6. Implementation Issues for Cost Allocation Under
D.04-12-048
Two principal implementation issues that have been identified in this proceeding relate to (1) whether the D.04-12-048 NBC should be determined in isolation (separate charge approach) or in conjunction with other resources and other related CRS obligations (total portfolio approach); and (2) the method by which new resource obligations are determined for specific customers considering when those customers depart or choose alternative energy providers (vintaging). We also address issues related to the cost-effectiveness and the actual calculation of the NBC in this portion of the decision.
6.1. Total Portfolio and Separate Charge Approaches
Under the total portfolio approach, the uneconomic costs associated with new generation resources46 are determined in conjunction with the economic and uneconomic costs associated with older generation resources. Under the separate charge approach, the uneconomic costs associated with new generation resources are determined separate from that for older generation resources. In either case, new generation NBCs (based on either the total portfolio or separate charge approach) would be imposed in those years in which generation costs are shown to be uneconomic, that is higher than the market benchmark costs, and the NBCs would recover no more than those uneconomic costs for those years. New generation NBCs would not be imposed in those years where the generation costs are lower than the market benchmark costs.
In a series of decisions in R.02-01-011 (the DA/DL CRS proceeding) and R.03-10-003 (the CCA proceeding), the Commission adopted CRSs applicable to DA, MDL, CGDL and CCA. As explained earlier, the components of the CRS include the ongoing CTC and the DWR power and bond charges. Also, for PG&E, DA and MDL are responsible for the ECRA, which recovers PG&E's bankruptcy-related costs.47
The total portfolio approach is used in determining the power charge indifference amount (PCIA), which is the DWR power charge element of the CRS. The revenue requirement of the total portfolio of resources, which includes the DWR contracts, resources subject to ongoing CTC and pre-restructuring resources not subject to ongoing CTC (primarily utility retained generation (URG)), are compared to market costs. If the total portfolio costs exceed the market costs, that difference represents the uneconomic or stranded costs. Dividing that difference by total bundled customer and departing customer usage results in an "indifference amount," which in this case is positive and represents what departing customers should pay in order that remaining bundled customers remain indifferent to their departure. The PCIA is then calculated by subtracting the ongoing CTC charge from the positive indifference amount. If the PCIA is positive, the amount collected through the PCIA is remitted to the DWR to reduce the bundled service customers' DWR power charge obligation, while the ongoing CTC amount would be credited to the Energy Resource Recovery Account (ERRA) balancing account. If the PCIA is negative, there would be no remittance to the DWR and the entire indifference amount would be credited to the ERRA.
If the total portfolio costs are lower than market costs resulting in a negative indifference amount, the customers' departure is economic. However, departing customers do not receive a credit on their bills for negative indifference amounts. Instead, negative indifference amounts can be carried over to offset future positive indifference amounts but are not eligible to be applied against any other components of the CRS.
To implement the D.04-12-048 NBC, SCE recommends using the existing CRS total portfolio approach for calculating an indifference amount except the total portfolio would now also include new generation resources subject to the D.04-12-048 NBC. Also, customers' cost responsibility for new generation resources would vary depending on when the customers depart and which new generation resources were committed to on their behalf prior to their departure. The revenue requirement would have to be calculated for each vintage of the utility's total portfolio of generation resources and contractual commitments. In its annual ERRA proceeding, SCE will set forth its total generation revenue requirement for each vintage of departing load and will also identify the portion of it that relates to costs covered by Public Utilities Code Section 367(a) to enable the calculation of the ongoing CTC. The total generation revenue requirement for each vintage will then be added to SCE's allocated DWR power charge revenue requirement to determine the revenue requirement on which an indifference amount will be calculated. Those revenue requirements would be compared to the market costs benchmarks and indifference amounts and PCIAs can be calculated and charged for each vintage of total portfolios, similar to the existing CRS calculations, as described above.
SCE supports the total portfolio approach because it is simple and provides departing customers with the benefit of any below-market assets they leave behind by netting them against any above-market costs in the total portfolio (including commitments made after D.04-12-048 was issued).
The total portfolio approach is preferred by SCE, SDG&E, AREM, Hercules, Merced ID, and Modesto ID. However, both SCE and SDG&E indicate D.04-12-048 is ambiguous as to whether a separate charge should be used and request the Commission clarify its intentions in this proceeding. If a separate charge is used, SCE indicates it does not oppose PG&E's proposal. Also, SCE and SDG&E note that in D.07-05-005, the Commission resolved the issue of whether negative non-bypassable charges reflecting below market costs of a utility's procurement portfolio should be carried over from one year to the next. However, while the Commission held that a negative indifference amount in a given year should be carried-forward to cancel out future positive indifference amounts,48 SCE and SDG&E state the decision is ambiguous as to whether that netting of negative versus positive indifference amounts applies only as long as the PCIA, or the DWR indifference concept, is in place. SCE and SDG&E therefore request that the Commission clarify how long it intends the carry-forward of negative indifference amounts to apply.
TURN is concerned with the 10-year limitation on cost recovery for non-renewable resources and recommends that, in order to maintain bundled customer indifference, the total portfolio should include the lower cost pre-restructuring resources that are not subject to ongoing CTC treatment for 10 years, ending in 2010, to offset the effect of the 10-year limitation on NBC cost recovery for non-RPS resources. If that adjustment were adopted, TURN would support carrying over negative indifference amounts to offset positive indifference amounts in future years. SDG&E supports TURN's proposal to limit the time that pre-restructuring resources are included in the total portfolio. PG&E indicated that if the Commission does not adopt PG&E's separate charge proposal, it should, at a minimum, adopt the limitation on pre-restructuring resources proposed by TURN. DRA indicated that, while it agrees with PG&E's approach, it could also support TURN's proposal.
Rather than employing the total portfolio approach, PG&E has proposed a separate charge approach, where the new generation resources subject to the D.04-12-048 NBC, and only those resources, are used when comparing resource revenue requirements to market costs. Any resultant positive indifference amounts would represent the uneconomic costs that departing customers should pay in order that remaining bundled customers remain indifferent to their departure. The resultant charges are separate from the ongoing CTC and DWR power charges which would continue to be calculated separately as part of the existing CRS.
If the separate charge results in below-market costs, i.e., a negative indifference amount, the departure of customers would be economic. Under PG&E's proposal, there would be no credit on the departing customers' bills to reflect the negative indifference amount. Also the negative indifference amount could not be carried over to offset future positive indifference amounts.
PG&E argues that the D.04-12-048 NBC is different than the ongoing CTC and DWR power charges in a number of important ways and there are a number of differences between the approaches which justifies its proposal. They are:
· First, the D.04-12-048 charges apply to prospective generation costs, unlike ongoing CTCs, which recover QF and utility-owned generation costs, and the DWR-related costs.
· Second, the D.04-12-048 NBCs have certain limitations that do not apply to ongoing CTCs and DWR power charges, such as the 10-year limit on recovery for nonrenewable resources, including both PPAs and utility-owned generation. The CTC and DWR-related charges are for the life of the contracts at issue.
· Third, the D.04-12-048 charges apply to "all customers," unlike ongoing CTCs and the DWR power charges for which the Commission has granted some limited exceptions. Because the D.04-12-048 non-bypassable charges differ from ongoing CTC and DWR power charges, the Commission determined that an "additional" non-bypassable charge was necessary.
