8. Implementation Issues for Cost Allocation Under
D.06-07-029
PG&E, SCE, SDG&E and TURN refer to D.07-09-044 wherein the Commission adopted an uncontested settlement that specified the principles for the D.06-07-029 energy auction and the implementation details for the corresponding allocation of benefits and costs,76 and indicate nothing further needs to be done on this subject in this proceeding.
While most other parties are silent on this matter, AReM proposes certain modifications as discussed below. Also, EPUC raises a number of issues pertaining particularly to CGDL customers and states that they must be addressed, if the Commission does not exclude all CGDL from having to pay the D.06-07-029 charge. They include the following:
· Determination of a "capacity factor" exemption for qualifying CGDL;
· Determination of allocation method for RA credits to individual CGDL customers;
· Establishment of mechanisms to guard against "double-billing" CGDL customers that also take standby service by the IOUs;
· Establishment of mechanisms to guard against mistaken billing of load that is exempt from the definition of departing load (e.g., normal course of business load changes, back-up generation); and
· Regarding PG&E's proposal that CGDL customers "re-sell" the allocated but not needed RA credits, determination of identification methods for "purchasers" of RA credits.
Since we have essentially excluded all CGDL from having to pay both the D.04-12-048 and D.06-07-029 NBCs, as determined earlier in this decision, we need not address these issues at this time. However, we do note that consideration of the "capacity factor" exemption is beyond the scope of this track of the proceeding; there has been no demonstration that an allocation method for RA credits to individual CGDL customers does not already exist; the need to establish mechanisms to guard against "double-billing" CGDL customers that also take standby service by the IOUs and to guard against mistaken billing of load that is exempt from the definition of departing load has not been demonstrated; and the determination of identification methods for "purchasers" of RA credits is not necessary due to the manner in which this decision handles such credits.
8.1. Use of the DA CRS
In order to minimize the administrative burden associated with implementing the D.06-07-029 NBC, AReM recommends that, for DA customers, the charge be collected through the existing DA CRS. AReM does not provide any details on its proposal, and its intentions are not clear. If AReM is proposing that the D.06-07-029 costs be included with other utility procurement costs similar to the total portfolio approach adopted for the D.04-12-048 cost allocation, PG&E would oppose this proposal. PG&E argues that (1) the D.06-07-029 CAM is unique in that it allocates both benefits (i.e., RA credits) and costs and (2) any proposal to blend the D.06-07-029 costs with other stranded costs is contrary to the express terms of the settlement, which AREM signed on to as a settling party.77
The D.06-07-029 NBC is distinct from the elements of the DA CRS in that the charge itself is based on a cost that is net of the energy value, and there are associated RA credits. If and how those elements would be included in a charge that is based on a comparison of the costs of the energy and capacity of the IOUs resources to a market price benchmark is not explained by AReM.
Also, as explained in the principles for the energy auction process and products:
4. Net costs shall be calculated and determined separately for each Energy Auction PPA, and net costs shall not be netted against or in any way impacted by the costs of other resources in the utility's resource portfolio.78
The DA CRS and the D.06-07-029 NBC should therefore be calculated and billed as separate items.
8.2. Inclusion of the Charge under the DA CRS Cap
AReM recommends that, in order to prevent the NBCs from imposing an undue economic burden on DA customers and acting as a further drag on the DA market, the Commission should include the NBCs under the 2.7 cent per kilowatt hour (kWh) cap for the DA CRS established in D.02-11-022 and affirmed in D.03-07-030. SCE and PG&E oppose the recommendation.
SCE states that AReM's proposal is procedurally improper. According to SCE, presenting this proposal for the first time in Opening Brief deprives other parties of their due process rights. SCE further notes that, for PG&E and SDG&E, the 2.7 cent per kWh DA CRS cap is no longer in effect because they have already recovered their DA CRS undercollection, and for SCE the cap is expected to be eliminated by the end of 2008. Also, DA customers' LSEs will receive RA capacity credits in exchange for paying this NBC. This will allow them to reduce the cost of procuring capacity for DA customers and their corresponding charge to DA customer for such capacity.
