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<br />. <br /> <br />. <br /> <br />This uncertainty stems fr~m many possibilities, among them <br /> <br />that (a) by 1969 WAPA may have contracted to market hydropower <br />from Reclamation projects as p(!ak power, thereby adding greatly' <br />to available regional peaking capacity, (b) the potential effects <br />of load management and diversity exchange policies upon future <br />demand for peaking power may have been underestimated in area <br /> <br />utility forecasts, and (c) the seasonal peak demand for <br /> <br /> <br />electricity in the Tri-State a~ea may decline as groundwater <br /> <br /> <br />pumping for irrigation purposes is reduced due to energy costs <br /> <br />and declining water levels, <br /> <br />The price for peaking power is an obvious element <br /> <br />in determining how much of such power will be consumed, The <br />utility load projections used in phase I to confirm the existence <br />of effective demand do not include explicit consideration of this <br />price. However, the long-run marginal cost of peaking power <br /> <br />implicit in the Tudor calculations is 203 mills/kwh (composite ~ <br />~ <br /> <br />rate with fuel price escalatioh, or 190 mills without fuel price <br /> <br />escalation), There is reasonable doubt that peaking power demand <br />would grow at the 5 percent rate projected by the utilities and <br />Tudor if peaking power were to be priced at Tudor's estimated <br /> <br />long-run marginal cost. In fact, it is not unreasonalbe to <br /> <br />suppose that peaking power demand might not grow at all if such <br /> <br />very large rate increases were to occur. <br /> <br />It is true that utilities in this area do not now price <br /> <br />power, and particularly peaking power, at this long-run marginal <br /> <br />cost, There are, however, indications that future power pricing <br /> <br />-5- <br />