DRA supports PG&E's proposed approach.
The principle of bundled customer indifference is paramount in considering the total portfolio/separate charge issue. Again, bundled customer indifference means that bundled customers should be no worse off nor should they be any better off due to departing loads. To start, we must determine what the real differences are between the separate charge approach and the total portfolio approach. Based on what those differences are and how they are viewed when considering bundled customer indifference, we can determine our preference. We can then consider whether the D.04-12-048 NBC 10-year limitation on cost recovery for nonrenewable resources necessitates some kind of adjustment to maintain bundled customer indifference; and if so, what that adjustment should be.
In total, the resources and costs for determining the charges for the remaining ongoing CTC costs, DWR related costs and the costs for new generation resources authorized by D.04-12-048 are the same under the total portfolio approach and the approach that calculates the D.04-12-048 charge separate from the ongoing CTC/DWR power charge. As clarified during evidentiary hearing by SCE witness Jazayeri, at this point, the only difference between the separate charge and the total portfolio approaches is how negative charges are handled in the calculations.49
If all the calculated charges were positive, the departing customer would pay the same amount under both approaches. The only difference would be that the total portfolio approach, which considers all of the resources and costs together, would result in one combined charge; while the separate charge approach would result in two charges - the combined ongoing CTC/DWR power charge and the separate D.04-12-048 charge, which when added together would equal the total portfolio charge.50
However, if one of the charges is negative, the separate charge and total portfolio approaches would result in different charges, at least initially. For example, if the combined ongoing CTC/DWR power charge for any particular year is negative and the D.04-12-048 charge is positive, the two approaches would yield different total charges for that particular year.
Under the total portfolio approach, the three charges are essentially netted against each other and the result may be positive or negative. If the combined amount is positive, the customer would pay the combined charge. If the combined charge is negative, the customer would not pay anything and the combined negative charge would be carried over for use in subsequent years.
Under the separate charge approach, the customer would not pay anything for the ongoing CTC/DWR power charge and the entire negative amount would carry over for use in subsequent years. The customer would also separately pay the full amount of the D.04-12-048 charge. Therefore, in that particular year, under these circumstances, the customer would pay a higher amount under the separate charge approach. However, when looked at over a number of years, in situations where the ongoing CTC/DWR power charge is negative, the customer may essentially pay the same amount under either approach, since even under the separate charge approach, the negative ongoing CTC/DWR power charge, while not offsetting the D.04-12-048 charge in that particular year, can be used to offset positive ongoing CTC/DWR power charges in subsequent years.
The principal difference between the separate charge approach and the total portfolio approach occurs when the D.04-12-048 NBC charge for any particular year is negative. Under the separate charge approach, the customer would not pay a D.04-12-048 charge, similar to what would happen if the combined ongoing CTC/DWR power charges were negative. However, in contrast to the negative ongoing CTC/DWR power charges being carried over for use in subsequent years, the separate negative D.04-12-048 charge would not be carried over for use in subsequent years. That negative amount then could never be reflected in calculating the customer's charge. Under these circumstances, over time, the total of the two separate annual charges would diverge from the total of the annual total portfolio charges, simply because the negative D.04-12-048 charge is never accounted for in calculating charges -- not in the particular year in which it occurs, nor in any subsequent year.
The handling of negative charges was previously addressed in D.07-05-005. In that decision, we stated:51
...By allowing for negative indifference amounts to be netted against future positive amounts, the goal of bundled customer indifference is preserved...
...By recognizing only positive indifference amounts, but not tracking offsetting effects attributable to negative indifference, PG&E's proposed method could result in a permanent net positive indifference amount charged to DA/DL customers. The indifference charge is intended to capture the applicable above-market procurement costs. Indifference is achieved when there is neither an under-or-over recovery of such indifference charges from DA/DL customers..."
...Therefore, in order to maintain indifference, both positive and negative indifference effects must still be tracked, with the negative amounts offsetting positive amounts...
While the Commission's reasoning in that decision applied to the existing DA/DL CRS calculations, the basic principles directly relate to handling of negative charges in this proceeding as described above. It is similarly necessary that negative indifference amounts be carried over for use in subsequent years to maintain bundled customer indifference. The total portfolio approach is consistent with this principle. PG&E's separate approach is not. While we could adopt PG&E's separate approach after first modifying it to conform to our previous determinations regarding the carryover of negative indifference amounts, we prefer instead to adopt the use of the total portfolio approach for use in implementing the D.04-12-048 NBC. This preference is primarily based on our understanding of the implications of each approach with regard to the handling of pre-restructuring resources not subject to ongoing CTC, as discussed below. The use of the total portfolio approach is necessary to implement provisions of this decision regarding the use of these pre-restructuring resources in determining cost responsibility once recovery of the DWR power charge ends.
One of PG&E's objections to the total portfolio approach is related to whether or how long the pre-restructuring resources52 should be included in the portfolios for calculating ongoing CTC, DWR power charges and D.04-12-048 charges. PG&E argues that requiring new generation costs to be offset by generation that is 25 to 30 years into its depreciation cycle does not truly capture the stranded costs associated with the new generation, and departing customers should not receive the benefits of existing generation after they leave bundled service. By PG&E's separate charge approach, the pre-restructuring resources are not included in the calculation of the separate D.04-12-048 charge. Also, while PG&E acknowledges that currently these resources are reflected in the calculation of the PCIA, PG&E also states that the indifference standard and current total portfolio approach expire once the DWR power charge ends. When that happens, as a consequence of PG&E's separate charge approach for the D.04-12-048 charge, only the ongoing CTC would remain in the existing CRS calculation, effectively eliminating the use of pre-restructuring resources.53
SCE, in recommending the total portfolio approach, does not indicate that pre-restructuring resources should ever be excluded from the portfolio. SCE's statement that its proposal "provides the departing customers with the benefit of any below-market assets they leave behind by netting them against any above-market cost in the total portfolio (including commitments made after D.04-12-048 was issued)," suggests, to the extent contracts have not expired or generation assets are not yet retired, the pre-restructuring resources would remain in the portfolio as long as D.04-12-048 charges were being calculated and assessed. Similar to the current DWR power/ongoing CTC methodology, the total indifference amount would be calculated, the ongoing CTC portion would be calculated pursuant to Pub. Util. Code § 367(a), and that amount would be subtracted out of the total resulting in the D.04-12-048 charge.
In D.02-11-022, the Commission determined that a total portfolio approach was appropriate for use in calculating the DA CRS, stating:
The intent underlying the indifference calculation, however, is to determine the cost shifting that resulted from the migration of certain bundled customers to DA. An accurate measure of cost shifting cannot be determined if we selectively focus only on certain components of cost shifting while ignoring others. The directive in D.02-03-055 was to consider all cost shifting, not just those effects attributed to the DWR portion of the total portfolio. The netting of [utility retained generation] URG savings does not imply that those URG resources are somehow dedicated to serving DA customers. The attribution of savings to DA customers merely reflect the change in costs experienced by bundled customers associated with their use of those dedicated resources. (D.02-11-022, p. 25.)