PG&E states that there is nothing in the settlement that the Commission recently approved that would support capping the D.06-07-029 costs, and AReM should have proposed a cap in the settlement if it believed this was an important issue. PG&E also states that capping the net costs that could be allocated to DA customers would result in bundled customer bearing a greater share of the burden of the new generation costs, unfairly shifting costs to bundled customers. Also, since AReM suggests capping the costs, but not the allocation of the RA benefits, PG&E argues that DA customers should not be allowed to receive the full RA benefits of the D.06-07-029 cost allocation mechanism while only bearing a limited amount of the costs.
We agree with SCE's statement that AReM's proposal is procedurally improper. AReM could have, and should have, made this proposal in its prepared testimony, not in Opening Briefs. However, we will address it at this time. Having to consider other parties' due process rights is obviated by the fact that AReM's proposal is rejected.
First of all, the 2.7 cent/kWh DA CRS caps will have expired for all three IOUs by the end of 2008. Without a more definitive showing of need, we are reluctant to reinstate such caps, at any level, along with the necessary procedures for recovery of undercollections. Furthermore, the ESPs will be receiving RA credits. They should pay for such credits as they are received and used, not on some deferred basis. The need and equity of AReM's proposal has not been demonstrated, and it will not be adopted.
8.3. Five-Year Limitation
The adopted CAM in D.06-07-029 specified in part:79
2. New generation approved by this Commission and eligible for the cost allocation mechanism will receive cost recovery for a period of up to 10 years. We limit the maximum term of any cost paid by all customers to the term of the contract, or 10 years, which ever is less, from the time that the new unit comes online.
3. We intend this cost allocation mechanism to be in place for the term of the contract or up to 10 years, whichever is less, from the time the new unit comes on line. However, the mechanics of this cost allocation mechanism may change depending on the new market-based system which may evolve.
Rather than using the adopted cost recovery period of up to 10 years, AReM recommends that the Commission limit application of the CAM (or any similar ratemaking mechanism it may adopt for such purposes) to five years. AReM cites cross-examination testimony in a previous track of this proceeding, which indicates the utilities' long-term procurement plans are sufficiently flexible to allow them to adjust their portfolios to accommodate significant changes in load within a few years, and asserts the shorter five-year period would be adequate to avoid any cost shifting. PG&E, SCE and SDG&E oppose the five-year limitation.
PG&E states that the fact that the utility can adjust the amount it procures does not eliminate the above-market costs it must pay for contracts it has already entered into on behalf of the benefiting customers, and argues that AReM's proposal to limit the D.06-07-029 cost allocation mechanism to five years would result in remaining bundled customers bearing a disproportionate share of the costs for new generation associated with long-term contracts, which will typically be 10 years or longer.
SCE states that AReM offers no legitimate reason for disrupting the careful balance the Commission achieved in D.06-07-029 (and on which SCE relied in entering into power purchase agreements for new generation resources) and that AReM's attempt to reduce the cost recovery period should be rejected.
SDG&E state that AReM's proposal contradicts the Commission's ruling in D.06-07-029 that the recovery period be up to 10 years, and that, with respect to AReM's argument that the IOUs' procurement activities are flexible enough to allow for a five-year recovery period, the Commission considered that argument in D.04-12-048 and concluded that a 10-year period was justified.
AReM argues the IOUs' long-term procurement plans are sufficiently flexible to allow them to adjust their portfolios to accommodate significant changes in load within a few years. AReM bases its argument on cross examination of utility witnesses in another track of this proceeding, where such flexibility was acknowledged. However, that examination related to increased DA load only. In the context of the CAM, DA load planned for by the IOUs includes existing DA load as well as increased DA load. Also, the IOUs must continually take into account ongoing MDL and CGDL in their procurement activities and may have to make further adjustments for potential CCAs or large municipalizations. AReM does not address the manner in which the IOUs would adjust their procurement when faced with all of these possibilities or whether any of the adjustments might result in additional costs that would be borne by bundled customers only. Also, it is one thing for the IOU to be able to adjust it's portfolio to accommodate significant changes in a short period of time in terms of physical energy purchases, however, it is quite another to do so in a manner that would result in bundled customer indifference. There is insufficient justification for modifying the length of the CAM as adopted in D.06-07-029, and we will not adopt AReM's request to do so.
76 Unlike the D.04-12-048 NBCs, D.06-07-029 costs are not costs that are factored into and recovered through the total portfolio methodology.
77 PG&E Reply Brief, pp. 37-38.
78 D.07-09-044, Appendix A, p. 22.
79 D.06-07-029, p. 27.
