8. CTM Calculation
Under PG&E's proposal, the incentive must yield a positive CTM. PG&E uses a model to calculate the CTM for each year in a 30-year analysis period. The CTM is calculated as the revenue from the new customers less the incremental cost to serve them. The model then calculates the net present value (NPV) of the stream of annual CTM values. The NPV is the current value of a future revenue or expense. A positive NPV of the CTM stream means that the current value of the revenues exceeds the current value of the costs. Thus, there is a positive CTM.
The details of the CTM calculation (ex. a single family home subdivision) are as follows.
· Annual energy usage would be based on single-family homes constructed in the same local area within the last five years. PG&E assumes that usage would be constant once a home is built.
· Demand would be estimated by applying a class-specific load factor to the expected sales for each customer class. For residential sales, the demand would be calculated by dividing the annual usage by the number of hours in the year (8,760). This would then be divided by PG&E's most recent load factor for the residential class.17
· The average rate would be the average rate in effect at the time the incentive offer is made.
· PG&E assumes no escalation in rates or marginal costs over the 30-year analysis period.
· Incremental revenue is calculated as the annual energy usage times the average rate.
· Non-bypassable charges are removed from the revenue because they would be recovered from the customer even if the POU provides service.18
· Marginal costs would be the most recent Commission-adopted marginal costs escalated at the rate of inflation to the date the incentive offer is made. PG&E proposes to use the most geographically-specific marginal costs the Commission has approved. The marginal costs would include the one-time costs of connecting the customer, including the incentive, as well as ongoing costs.
· The incremental cost of serving the new development would be calculated by applying the unit marginal costs to the expected billing determinants (number of customers, annual energy usage, and demand).
· The CTM for each year is the incremental revenue less the incremental cost.
· The NPV is calculated using PG&E's after-tax weighted cost of capital as the discount rate.
· The compliance period would be up to five years.
The parties do not appear to disagree with PG&E's general calculation methodology. However, they do disagree on some of the inputs to the calculation. As stated previously, we do not address all of the issues raised by the parties because they are moot due to the fact that we are denying the application. The issues we discuss below contribute to our denial of the application. If we were to grant the application, additional issues regarding the incentive calculation would have to be addressed. The fact that we do not address them herein does not mean that we would make no changes to the incentive calculation or the inputs thereto or that further analysis would not reveal additional reasons to deny the application.
8.1. Positions of Parties
TURN states that PG&E's 2007 general rate case (GRC) settlement (settlement) was not intended to constitute a precedent regarding any principal or issue in any other proceeding. Thus the Commission is not required to use the marginal costs adopted in the settlement in this proceeding. Additionally, TURN states that it does not support the use of marginal costs resulting from a GRC settlement because the settlement process does not adopt a specific set of marginal costs that have been vetted by the Commission or other parties.
For public purpose program (PPP) revenues, TURN states that PG&E assumed that the new customers will provide PPP program revenue and that there will be no PPP costs associated with the new customers because such costs are fixed during each program cycle (the addition of new customers would not add new costs). TURN states that over the 30-year CTM evaluation period there will be many PPP funding cycles and the new customers will take advantage of them. Thus, there will be PPP costs.
TURN states that it does not dispute PG&E's contention that line extension facilities could last 30 years. However, it argues PG&E's assumption that costs and revenues will remain static over that period increases the risk that the incentive will produce a negative CTM.
TURN states that PG&E's assumption that none of the new customers will participate in the California Alternative Rates for Energy (CARE) program may be reasonable for the first few years. However, TURN argues that single-family homes and multi-family homes will likely be rented over the 30-year analysis period increasing the likelihood that they will be occupied by customers who qualify for the CARE program. CARE customers receive a 20% discount on their energy bills and are exempt from paying Department of Water Resources Bond Charges, the CARE surcharge, or any California Solar Initiative costs. Thus, TURN represents that inclusion of CARE customers in the analysis would result in a lower CTM.