That reasoning is directly applicable to our consideration of the D.04-12-048 charge. By including only the D.04-12-048 resources in the portfolio, the separate charge approach only considers cost shifting associated with those resources. Bundled customer indifference will only be maintained if all resources are included in the portfolio used to calculate the related charges, whether it is the ongoing CTC, DWR power charges and D.04-12-048 charges or just the ongoing CTC and D.04-12-048 charges. Therefore, the use of the total portfolio and the inclusion of the pre-restructuring resources in that portfolio is the appropriate approach to use for the duration of the D.04-12-048 NBC cost recovery54 even after cost recovery of the DWR power charge ends.
Similarly, the current provisions related to negative indifference charge carryover for use in subsequent years should be continued once DWR power charge recovery ends. Again, this is necessary to maintain bundled customer indifference. D.07-05-005 did state that at the expiration of the DWR contract term, the applicability of the indifference requirement would also expire. That made sense in the context of that decision, since it was the recovery of the DWR contracts themselves that necessitated the total portfolio approach and bundled customer indifference as it relates to such recovery. With the expiration of the DWR contract term, none of this would have been necessary, and the applicability of the indifference requirement as it relates to DWR power charge cost recovery should also have ended. However, with the inclusion of D.04-12-048 cost recovery as part of the total portfolio, the reasons cited in D.07-05-005, as discussed above as to why negative indifference charge carryover is appropriate, apply even after expiration of the DWR contract term. That reasoning is as valid for cost recovery related to the ongoing CTC and D.04-12-048 charges as it was for cost recovery related to the ongoing CTC and DWR power charges.
As discussed below, we have considered the effects of the D.04-12-048 provision whereby cost recovery for non-renewable resources is limited to 10 years, and we do not feel it is necessary to make any related changes to the total portfolio approach at this time.
In D.04-12-048, the Commission concluded:
The utilities should be allowed to recover stranded costs for their non-RPS resource commitments from departing load over either the life of the contract or 10 years, whichever is less. The ten-year recovery period should also apply to any utility-owned generation acquired as a result of the procurement process, commencing once the resource begins commercial operation. Stranded costs arising from RPS procurement activities should be collected from all customers, including departing load, over the life of the contract. The utilities should be allowed the opportunity to justify in their applications, on a case-by-case basis, the desirability of adopting a cost recovery period of longer than ten years for their non-RPS resource commitments. Cost recovery for that portion of a resource acquired by the utilities to meet local reliability needs should be recovered from all customers. (Conclusion of Law 16.)
Two proposals have been made to address the perceived effects of this 10-year cost recovery limitation. There is PG&E's separate charge approach which effectively abandons use of the supposedly cheaper pre-restructuring resources as soon as DWR power charge cost recovery ends. There is also TURN's proposal for use of a total portfolio approach which would include the pre-restructuring resources in the total portfolio only through 2010. In both cases, the resultant D.04-12-048 charge would likely be higher than it would be if there were no limitations on including pre-restructuring resources in the total portfolios. Both PG&E and TURN argue that their proposals are necessary to maintain bundled customer indifference with respect to the D.04-12-048 10-year limitation for cost recovery of non-RPS resources.
As support for its position TURN argues, "As long as new non-RPS resources can only be included for 10 years, consistency would dictate that pre-restructuring non-QF resources should only be included in the total portfolio for ten years as well. Otherwise, there is a bias in the calculation that interferes with the achievement of bundled ratepayer indifference on a total portfolio basis."55
However, the D.04-12-048 10-year cost recovery limitation is for each specific non-RPS resource. TURN's pre-restructuring resource limitation is not specific for each resource but is instead applicable to the total portfolio with a set end date of 2010. Since the DWR power costs are continuing and will likely not end until after 2010, the pre-restructuring resources would have been included in the total portfolio anyway to maintain bundled customer indifference in the calculation of the fully recoverable DWR power charge for that entire 10-year period. If a non-RPS resource begins providing energy in 2011, cost recovery of the related D.04-12-048 charge would extend 10 years through 2020. Yet under TURN's proposal, in the calculation of the related D.04-12-048 charges, the pre-restructuring resources would not be included in the total portfolio for any of those years. TURN's argument that a limitation on the use of pre-restructuring resources fairly offsets its perceived effects of the D.04-12-048 10-year limitation on cost recovery for non-RPS resources is not persuasive.
Similarly, while PG&E's separate charge approach has not been adopted by this decision, when its separate charge approach and existing CRS are looked at in total, pre-restructuring resources would also cease to be considered in determining these charges at a specific point in time. That would be when the DWR power charge ends. We see the same problems with that as we do with TURN's proposal to end the use of pre-restructuring resources in the total portfolio in 2010.
As indicated, we do not see the logic or fairness in ending the use of pre-restructuring resources in the total portfolio as of 2010 or as of the date that cost recovery for the DWR power charge ends as a way to address the D.04-12-048 limitation on cost recovery for non-RPS resources and will not do so.
With respect to non-RPS resources that will be available for more than 10 years but which are limited to 10-year NBC recovery, the utilities can, over time, adjust their load forecasts and resource portfolios to mitigate the effects of DA, CCA, and any large municipalizations on bundled service customer indifference. By the end of a 10-year period, we assume the IOUs would be able to make substantial progress in eliminating such effects for customers who cease taking bundled service during that period. Furthermore, as provided by D.04-12-048, uneconomic costs associated with new non-RPS resource contracts of 10 years or less are fully recoverable, and the uneconomic costs of new RPS contracts are fully recoverable over the length of the contract with no limitation.
We must also consider the possibility that for non-RPS contracts or utility resource assets with lives significantly longer than 10 years, there may be a point in time when such resources may become more economic, when compared to the market benchmark, than many of the other newer resources existing during that time period, and thus may in effect lower future total portfolio costs similar to the manner in which the pre-restructuring resources currently have in lowering current total portfolio costs. The fact that such lower costs would also not be reflected in the total portfolio after the initial 10 year period may have an impact on the need to extend the length of time that certain resources should remain in the total portfolio.
However, if the IOUs believe a cost recovery period extension is appropriate and necessary for specific non-RPS resources, they can make such requests under the provisions of D.04-12-048. The Commission can then tailor its findings, conclusions and remedies to the specific facts of each case and can fully extend, partially extend or not extend the cost recovery period. We believe this process is fair and more reasonable than implementing some overall limitation on the resource portfolio mix.
In a number of advice letter filings requesting approval of RPS power purchase agreements, PG&E included a request to recover the above market costs of the contracts through a NBC, consistent with its interpretation of D.04-12-048. The Commission consistently declined to do so, indicating that it would not address such above market cost recovery in the resolutions and indicated that R.06-02-013 was the appropriate procedural forum for addressing those issues.56 In Resolution E-4138, dated December 20, 2007, the Commission clarified its intent as follows:
...by this resolution we make no determination of whether stranded costs will in fact be incurred during the life of this contract. However, to the extent that such costs should occur, such costs will be eligible for stranded cost recovery subject to any determination in R.06-02-013 or any other proceeding regarding the implementation of cost recovery provisions of D.04-12-048....
