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.' . . Tudor Engineering Page 2 the potential effects of load management and diversity exchange policies upon future demand for peaking power may have been underestimated in area utility forecasts, and (c) the seasonal peak demand for electricity in the Tri-State area may decline as groundwater pumping for irrigation purposes is reduced due to energy costs and declining water levels. The price for peaking power is an obvious element in determining how much of such power will be consumed. The utility load projections used by Tudor to confirm the existence of effective demand do not include explicit consideration of this price. However, the long-run marginal cost of peaking power implicit in the Tudor calculations is 203 mills/kwh (composite rate with fuel price escalation, or 190 mills without fuel price escalation). There is reasonable doubt that peaking power demand would grow at the 5 percent rate projected by the utilities and Tudor if peaking power were to be priced at Tudor's estimated long-run marginal cost. In fact, it is not unreasonable to suppose that peaking power demand might not grow at all if such very large rate increases were to occur. It is true that utilities in this area do not now price power, and particularly peaking power, at its long-run marginal cost. There are, however, indications that future power pricing will move in this direction, due to the influence of the buy-back provisions of PURPA and the general trend of regulatory authorities to strive for economically rational energy production and consumption. But even if this change does not occur, and the peaking power load growth necessary to justify a Cache La Poudre peaking plant is realized, it would then be improper to calculate benefits at the 203 mill rate used by Tudor when the power produced is, in fact, marketed at a lower rate. This would constitute a violation of the willingness to pay principle of benefit estimation which is incorporated in my guidelines.