8.2. Discussion
In D.07-09-004, in PG&E's 2007 GRC, the Commission adopted a settlement regarding marginal costs. Settlements are not generally intended to constitute a precedent regarding any principal or issue for use in any other proceeding. PG&E represents that the settlement specifies that one of the agreed-upon purposes of the marginal costs adopted in the settlement is for establishing "customer-specific contract rate floors for customer retention and attraction." In this proceeding we are not dealing with rates, much less rate floors, and the incentive would primarily be offered to developers who are not customers. Thus the record does not indicate that the marginal costs adopted in the settlement were intended by the parties to the settlement or the Commission for use in this proceeding or in calculating the incentives. Therefore, the reasonableness of their use in calculating CTM is not proven. Thus marginal costs would be a potential issue in the reasonableness review that could add significantly more controversy and complexity to the reasonableness review.
No party disputes that there will be PPP revenues. The PPP revenue requirement is determined in GRC's, and does not change until the next GRC. As a result, incremental PPP costs may not be reflected in rates until the first GRC after the incentive is awarded. In subsequent GRCs such costs would be included in the historical costs on which the GRC forecasts would be made. Thus, PPP costs would be recognized in the rates resulting from subsequent GRCs. Therefore, we agree with TURN that PPP costs should be included in the CTM calculation. However, the record does not indicate how to do so.
PG&E claims that its assumption that costs and revenues will remain static over the 30-year period tends to understate the CTM because if the revenues and marginal costs are escalated at the same rate, the difference between them would increase resulting in a greater CTM, all else being the same. This would be true under PG&E's assumption that both escalate at the same rate. However, the record contains no study that demonstrates how revenues and marginal costs have escalated historically or how they will do so in the future. Therefore, PG&E's assumption that costs and revenues will remain static over the 30-year period has not been shown to be reasonable or to understate the CTM.
We agree with TURN that PG&E's assumption that none of the customers will participate in the CARE program may be reasonable for the first few years. We also agree with TURN that at least some single-family homes and multi-family homes will likely be rented over the 30-year period to customers who qualify for the CARE program. PG&E states that, in the case of a CARE customer or a multi-family development, it would include the effect of the CARE program in its CTM calculation. PG&E's statement applies to initial residents of a residential development. However, TURN's argument applies to residents later in the analysis period as the development ages. PG&E did not address this possibility. Additionally, the record does not reflect how sizable this effect would be. Furthermore, since the incentive calculations would be specific to each development, this is a matter that would have to be addressed in the reasonableness review adding to the complexity of such proceedings.
PG&E's proposal will have to be administered, which means there will be administrative costs. PG&E's exhibits do not address administrative costs. In the hearings, a PG&E witness represented that costs related to determining whether the applicant qualifies for the incentive and whether PG&E will offer the incentive have been charged to Federal Energy Regulatory Commission Account 912 (Account 912), which has not been funded by the Commission in a number of GRCs, and are paid by shareholders. The record does not indicate whether the revenue requirement adopted in PG&E's 2007 GRC excluded Account 912 costs or whether all costs related to administration of the proposal would be charged to Account 912. In addition, PG&E has not proposed in this proceeding that administration costs related to this proposal, whether charged to Account 912 or not, be born exclusively by shareholders in the future. Thus, PG&E has not demonstrated that there would be no administrative costs that should be included in the CTM calculation or otherwise addressed in its proposal.
There will be costs associated with the reasonableness review. The Commission's costs, at least part of PG&E's costs, and costs incurred by intervenors eligible for intervenor compensation are recovered from ratepayers. Thus the reasonableness review costs would be paid, at least in part, by PG&E's ratepayers. These reasonableness review costs will reduce any CTM generated by the incentives. However, PG&E has provided no estimate of such costs and does not include them in its CTM calculation or otherwise address them in its proposal.
Given the above flaws in PG&E's CTM calculation, we find PG&E has not demonstrated that it is reasonable. Without a reasonable CTM calculation, the proposed incentive program can not be implemented.
17 The load factor is the customer's average demand divided by the customer's maximum demand.
18 Non-bypassable charges include the Department of Water Resources Bond Charge, Competition Transition Charge, Nuclear Decommissioning Charge, and Trust Transfer Amount (for residential and small commercial customers only).