To further clarify, with respect to the implementation of the stranded cost provisions of D.04-12-048 that are addressed in today's decision, the NBCs, which include any above market costs related to RPS contracts, will not apply to departing load that is excluded from the load forecasts used to develop the IOUs' LTPPs. The excluded departing load includes MDL, with the exception of large municipalizations, and CGDL. DA and CCA load are fully subject to the D.04-12-048 NBC. Furthermore, RPS contracts are fully recoverable over the life of the contracts. When calculating the CRS, the RPS contracts will be blended in with other generation resources under the total portfolio analysis. The costs of all of the resources would be compared to the applicable benchmark price to determine whether there are any above market costs. The applicable benchmark price will be calculated as set forth in D.06-07-030 and modified by D.07-01-030. Also, since the D.04-12-048 NBC is based on a total portfolio analysis of an above-market price and is not intended to allocate specific resources to specific customers, none of the benefits or attributes of the RPS contracts will be transferred to those customers who pay the D.04-12-048 NBC at this time. We note, though, that future developments in the State's renewable and/or greenhouse gas policies may both necessitate and facilitate a review of the manner in which renewables attributes are treated with respect to departing load and the new generation NBC to best maintain ratepayer indifference and the State's various policy objectives.
The D.04-12-048 NBC was established for a number of reasons including the uncertainty caused by potential increases in DA,57 CCA and DL.58 The need for the NBC is likely to be long lasting. Given the potential long-term nature of the charge, we must allow for the possibility that certain future circumstances may result in a need to modify the NBC related processes adopted in this decision.
For instance, SCE believes that the current methodology for determination of a market price benchmark is reasonable as long as the load departure does not increase significantly above that seen in the post-2001 period. If it does increase significantly, SCE indicates it may ask the Commission to revisit the issue.59 SDG&E also states that it is not clear that the benchmark would be appropriate in the future should DA reopen or significant load migrates via CCA.60 Significant shifts in load may affect other things such as the need for renewable contracts and how such contracts should be handled in the recovery of stranded costs.
If, due to future changing circumstances, the processes adopted by this decision for determining the NBC become unworkable, unbalanced, or unfair, parties may propose and request, for our consideration, modifications to the form of the NBC or the manner in which the NBC should be determined or calculated.
To summarize, we adopt the use of a CRS calculation using a total portfolio approach that accounts for the ongoing CTC, DWR and D.04-12-048 charges. This includes netting the individually calculated annual charges and carrying over any negative total charge to offset positive charges in subsequent years. Further, we determine that pre-restructuring resources should continue to be included in the portfolio of resources used in determining the D.04-12-048 charges, once recovery of DWR power costs ends. We will address the effects of the 10-year limitation on cost recovery of new non-RPS generation resources on bundled customer indifference, on a case-by-case basis, if and when the IOUs request cost recovery extensions, pursuant to the provisions of D.04-12-048. Finally, should the processes adopted by this decision become unworkable, unbalanced, or unfair, parties may request, for our consideration, modifications to the form of the D.04-12-048 NBC or the manner in which that NBC should be determined or calculated.
6.2. Vintaging
For this proceeding, we define vintaging as the process of assigning a departure date to departing customers in order to determine those customers' generation resource obligations.61 To implement the stranded cost recovery principles adopted in D.04-12-048, the IOUs must track the generation costs, including the costs of certain generation commitments, incurred to serve departing customers up to the point when a particular customer departs and the IOU no longer provides procurement services to serve its load. The law permits the recovery of stranded costs from those customers who are responsible for stranded costs related to resource and contractual commitments made by the IOU up until the time of the customer's departure and that departing customers should bear no cost responsibility for such commitments the IOU makes after their departure. The determination of a departure date is extremely difficult, especially one that tracks customers by the day, the week or the month of departure and vintages them accordingly. Each of the IOUs has made an alternative recommendation to establish a departing customer's vintage, and certain other parties have indicated their preferences and recommendations on this issue.
PG&E proposes annual vintaging. For example, if a customer leaves in 2009, it would be responsible for any stranded costs associated with new generation resource commitments made in 2009 and previous years, but would not be responsible for commitments made in 2010. PG&E states that its proposal is consistent with its ERRA, which is forecasted on an annual basis. PG&E adds that its proposal reflects the reality that negotiating a new PPA or obtaining Commission approval may take some time, and that although the PPA may be executed or approved later in a calendar year after a customer departs, negotiations were started or the contract was submitted to the Commission for approval before the customer departed, on behalf of that customer and other bundled customers.
PG&E states that some parties have advocated shorter vintage periods, such as a six-month vintage. However, shorter periods will only add to the complexity of administering the D.04-12-048 NBCs. Under these proposals, within any given year there would be two or more classes of customers with certain vintages, requiring the tracking of when specific resource commitments were made and when customers left. Moreover, this proposal ignores the fact that a PPA may be executed or approved by the Commission later in the year, but was originally negotiated or submitted on behalf of the customer before it departed. PG&E notes the vintage period included in Modesto's Board approved NBC tariff is an annual vintage, which is what PG&E proposes here. PG&E concludes that the Commission should adopt PG&E's annual vintaging proposal because it is equitable and can be easily administered.
SCE proposes to vintage the departing customers by the calendar year in which they depart and on whether they depart in the first or second half of the calendar year. Customers leaving or providing SCE a binding notice of intent to leave in the first half of 2009 would be assigned a vintage that would include all the resources that SCE contracted for up through December 2008. For example, a customer that departs in April 2009 (first half of 2009) will be responsible for the stranded costs associated with utility commitments made through December 2008. However, a customer that departs in September 2009 (second half of 2009) will be responsible for the stranded costs associated with utility commitments made through December 2009. SCE adds that it should be understood that "the time a commitment is made" refers to when SCE executes a contract or begins the construction of a new generation resource, not when deliveries begin under the contract or the generation resource becomes operational.
SDG&E proposes the same vintaging methodology as proposed by SCE, indicating that while no single vintaging methodology is perfect for all situations, this is the fairest and most cost-effective methodology overall.
Hercules states that bundled customer indifference cannot be achieved if departing customers are held responsible for generation commitments made after their departure. As a result, Hercules prefers SCE's proposal (assigning vintage years to departing customers) to PG&E's proposal because, under SCE's proposal, at most a customer will be held responsible for generation commitments made up to six months after departure, compared to up to 12 months after departure under PG&E's proposal.
TURN indicates that while its bundled customer constituency would benefit from slightly greater stranded cost recovery under PG&E's method, SCE's approach strikes a better balance than does the PG&E proposal. TURN adds that if its other recommendations that are designed to insure bundled ratepayer indifference were adopted, it would support the SCE proposal on this issue.
DRA states that it supports SCE's and SDG&E's proposals adding that the Commission must craft a workable solution that balances the rights of departing load customers with the practicality of utility administration.
AReM notes that the Commission will be considering a broad range of issues related to a new retail market structure in its rulemaking concerning DA (R.07-05-025) and urges the Commission defer the development of a vintaging system for DA customers to that proceeding. However, if such a vintaging system is to be adopted in this proceeding, AReM recommends that DA customers should be assigned a vintage that corresponds with the month in which they provide notice to their utility of their intent to depart bundled service. AReM states that while, in theory, each customer should be assigned an individual "vintage" corresponding to the precise time that the customer gives notice of its intent to depart, it recognizes that this could impose a significant administrative burden, as it would require the NBCs for each customer to be calculated separately. Instead, AReM indicates that it would support a method that assigns a customer a vintage based on the month that a customer gives notice of its intent to depart bundled service, and in which customers who notify the utility of its intent to depart in a given calendar year are responsible for commitments made through June of that year.
