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in order to pay future operating expenses and to repay all costs assigned to be repaid by power revenues. Common to all options is the assumption that, after fiscal year 1989, all RGP generated energy will be sold as firm energy and there will be no firming energy purchases or surplus energy sales. Option A is based on the continuation of existing operating proce- dures and market ing po 1 icy, i. e., the sale of ~4 MW summer season firm capac ity and accompanyi ng energy, the purch ase of summer season firm i ng capacity and energy from the Colorado River Storage Project (CRSP), no sale of winter season capacity, and the sale of RGP winter season energy generation as surplus energy. A repayment study of Option A indicates the need for a new composite rate of 26.28 mills per kWh at 58.2 percent load factor. For the purpose of minimizing discrimination among power users, equal costs at 58.2 percent load factor have been assigned to the capacity and energy components, resulting in a rate of $5.585 per kW- month and 13.14 mills per kWh. Option B is based on the sale of 24 MW summer season firm capacity and accompanying energy, the purchase of summer season firming capacity from the CRSP, and system operat ions whereby RGP energy generat i on is integrated with the CRSP on an annual basis through an energy interchange or "banking" arrangement. Any annual RGP energy generation in excess of RGP summer season obl igations would oe sold as surplus, and any annual deficiency in RGP energy generation would be made up by purchases from the CRSP at the average annual price paid byCRSP for such energy. The est imated future annua 1 RGP energy generat i on used in the repayment studies is greater than the RGP summer ob1 igtions, so the studies indi- cate a net RGP surplus energy sale for future years in the winter season. Option C is the same as Option B except that it includes in addi- tion the sale of 24 MW winter season firm capacity with return of energy and the purchase of winter season firming capacity from CRSP. A repay- ment study of Option C shows the need for a composite rate of 21.08 mills per kWh at 58.2 percent load factor, with components of $4.48 per kW- month and 10.54 mills per kWh. In each of the three .options the RGP relies on considerable assist- ance from the CRSP. I n Opt ion A, there wou 1 d be a cost s av i ngs of about $200,000 annually to RGP due to purchases of firming energy from the CRSP at the CRSP firm power rate. In options Band C, the CRSP would be pro- viding energy banking to the RGP so that RGP winter season energy genera- tion cotIld be used to help meet summer season contractual obligations. In all three options, the CRSP would be providing firming capacity to the RGP. The firming energy provided by the CRSP to the RGP in Option A would represent an "out-of-pocket" expense of about $200,000 annually to the CRSP. Western Area Power Administration (Western) will hold a publ ic information forum to discuss the three options and other possible options for rate adjustments and to answer questions. A public comment forum will be held thereafter, at which interested persons may submit written or oral comments. 2 ,Y.J!4 . ,)