12. Avoided Cost
We need to adopt three factors in order to correctly value the avoided generation costs of the demand response: capacity cost, energy cost and the appropriate discount rate. PG&E and DRA agree on the first two but diverge sharply on discount rates. TURN disputes all three components with PG&E. As discussed below, we will adopt PG&E's calculations for all three factors. As noted above, our finding on avoided capacity cost applies in the limited application of valuing the AMI demand response: avoided capacity costs are to be considered for specific purposes when timely decisions are needed. We do not otherwise prejudge our pending rulemaking.
PG&E proposes a supply-side avoided capacity cost of $52 per kW year, based on the Commission's 2004 Market Price Referent.48 PG&E claims this is consistent with its other avoided generation costs testimony in recent Commission cases.49 PG&E also used an avoided capacity cost of $85 per kW year, as directed by the July 21, 2004 Assigned Commissioner's Ruling, and intended this to be consistent with avoided costs used for demand response in the past. PG&E used $52 per kW year and the $85 per kW year avoided capacity costs scenario 1(e) and the base case respectively.50 For the base case, the gross Total Resource Cost benefits are $510 million in Revised Table 1-1 (in 2005 Present Value). For Scenario 1(e) the benefits are $338 million. (Ex. 4-1S, Revised Table 1-1.) Either value more than offsets the operational benefit shortfall calculated after considering the stipulations between PG&E and DRA, whereby the forecast operational gap was reduced to $234 million. (Revised Tables 10-1 and 10-2, Ex. 32.)
DRA supports PG&E's use of $52 per kW year and believes any further litigation here would only duplicate the Rulemaking. (DRA Opening Brief, p. 24.)
PG&E and DRA had a methodological dispute over the recognition of the tax deductibility of interest when calculating the net present value of the AMI projects cost and benefits. PG&E was persuasive that the AMI project is cost effective whether the tax benefit of the deductibility of interest is reflected in the discount rate (7.60% the after-tax weighted cost of capital) or in the annual cash flows discounted by the pre-tax rate of return (8.79%).51 PG&E's method used an after-tax project cash flow and therefore used an after-tax discount rate. We find PG&E was internally consistent in its method and therefore will not adjust the discount rate.
There is a significant difference between PG&E's $52 per kW year and TURN's $23 per kW year which is caused by using different gross fixed costs for combustion turbines. As already noted, PG&E's cost assumptions come from the Commission's adopted Market Price Referent. TURN instead used JBS Energy, Inc.'s fixed charge model to compute the combustion turbine fixed costs. TURN also uses a constant hourly gas price. PG&E argues, and we agree, that TURN's calculations are not reasonable. TURN did not show its approach to be more consistent than PG&E's with existing Commission policy on avoided cost determination.
12.1. Conclusion
We will adopt the Scenario 1(e) forecast of $52 per kW and a benefit calculation of $338 million to evaluate the AMI deployment. This is more conservative than the Base Case analysis and still results in finding that the project is cost-effective. We adopt PG&E's after-tax calculation of cash flow and the use of an after-tax rate of return as the discount rate.
48 Energy Division Revised 2004 Market Price Referent, dated February 10, 2005, adopted in Resolution E-3942.
49 Ex. 12, Ch. 3 p. 3-2.
50 Ex. 4-1S, p. 1-2, Revised Table 1-1.
51 Ex. 11, Ch. 14, p. 14-6.