Under AReM's proposal, customers who provide notification in January would pay for the stranded costs of up to six months of resource additions that were not made on their behalf, and customers who provide notification in December are exempt from the stranded costs of up to six months of resource additions that were made on their behalf. AReM argues that bundled customers would be left indifferent, since the overpayments and underpayments should, on average, cancel each other out, and there is no room for gaming, since a customer is never any better off for delaying his departure.
CCDC asserts that the vintage of DG customers is 2002 and, therefore, customers who install DG after 2002 should not be subject to stranded cost recovery under D.04-12-048 or net cost allocation under D.06-07-029. CCDC argues that, for purposes of vintaging, load should be considered departing as of the date an IOU knew, or should have known, of the departure and notes the record in R.02-01-011 demonstrates that the IOUs had knowledge of DG departing load at least as early as 2001. It is CCDC's position that the IOUs should have continued forecasting DG departing load, the IOUs should be incorporating those forecasts into its procurement plans, the IOUs should not be procuring power for load they forecast will depart, and therefore the date of departure, or the vintage, for DG departing load, should be 2002. If the Commission does not set 2002 as the vintage for all CHP DG, then CCDC supports SCE's vintaging proposal.
Merced ID and Modesto ID similarly state that the Commission should confirm that the vintage of the transferred and new municipal departing load of Modesto ID and Merced ID is 2002 and, therefore, that the transferred and new municipal departing load of Modesto ID and Merced ID is not subject to stranded cost recovery under D.04-12-048 or net cost allocation under D.06-07-029. Merced ID and Modesto ID recommend that vintaging for non-exempt departing load should be based on SCE's proposal.
EPUC states that if no exemption is adopted for CGDL, the IOUs should use six month periods for vintaging purposes.
CCSF recommends there be at least two vintaging periods per year.
The CCDC and the Merced ID/Modesto ID proposals that the vintage year for their customers should be 2002 are essentially based on the premise that forecasted load should be excluded from having to pay the new generation NBCs. This issue was addressed earlier in this decision. As discussed in Section 4.1, MDL, with the exception of large municipalizations, and CGDL customers' fair share will be zero, and thus, they are excluded from having to pay the D.04-12-048 NBCs. The reason for the exemption is that these loads were excluded from the load forecasts used to develop the LTPPs. (See discussion above.) It is therefore unnecessary to address the 2002 vintage year issue.
We will not grant AReM's request to defer the development of a vintaging system for DA customers to R.07-05-025. Earlier in this decision, we determined that customers who are eligible to return to DA should not be excluded from having to pay the NBC associated with D.04-12-048. A vintaging methodology needs to be adopted now in order to determine the related cost responsibility, if and when such customers return to DA. If there are any vintaging related determinations made in R.07-05-025 that affect what is adopted in our decision today, we will consider modifications to today's decision, as necessary, at that time.
For DA customers, CCA customers,62 and customers departing due to a large municipalization that is not reflected in the departing load forecasts, there are two general vintaging proposals as described above in the parties' positions. PG&E proposes that December 31st should be the assigned departure date for vintaging purposes for those customers departing in any particular year. Most customers would therefore have an assigned departure date that is later than the actual departure date. On the other hand, SCE proposes that customers departing in the first half of the year would have a departure date for vintaging purposes of December 31st of the prior year, while customers departing in the second half of the year would have a departure date for vintaging purposes of December 31st of the year in which they depart. By this method, some customers will have assigned departure dates that are earlier than the actual dates, while others will have assigned departure dates that are later than the actual dates. As indicated above, this proposal is supported by a number of parties and is perceived to be fairer than PG&E's proposal.
First of all we agree that it is necessary to have some simplifying methodology so that the IOU does not have to figure out and administer the actual vintage for every customer.63 However, in simplifying the process, most customers will have assigned departure dates that will not be the same as the actual date. The consequence of having a later than actual departure date is that the customer may end up being responsible for resource commitments made after that customer's actual departure (likely to benefit the remaining bundled customers), while the consequence of having an earlier than actual departure date is that the customer may end up not being responsible for certain resource commitments before that customer's actual departure (tending to be potentially adverse to the remaining bundled customers). Under PG&E's proposal, most customers will have assigned departure dates that are later than actual. This proposal would almost certainly benefit the remaining bundled customers in the long term. Under SCE's proposal there will be customers with assigned departure dates that are both earlier and later than actual. Over the long term, potential benefits and adverse effects to bundled customers would tend to balance out under this proposal. Consistent with our commitment to adhere to the bundled customer indifference principle where possible, we will adopt SCE's proposal to use two departure dates for vintaging purposes. We will also adopt SCE's related proposal that "the time a commitment is made" is when the IOU executes a contract or when the IOU begins the construction of a new generation resource, not when deliveries begin under the contract or the generation resource becomes operational. With regard to PG&E's concerns regarding complexity, the SCE proposal would still use annual electric revenue adjustment mechanism (ERAM) forecasts, and we do not see the process of assigning the vintage based on either the year in which the customer departs or the year before the customer departs (SCE proposal) as being any more complicated than assigning the vintage based on the year in which the customer departs (PG&E proposal). An assignment to a particular year needs to be done in either circumstance. Also, we are not persuaded to adopt PG&E's proposal for the stated reason that negotiating a new PPA or obtaining Commission approval on behalf of a departing customer and other bundled customers before the customer departs may take additional time that is not directly reflected in the vintaging process. As indicated previously, we have adopted SCE's vintaging proposal which includes the identification of resource commitments that are made on behalf of departing customers based on when the IOU executes a contract or begins the construction of a new generation resource. That sufficiently covers the timeframe for departing customers' cost responsibility.
AReM's alternative proposal to use commitments as of June 30 for DA customers leaving bundled service in that year is similar to SCE's proposal in that, over time, the effect of customers having assigned departure dates earlier than the actual dates would be balanced by the effect of customers having assigned departure dates later than the earlier the actual dates. The only difference is that under AReM's proposal, DA customers departing in the first half of the year would have an assigned departure date that is later than their actual departing dates, while DA customers departing in the second half of the year would have an assigned departure date that is earlier than their actual departing dates. This is the opposite of SCE's proposal whereby customers departing in the first half of the year would have an assigned departure date that is earlier than their actual departing dates, while customers leaving in the second half of the year would have an assigned departure date that is later than their actual departing dates. Fairness and bundled customer indifference can be achieved under either approach. For consistency, we prefer to use one approach for all customers. Also, it is not clear what additional work would be involved in developing the June 30th, or mid-year, portfolios and the associated costs. The generation revenue requirement set forth in the ERRA proceedings and the allocated DWR power charge revenue requirements are generally determined on a full-year basis. For that reason, as well as the fact that it was preferred by a majority of the parties, we choose to adopt the SCE vintaging proposal over that of AReM.
