 11,019 32,704 9.904 15.647 18,044 14.653 2017 44,721 12,937 9.952 16.006 18,405 14,727 2012 11,225 13,174 10,000 16,166 18.773 14,800 2013 11,329 13,416 10,048 16,327 19,149 14,874 2014 11,435 13,663 10.098 16,491 19,532 14,949 2015 11,542 13,915 10,147 16.655 19.922 15.023 2016 11,649 14,173 10,196 16.822 20,321 15,099 2017 11,758 14435 10,245 16,990 20,727 15.174 2018 . 11,666 14,702 10.295, 17,160 21,142 15.250 2019 11.979 14,975 10.345 17,332 21.565 15,326 2020 12,091 15,253 10.395 17.505 21,996 315.403 2021 42.206 15.537 10.446 17,680 22,436 15.480 2022 12.318 15,827 10,496 17.857 22.864 15,557 2023 124% 16.122 10,587 18,035 23.342 15.635 2024 12,550 16,423 10,599 18,216 23.809 15,713 2025 12,668 16,730 10,650 18,398 24,285 15,792 ANNUAL GROWTH RATES 1970-1980 ERR 1.0% 1980-1990 4.0% 2.0% 1990-1995 06% 1.3% 1995-2000 “14% 0.8% “24% 06% 0.0% “1.2% 2000-2005 1.0% 2.3% 0.3% 1.0% 2.0% 0.5% 2005-2010 0.9% 1.8% 0.5% 1.0% 2.0% o.s% 2010-2025 0.9% 1.9% OS% 1.0% 2.0% O.s% HISTUS.WK4 (KETCHFIN.wpd) June 5, 1998 Page 5 Ketchikan Public Utilities Electric Load Growth Study FIGURE A. (part 3.) KETCHIKAN PUBLIC UTILITIES PROJECTIONS OF PEAK DEMAND (MW) KPU PEAK DEMAND HIST BASE HIGH Low 1970 10.0 1971 124 1972 125 1873 13.9 = 1974 13.4 1975 137 1976 14.0 1977 16.3 1978 15.1 1979 16.1 1980 177 1981 16.9 1982 19.4 1983 20.8 1984 21.6 1985 25.1 1986 20.4 1987 22.0 1988 23.8 1989 26.7 1990 26.6 1991 25.3 1992 274 1993 26.9 1994 28.6 1995 31.4 314 314 31.4 1996 26.9 26.9 26.9 26.9 3997, 30.1 30.1 30.1 30.1 719968 a a 277 1999 27.2 27.6 26.9 2000 27.4 28.3 26.7 2007 ZT 29.0 26.7 2002 28.1 23.7 26.8 2003 28.3 30.4 26.9 2004 28.6 31.0 27.0 2005, 28.9 317 27.2 2006 25.2 32.3 274 2007 29.4 33.0 27.6 2008 29.7 33.7 27.8 2009 30.0 4 27.9 2010 30.3 35.1 28.0 2011 30.6 35.8 26.2 2012 30.9 38.6 28.3 2013 31.2 37.3 28.4 2014 315 38.1 28.6 2015 31.8 38.9 28.7 2076 32.1 38.7 28.8 2017 32.4 40.5 29.0 2018 32.7 414 23.4 2019 33.0 42.3 29.3 2020 33.3 43.1 29.4 2021 337 44.0 23.5 2022 34.0 45.0 29.7 2023 44.3 458 29.8 2024 6 469 30.0 2025 35.0 47.9 30.1 ANNUAL GROWTH RATES 1970-1980 5.9% 1980-1990 4.2% 1990-1995, 34% 1995-2000 27% “2.1% 2000-2005 1% 23% 2005-2010 1.0% 21% 0.6% 2010-2025 1.0% 21% 0.5% HISTUS.WK4 (KETCHFIN.wpd) June 5, 1998 Page 6 a