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<br />II <br />I <br /> <br />I <br /> <br />I <br /> <br />I <br /> <br />I <br />I <br /> <br />I <br /> <br />I <br /> <br />I <br /> <br />I <br />I <br />I <br /> <br />I <br />I <br /> <br />I <br /> <br />I <br /> <br />I <br /> <br />I <br /> <br />- <br /> <br />represent multiple reservoir syst'9ms with an <br />peaking hydropower production and a lower, <br />reregulation and conservation storage. <br /> <br />upper reservoir pr imar ily for <br />or terminal reservoir, for <br /> <br />The cost €::;timates for Phase II were revised somewhat from Phase I to <br />reflect refinement of design layouts to a reconnaissance level of detail. The <br />total capital cost estimates (in 1982 dollars) for the single reservoir <br />systems ranged from $110 million to $131 million while the multiple reservoir <br />systems ranged from $354 million to $401 million. <br /> <br />The evaluation of the Phase II alternatives utilized both monetary and <br />non-monetary evaluation factors as in Phase 1. For the Phase II analyses, <br />however, the evaluation factors were revised and expanded to include pre- <br />liminary financial projections and additional physical impacts. <br /> <br />The Phase II economic evaluations included benefit-cost ratios and net <br />annual benefits for the single reservoir systems (Alternatives 1 and 8) and <br />the economic value of peaking power production for the multiple reservoir <br />systems (Alternatives 2 and 7). The economic analyses indicated that none of <br />the alternatives would be feasible at the present time using a 7 1/2 percent <br />discount rate. <br /> <br />Sensitivity analyses were also performed using discount rates of five <br />percent and ten percent for the economic evaluations. The five percent <br />analysis provided a preliminary indication of economic feasibility while the <br />ten percent analysis indicated very unfavorable conditions of economic <br />feasibility. <br /> <br />It should also be noted that, due to <br />systems formulated for these alternatives <br />ceivable that optimization would result <br />favorable benefit-cost relationships. <br /> <br />time and budget constr aints, the <br />were not optimized. It is con- <br />in smaller reservoirs with more <br /> <br />The preliminary financial evaluations projected total investment <br />requirements and annual costs under two different financing approaches: (1) <br />the state funding approach and (2) the revenue bonding approach. The state <br />funding approach assumes a project would be funded from the CWCB construction <br />fund and that capital costs would be amortized at five percent for forty <br />years. The revenue bonding approach assumes the issuance of tax-exempt <br />revenue bonds by a political subdivision of the state with capital costs <br />amortized at twelve percent for thirty years. Interest during construction <br />(i.e., the cost of short-term construction financing) and cost of issuing <br />bonds were added to capital costs under the revenue bonding approach. <br /> <br />An additional element of the financial evaluations was the calculation of <br />the cost burden on peaking power for the two multiple reservoir systems <br />(Alternatives 2 and 7). The cost burden is defined here as the value that <br />peaking power would have to attain, along with the estimated revenues from all <br />other project purposes, to retire the total project costs for the multiple <br />reservoir systems. <br /> <br />S-5 <br />