The six-month proposal by EPUC appears to be similar to PG&E's proposal except the lengths of the vintaging periods are halved. There is still the problem of having most assigned departure dates being later than the actual departure dates. The six-month proposal would also add administrative burdens, since resource vintages and revenue requirements would also have to be determined on a six month rather than annual basis.
6.3. Calculation of the D.04-12-048 NBC
The D.04-12-048 NBC will be reflected as an element of the CRS as explained above. The new generation costs will be calculated annually by each IOU as part of the generation revenue requirement determined in its ERRA proceeding. The adopted DWR power charge revenue requirement is determined from the DWR revenue requirement allocation proceeding. With this information, the indifference amounts can be calculated. Since the calculation of the indifference amount requires both the adopted generation revenue requirement and adopted DWR power charge revenue requirement, each utility will submit the calculation of the indifference amount for each vintage of departing load in its advice letter implementing the later of the annual ERRA decision or the annual DWR revenue requirement allocation decision, as is currently done.64 Those advice letters will be reviewed by the Commission's Energy Division, but parties have the opportunity to protest the advice letter filings if they see a need to do so. Also, issues regarding consistency of the implementation and calculation of the CRSs with respect to this decision can be raised and litigated in the forecast phase of the IOUs' ERRA proceedings.
Examples of CRS calculations that include new generation charges are shown in Appendix E to this decision.65
While all parties did not address all aspects of the calculation of the D.04-12-048 NBC and related CRS, there appeared to be a few areas where there did not appear to be any disagreements. They include (1) the use of the market benchmark adopted in D.06-07-030, as modified by D.07-01-030, to determine above-market costs and (2) the use of a forecast of costs, done through the ERRA, without an after-the-fact true-up. Both are reasonable and should be used in determining the D.04-12-048 NBC and related CRS.
Regarding the market benchmark, SCE believes that the current methodology for determination of a market price benchmark is reasonable as long as the load departure does not increase significantly above that seen in the post-2001 period.66 If it does increase significantly, SCE states that it may ask the Commission to revisit the issue, indicating that, in that case, it may be appropriate, for example, to calculate a mark-to-market for the utility portfolio for each calendar year (or smaller intervals such as each quarter) and assign the resulting stranded costs to all customers departing during that calendar year for all future years. SCE also cites Finding of Fact 38 of D.04-12-048, which recognizes that future development of liquid and competitive capacity markets and the implementation of the California Independent System Operator's Market Redesign and Technology Upgrade may warrant a modification to the adopted market price benchmark. SCE's concerns are legitimate. We will leave it to the parties to propose such changes, if and when they become necessary, in the proceedings where the market benchmark is calculated and used (e.g., the ERRA).
Based on the cross-examination of PG&E witness Winn on the cost recovery concept that, for a specific amount of utility plant, the accumulated depreciation is lower in the earlier years, and the associated net plant and fixed costs are therefore higher in the earlier years, when compared to the later years,67 Merced ID/Modesto ID argue that the Commission should require that the IOUs should use a levelized calculation of the fixed costs of utility owned generation assets. Merced ID/Modesto ID suggests the Commission could have a workshop to address implementation of a levelized cost calculation. CCDC and EPUC make similar recommendations.
While the concept of levelized fixed cost recovery may be valid under certain circumstances, we will not deviate from normal capital cost recovery in this instance. As suggested by Merced ID/Modesto ID, CCDC and EPUC the fixed cost revenue requirement in the latter years of a project's life may be less than in the early years. This is principally due to the reduced rate base amount caused by the accumulated depreciation up until that time. However, in this proceeding we are dealing with stranded cost recovery that may last for 10 years while the project itself may have up to a 30-year life or more. Regarding the proposed levelized fixed cost recovery proposal, we do not feel it is equitable for customers who will only be paying for 10 years of the project's depreciation to be entitled to the entire reduced revenue requirement effect that results from the accumulated depreciation that will have been paid by other customers for 30 years or more. Therefore we will not adopt the levelized fixed cost recovery proposal for use in this track of the proceeding.
6.3.3. Determination of Capacity Adders and Line Loss Adjustments
EPUC also states a need for workshops related to the determination of capacity adders and line loss adjustments. However, EPUC did not explain what is wrong with either the values of these items or the way that these items are included in NBC calculation, or make any proposals to address any perceived shortcomings. No other party stated a need or recommended workshops for these purposes, and no party expressed agreement with EPUC in this regard. Such workshops have not been justified and will not be required by this decision.
6.4. Cost-Effectiveness
CCDC, Merced ID and Modesto ID have recommended that the Commission should evaluate the cost-effectiveness of the IOU's proposal for determining stranded costs, vintaging customers and calculating and imposing NBCs.
Also, Hercules states that no NBC should be billed to a departing load customer if the cost of determining, billing and collecting the charge exceeds the revenues to be collected. Hercules argues that without this limitation the IOU's bundled customers would be forced to pay more for billing and collecting departing load charges than the revenues would otherwise justify, thus violating basic principles of cost benefit.
While certain parties questioned the cost-effectiveness of the NBCs, no party provided any analysis or other evidence that would indicate whether or not the NBCs proposed by the IOUs in this proceeding were, or were not, cost-effective when comparing the costs of implementing and imposing the charges with the revenues that might be generated by such charges.
In order to address this issue, the ALJ requested the IOUs to provide the following:68
1. NBC related activities necessary to do the following:
a. Calculate the system average new generation NBC by vintage year or calculate the cost responsibility surcharge by vintage year.
b. Determine cost allocations.
c. Identify the customer.
d. Determine the customers NBC.
e. Bill the customer.
f. Collect and process a customer's payments.
g. Develop and maintain necessary tools and data base to perform items a. through f.
2. Estimates of the costs for each of the activities identified in response to Item 1 by cost center if possible. For Items 1.c. through 1.f. provide estimates of costs on a per customer basis.
3. For each cost identified in response to Item 2, an indication of whether the cost is a recurring or non-recurring cost. Include the frequency of recurring costs.
4. For each cost identified in response to Item 2, an indication of whether the cost is incremental to costs currently incurred by the utility or whether the cost is embedded in costs currently incurred by the utility.
5. Range of potential revenues that might be realized by imposition of an NBC, including that related to low, medium, and large usage customers, based on NBCs calculated using new generation costs or to total portfolio costs being 5% and 10% above the market price benchmark.
6. Conclusions and explanations of conclusions on the cost-effectiveness of imposing the NBC.
7. All assumptions and calculations related to 1 through 6.
8. Provide the information requested in Questions 1 through 7 for existing procurement related non-bypassable charges.
The intent of the ALJ's questions was to determine whether a reasonable forecast of revenues associated with NBCs could reasonably be expected to exceed the incremental costs of implementing and imposing the NBCs, which is generally the issue that was raised by the parties. There was no intention to determine the cost-effectiveness of previously authorized and implemented charges such as the ongoing CTC or DWR power charge.
PG&E, SCE and SDG&E's response to the questions in Exhibits 211, 212 and 213 were filed on October 12, 2007. To allow parties the opportunity to comment on, or express concerns related to, the materials contained in the exhibits, a date of October 19, 2007 was set for the filing of responses to the exhibits. Responses were filed by CMUA, EPUC, Merced ID/Modesto ID, and CCSF.
