9. Comments on Proposed Decision

The proposed decision (PD) of the ALJ in this matter was mailed to the parties in accordance with Section 311 of the Public Utilities Code and comments were allowed under Rule 14.3 of the Commission's Rules of Practice and Procedure. Comments were filed on August 11, 2008 by PG&E, SCE/TURN, AReM, CCDC, California Large Energy Consumers Association (CLECA)/California Manufacturers and Technology Association (CMTA), CMUA, EPUC, Merced ID/Modest ID, and Northern California Power Agency (NCPA).⁸⁰ Reply comments were filed on August 18, 2008 by PG&E, SCE/TURN, SDG&E, AReM, CCDC, CMUA, CCSF, DRA, EPUC, Merced ID/Modest ID, and NCPA.

To the extent that the comments merely reargued the parties' positions taken in their briefs, those comments have not been given any weight. The comments which focused on factual, legal or technical errors have been considered, and, if appropriate, changes have been made. Our consideration of comments related to the more controversial issues is summarized below.

9.1. Applicability of the NBCs

PG&E states that there is no evidence that the adopted load forecasts in this proceeding reflect MDL and CGDL. The PD discussion related to the applicability of the NBCs, has been revised to reflect the fact that the load forecasts adopted in D.07-12-052 are based on the CEC's 2007 IEPR Demand Forecast and to explain the evidence that supports the finding that loads associated with MDL (with the exception of large municipalizations) and CGDL are forecasted to depart and therefore are not included in the CEC load forecasts that were adopted in D.07-12-052 as the forecasts on which new generation needs are to be based in the LTPPs.

SCE and TURN state that the PD never explains why MDL and CGDL that are forecasted years after new generation resources have been acquired should benefit from the stranded cost reduction that increased load or flexibility in procuring resources of various terms can bring about. The PD has been expanded to explain that even for these resources, at the time the resource commitments are made, (1) the LTPP load forecasts exclude forecasted amounts of MDL and CGDL; (2) these customers will eventually become the departing customers for which those amounts of MDL and CGDL are forecasted; and (3) therefore, in effect, these customers' loads are only reflected in the LTPP load forecast for the years in which they are bundled service customers. Therefore, (1) the IOUs' procurement needs related to these customers are only identified and planned for in the years in which they are bundled service customers; (2) the IOUs' procurement commitments are made on behalf of these customers only for the time that they are on bundled service; and (3) these customers' fair share of the costs related to these resources should be zero after they depart.

SCE and TURN express concern with the PD statement that the fair share of customers in a "large municipalization" may be zero because the large municipalization was foreseeable. We have reconsidered and removed this statement explaining that such customers have NBC cost responsibility for those resources procured on their behalf prior to the date of their departure or prior to an appropriate alternative date for ending cost responsibility for new generation resources such as that related to a BNI. Such customers' fair share can be zero only for those resources procured after such dates. We also agree with the assessment of SCE and TURN that a BNI process is a reasonable and preferable means for establishing when the IOU should have known about departures related to a large municipalization and should have excluded them from its load forecasts. However, we do provide an opportunity for the large municipalization entity to propose and justify an alternative date for determining the end of cost responsibility for new generation resources that is neither a BNI date nor the actual departure date. The burden would be on the municipal entity to justify why the alternative date is more appropriate than what would be established in a BNI process.

PG&E argues that large municipalizations should be treated no different than DA and CCA and that calculating the fair share owed by each large municipalization on a case-by-case basis (by application) is inappropriate. We disagree. It is necessary that the affected IOU demonstrate on a case-by-case basis that the related annexation cannot reasonably be assumed to have been reflected as part of the historical MDL trends used in developing the adopted LTPP forecasts. Also, there may be a reason why a large municipalization should have a date for determining the end of cost responsibility for new generation resources that is neither a BNI date nor the actual departure date. An application process is a fair way to resolve these potential issues and we will not change the PD in that regard.

PG&E states that it should be made clear that NBCs also apply to New WAPA Departing Load and Split Wheeling Departing Load, consistent with D.06-05-018 and D.03-09-052. There were no replies to this comment. In its testimony, PG&E included such loads as being subject to the D.04-12-048 NBC (Exhibit 7, p. II-5). No party proposed such loads should be excluded from that charge. Similarly, no party proposed such loads should be excluded from that subject to the D.06-07-029 NBC. Consistent with D.06-05-018 and D.03-09-052 which assigned generation related NBC cost responsibility for new WAPA departing load and split wheeling departing load, we agree with PG&E's claim that such departing load should be subject to the D.04-12-048 and D.06-07-029 NBCs. The PD has been modified accordingly.

9.2. The D.04-12-048 NBC

PG&E and SCE/TURN continue to object to the 10-year cost recovery limitation for non-RPS resources. In general they believe that bundled customer indifference is violated by this limitation, especially since the PD would leave lower cost pre-restructuring resources in the total portfolio for the entire life of such resources. SCE and TURN urge the Commission to remove the 10-year limitation. PG&E argues all resources should be allowed in the total portfolio over the entire term of the PPA or life of a utility owned generation asset, or the inclusion of the pre-restructuring resources should be limited, in a manner previously recommended by TURN.

We are not convinced that the PD should be modified in this regard. First, PG&E, SCE and TURN apparently assume the resources in question will be uneconomic not only over the initial 10-year period, but over a substantial amount or perhaps the entire amount of the remaining PPA term or utility asset life. That may or may not be the case, depending on the economics of the specific resource. Second, by D.04-12-048, the IOU has the opportunity to request extension of the cost recovery period on a case-by-case basis. While this does not provide the certainty that the SCE/TURN or PG&E proposals do, we are convinced that it is a fair way for the Commission to review what the IOUs have done over time to mitigate potential stranded costs, what effect unlimited cost recovery for RPS contracts and 10 year or less non-RPS contracts has on overall stranded costs, and what the long term economics of the resources in questions are over time compared to that of other resources in the total portfolio. With that review, the Commission can make a better determination of the need to extend cost recovery periods in order to maintain bundled customer indifference over time.⁸¹

⁸⁰ On August 18, 2008, NCPA filed a motion for party status. There were no responses, and the motion is granted.

⁸¹ We do not expect to see such requests for every resource with an expected term or life exceeding 10 years. While it is up to the IOU to decide whether and why an extension for a particular resource is necessary, it bears the burden to justify the request in terms of the factors discussed in this decision.