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<br />I I <br />I <br />J <br />I <br />I <br />I <br />I <br />I <br />I <br />I <br />I <br />I <br />I <br />I <br />I <br />I <br />I <br />I <br />I <br /> <br />3.0 BASE CASE RESULTS <br /> <br />3.1 Overview <br /> <br />The base case studies identified the lowest-cost plan in terms of total system costs, <br />without new pumped storage plants. The plans represented the lowest-cost mix of <br />new plants and economy interchanges for Colorado. Firm purchased power and sales <br />contracts between the utilities in the state were prespecified in the model runs. Firm <br />contractual arrangements were dispatched as specified in existing and proposed <br />contracts, while economy purchases or sales would transpire when one utility's <br />marginal energy cost is lower than another utility's marginal energy cost. A mid-range <br />set of baseline assumptions reflected significant parameters, except for the load <br />forecast where the sensitivities to medium, high, and low estimates were analyzed. <br /> <br />Each utility's system generation expansion plans were optimized by using EGEAS's <br />dynamic programming capabilities. The optimization process simulates all possible <br />combinations of generation alternatives to meet a certain reliability criteria in order to <br />minimize system costs. The EGEAS program determined whether or not the reserve <br />margin criterion could be met in each year of the study period. If the criterion could not <br />be met, new generation capacity was added to the existing generation resources. The <br />optimization routine continued in this manner until the end of the study period was <br />reached. The program then retraced the calculations to confirm that decisions made in <br />the early part of the study period were still the most economic choices over the long <br />run. <br /> <br />The annual costs for the optimized plan were then calculated in each case. These <br />costs included total fuel, variable operation and maintenance (O&M) costs, and fixed <br />costs (carrying charges and fixed O&M) for new capacity additions. <br /> <br />In a more rigorous planning study, these results would be further tested by applying <br />individual utility financial capabilities to determine whether the plan was financially <br />feasible. This step was not performed due to the limits of the study. This first phase <br />provides an assessment of whether pumped storage might economically replace other <br />types of power generation. It was conducted as a long-term joint planning effort and <br />statewide assessment, and thus did not address the individual financial capabilities of <br />the study participants. <br /> <br />3-1 <br />