According to CMUA, the information contained in the IOU documents should be afforded no more weight than that attributed to any response to a data request not subjected to cross-examination. CMUA states that neither PG&E nor Edison provides any supporting documentation or verification for their conclusions that the New Generation NBCs are cost effective. Rather, the IOUs' conclusions are based on an analysis that lumps together all classes of departing load - existing and potential - into one large group. CMUA argues that until such time as the IOUs respond completely to all the elements of the request, providing the Commission more comprehensive and detailed cost information, and until such information is subjected to additional examination and scrutiny, the Commission cannot conclude that the New Generation NBCs are cost-effective. CMUA urges the Commission to regard the IOUs' filings as merely the first step in addressing this issue, and as the initial basis upon which to develop a more detailed record.
EPUC states (1) SDG&E erred in describing past applicability of NBCs to customer generation departing load (CGDL); (2) SCE's filing does not show cost-effectiveness of application of the proposed NBC to CGDL; and (3) PG&E does not provide a method for distinguishing between incremental load growth met with a direct transaction and normal course of business load changes or show how much it would cost the utility to distinguish between them. Additionally, according to EPUC, it remains unclear how a CGDL customer's standby service would be accounted for in determining this utility procurement departing load charge and whether the customer may essentially be charged twice for the same energy.
EPUC concludes that the IOUs' filings are inconclusive regarding the cost-effectiveness of applying a new procurement NBC on CGDL and further highlight the need for an exemption for these customers.
The primary concern Merced ID and Modesto ID have with the IOUs' cost-effectiveness exhibits is that they combine MDL with DA and CCA departing load. By applying the above-market assumptions to such a large potential departing load customer base, the IOUs overstate potential New Generation NBC revenues and understate the NBC collection costs potentially attributable to MDL. Additionally, Merced ID and Modesto ID state the IOUs' exhibits are superficial, contain errors and fail to fully respond to several of the questions.
Merced ID and Modesto ID request that the Commission (1) should require the IOUs to calculate potential New Generation NBC revenues for MDL only; (2) accord the IOUs' cost-effectiveness exhibits the weight of untested argument and use them only for the purpose of developing the scope of any further investigation it undertakes regarding the cost-effectiveness of any New Generation NBC; (3) consider findings in D.07-09-041 regarding PG&E's billing practices and findings in the Presiding Officer's Decision in Investigation 06-06-014 regarding manipulation of customer satisfaction data in SCE's Performance Based Ratemaking in deciding what weight to ascribe the cost-effectiveness exhibits of each; and (4) recognize PG&E's admissions that (i) it is aware of POU annexation proposals, and (ii) it has the ability to adjust its load forecasts to reflect successful proposals.69
CCSF states there are significant issues of concern arising from the IOUs' responses, including the following:
· PG&E appears to overstate the nature of Commission approval of current NBCs;
· The IOUs appear to over-estimate the size of the potential departing load;
· PG&E asserts that the "overwhelming majority" of new municipal load will use PG&E gas service (implicitly assuming that all such developments will include gas as a service). Neither assumption is substantiated;
· PG&E's proposed use of such gas records, even where it may be possible, seems potentially improper;
· PG&E and SCE appear to give no response to ALJ Question 8; and
· The responses generally seem to marginalize the incremental costs of these NBCs in a way that seems at odds with part of the IOUs' positions in litigation.
According to CCSF, the information cannot be deemed either accurate or reliable absent any test of its veracity, and the opportunity alone to offer comment is a poor substitute for time to review, opportunity to serve discovery and/or opportunity to cross-examine the proponents of the assertions at issue.
CCSF recommends the responses not be admitted as additional testimony, the exhibit numbers should be vacated and the submissions be identified as "Responses" with the express ruling that they are to be given the weight of untested argument only.
In an October 23, 2007 ruling, the ALJ ruled that, in order to issue a timely decision for this track of the proceeding, the cost-effectiveness issue would not be pursued as far as having the utilities augment or correct their exhibits, providing parties the opportunity to conduct further discovery and prepare responsive analyses, or providing parties the opportunity to cross-examination the IOUs on information contained in the exhibits. The ALJ also acknowledged the concerns expressed in the parties' responses as described above. While the exhibits were received into evidence, it was indicated that they would be weighed accordingly and that the value of the information in determining the cost-effectiveness of NBCs either generally or for a specific type of departing load is therefore limited. It is with this understanding that we now address this issue.
If new generation costs or total portfolio costs were 5% to 10% above the market price benchmark, the information provided by the IOUs demonstrates that imposition of the new generation NBCs would be cost-effective when analyzed on an incremental basis. For example, PG&E indicates that its costs to implement the D.04-12-048 NBC include a one-time billing system upgrade cost of between $5.8 and $7.5 million and recurring annual costs of approximately $23,331 per year. The revenues, which would be fully credited back to bundled customers to off-set above market generation costs, could be between $7.1 million a year (5% incremental departing load and 5% above market benchmark) and $28.5 million a year (10% incremental departing load and 10% above market benchmark) a year. PG&E states that over a 10-year period, this could result in revenues between $71 million and $285 million, depending on market conditions and departing load. SCE indicates most costs are embedded and quantifies incremental costs of between $200,000 to $1,200,000 to develop and maintain systems and data bases.
SCE estimates potential annual revenues of approximately $25 million (5% above market benchmark) and $50 million (10% above market benchmark). SDG&E estimates a potential range of yearly revenues of between $854,835 to $6,786,076 (assuming a total portfolio cost that is 5% and 10% above the 2007 market benchmark, allocated to a range of incremental departing load forecasts of 4% and 8%).
SDG&E indicates that implementation of tools and data bases would be a one-time cost of approximately $85,000 and determining the customers NBC would be a one time cost per account of approximately $2. According to SDG&E, there are no incremental costs associated with most of the other activities.
As explained earlier, the information provided by the IOUs was not subject to cross-examination. Whether certain costs are reasonable or are correctly classified as recurring, non-recurring, embedded or incremental is an issue that will not be resolved in this proceeding. Also, the IOUs' analyses could not and did not consider our resolution of the issue related to the applicability of the charges discussed earlier in of this decision. However, the description of the activities and, when provided, the quantification of costs appear to be in a reasonable range. What we conclude from this information is that potentially there is a substantial amount of revenue at stake in the new generation NBCs and at least under certain circumstances (e.g., CCA, large municipalizations and the potential for reopening direct access) the overall incremental revenues generated by the D.04-12-048 NBC would likely more than offset the overall incremental costs of implementing the NBC. In order to capture any revenues associated with the NBCs, the necessary costs to implement the charges must be incurred. In light of potentially significant amounts of new generation NBC revenues, it is reasonable to incur such charges. We make this finding with the understanding that undertaking any detailed cost-effectiveness analyses70 for these particular NBC charges at this time would be a speculative and not a particularly revealing exercise. That is because the costs for future new generation resources, the future market benchmark prices and the future amounts of load shifting caused by DA, CCA, MDL and CGDL would be the principal elements in any such analyses, and are generally unknown at this time.71 It is also for these reasons that we will not pursue the cost-effectiveness issue any further in this proceeding.
For the same reasons, once the charges are in place, it is reasonable for the IOUs to collect the NBCs without continually having to demonstrate cost-effectiveness for particular charges for particular customers.72
6.5. Additional Issues
Merced ID/Modesto ID state that it is possible that the level of stranded cost recovery and/or net cost allocation mechanism NBCs will be unreasonably high and recommend that the Commission evaluate these NBCs on an annual basis and determine whether it is appropriate to establish and implement a cap.
The Merced ID/Modesto ID assertion regarding the possible high level of stranded cost recovery is very general and not supported by any specific basis or reasoning. Prior to the costs of any of these new generation resources being included in the revenue requirement and being eligible for stranded cost recovery, the Commission will have already examined both the need and costs of the projects. We do not anticipate that our processes will result in unreasonably high levels of stranded cost recovery. It is not necessary to establish an annual procedure to determine whether it is appropriate to establish and implement a stranded cost recovery cap.
With respect to PPAs for non-RPS commitments, Merced ID/Modesto ID and CCDC interpret the D.04-12-048 provision that the IOUs should be allowed to recover any stranded costs that may arise over either the life of the contract or 10 years, whichever is less, to mean stranded cost recovery should begin when the PPA is signed, not when the project commences operation. We do not agree with that interpretation. From the time that the PPA is signed to the time the project commences operation, there are generally no payments being made. Essentially all costs to the IOU and the associated cost recovery from customers will begin with the commencement of operation of the project, and that is when the 10-year cost recovery period should begin.
For example, departing DA load in 2010 will be required to pay for nine years for a non-RPS resource that begins commercial operation in 2009, but for a non-RPS resource that is contracted for by the IOU in 2008 and will begin commercial operation in 2013, this customer will owe NBCs related to this resource from 2013-2022.
46 The total portfolio does not include contracts subject to the CAM adopted by the Commission in D.06-07-029.
47 For SCE, the HPC was also included as part of the CRS; however, the HPC was paid off and is no longer a part of the CRS.
48 See D.07-05-005, pp. 18-21.
49 SCE, Jazayeri, 11 RT 1442-1445.
50 The total portfolio methodology does not apply if a customer does not pay the DWR power charges. (See D.05-01-035, p. 3; D.06-07-030, pp. 34-38; D.07-01-020, p. 5.)
51 See D.07-05-005, pp. 18-19.
52 For purposes of this decision, "pre-restructuring resources" refers to those current IOU resources that existed prior to March 31, 1998 and are not subject to ongoing CTC treatment. These resources consist principally of the IOUs' retained generation (i.e., hydro, coal and nuclear plants). Power from these resources tends to be cheaper when compared to the costs related to ongoing CTC, the DWR contracts and new generation.
53 Consistent with D.06-07-030, pre-restructuring resources cannot be used to mitigate the costs of ongoing CTC alone. In that decision, we stated "We thus conclude that applying a bundled customer indifference standard is not appropriate in deriving the cost responsibility for MDL customers if no DWR power charge is paid. We shall apply a total portfolio indifference standard to MDL CRS obligations only where a DWR power charge is applicable. The indifference adjustment does not change the ongoing CTC that applies uniformly to all bundled, DA and DL customers." (D.06-07-030, p. 37.)
54 The pre-restructuring resources would be included in the portfolio as long as they have not been retired.
55 TURN Opening Brief, p. 7. See also Exhibit 117, p. 13.
56 For example, see Resolutions E-4046, E-4047, E-4055 and E-4084, E-4110, E-4084, and E-4138.
57 The potential increase in DA is dependent on the outcome of our proceedings regarding the lifting of the DA suspension. Our reference to this potential increase is not intended to prejudge the outcome of those proceedings.
58 In D.04-12-048, the Commission stated, "A major issue in this proceeding is the extent to which the utilities will be compensated for investments or purchases that they must make in order to meet their obligations to provide reliable service to their customers. The implementation of CCA, departing municipal load, and the potential for lifting, in some form or another, the current ban on allowing new DA all create a great degree of uncertainty as to the amount of load the existing utilities will be responsible for serving in the future. Given the potential for a significant portion of the utilities' load to take service from a different provider, the utilities are concerned that they could end up over-procuring resources and incurring the stranded costs associated with these resources." (D.04-12-048, p. 55.)
59 SCE, Exhibit 34, p. 14.
60 SDG&E, Exhibit 51, p. 1.
61 Departing customers also include new MDL.
62 An optional BNI process exists for customers choosing CCA. The departure date would be the CCA stated date on which the BNI is based. For those CCA customers who do not choose the BNI process, their departure date is when they cease taking procurement services from the IOU.
63 We agree with SCE's statement that "Ideally, departing customers should bear no cost responsibility for the resource and contractual commitments SCE makes after their departure. In practice, however, it is extremely difficult to track customers by the day, the week or the month of departure and assign them a CRS vintage. Vintaging based on calendar quarters could be done; however, it gets more and more difficult because you will have now four categories of customers to deal with instead of one or two. It can go even monthly, but it just becomes an administrative nightmare." (SCE Opening Brief, pp. 7-8; see also Exhibit 34, p. 11 and SCE, Jazayeri, 11 RT 1441.)
64 See D.06-07-030, pp. 22-29 and Exhibit 34, p. 15.
65 These calculations are illustrative and not all-inclusive. For instance, it does not include a total portfolio calculation for MDL that may be subject to the DWR power charge but not the D.04-12-048 NBC. In practice, the IOUs will calculate the CRS in their Advice Letter filings, and parties can review them and protest as they see fit.
66 Merced ID/Modesto ID indicated agreement with this belief.
67 PG&E, Winn, 10 RT 1215-1218.
68 Draft questions were provided to the parties on September 19, 2007 and were discussed at the end of evidentiary hearing on September 21, 2007. Based on that discussion, certain changes were made, and the final questions were attached to the September 21, 2007 Reporter's Transcript (Volume 14).
69 In their Opening Brief, Merced ID/Modesto ID urge the Commission to undertake a further investigation into the cost-effectiveness of NBCs, including those implemented in connection with electric industry restructuring and the energy crisis, perhaps using Exhibits 211, 212 and 213 as tools in developing the scope of any such further investigation. They note that the Commission uses established tests from the California Standard Practices Manual: Economic Analysis of Demand-Side Management Programs (October 2001) to determine the cost-effectiveness of IOU programs from various perspectives, including ratepayers, society and program participants (here, departing load) and request that the Commission ultimately evaluate the cost-effectiveness of the proposed NBCs from all three perspectives.
70 For instance, some parties insist the analyses should be done separately by type of customer (DA, CCA, MDL and CGDL).
71 We note that at this point it is not cost effective to set up and implement an NBC for MDL and CGDL customers, because at this point they are excluded from having to pay the charges, once these customers depart. There would be no revenues to offset any incremental costs. However, in the event that a large municipalization occurs, having procedures authorized and in place will facilitate the imposition and collection of potentially significant amounts of NBCs. The same can be said for significant amounts of CCA should they occur. Also, while there may be some DA activity at this time related to customers returning to DA service, significant amounts of activity and significant amounts of NBCs may result in the event that DA is reopened.
72 We also note that even if the D.04-12-048 NBC were somehow demonstrated to not be cost-effective for certain customers, imposing their departing load costs on bundled customers would be contrary to the general principle against cost shifting. The maintenance of bundled customer indifference to that departing load would have to be addressed in some other manner.
