XVI. CRS Mitigation: Capping or Levelizing CRS

Various parties representing DA interests propose that the Commission consider the cumulative economic impact on DA customers of imposing DA CRS charges, and the potential risk of making DA uneconomic. The Commission has previously expressed that the DA program has value for California, and that efforts should be undertaken to avoid making DA uneconomic. Various parties propose that the DA CRS be capped at prescribed amount to limit the adverse economic effects on DA that would otherwise result from the increase in electricity charges that would be required to fully fund DA CRS, including the Bond Charges.

Other parties such as TURN and ORA state that the Commission must address the risk a cap places upon bundled customers. Financing of the undercollection produced by a cap must come from somewhere. (See PG&E cross-examination of McDonald/DWR, Tr. 1, pp. 15-120). Bundled customers will pay the financing costs by default if another group or entity does not. (Marcus/TURN, Tr. 3, pp. 299-302. ) If a DA surcharge cap is adopted, issues that must be addressed include (1) what level of cap should be set; (2) under what conditions should the level of the cap be reevaluated; (3) what components does it cover? and (4) in what order are costs collected? Questions also arise concerning how the deferred collections in excess of the cap should be financed, and by whom. What interest rate should be applied to the deferred charges, and how can the responsibility for funding the interest be assigned to preserve bundled customer indifference?

D.02-07-032 (authorized SCE to establish a "Historical Procurement Charge" (HPC) in the matter of A.98-07-003. SCE was thereby authorized to apply the HPC to DA customers by reducing the DA customers' generation credit by 2.7 cents/kWh until the effective date of a Commission decision implementing a DA CRS in the instant rulemaking (R.02-01-011). This reduction in the DA surcharge credit was intended to provide for equivalent contributions between bundled and DA customers for the recovery of SCE's past procurement cost undercollections.

In D.02-07-032, we noted the likelihood that DA customers would be subject to DA CRS in this proceeding, bond charges in A.00-11-038 et al., and "tail" CTC associated with Public Utilities Code Section 367, in addition to the HPC. We observed that the "pancaking" of surcharges in different proceedings may lead to DA contracts becoming uneconomic. Yet, we have also set forth our policy in D.02-03-055 that there is value in maintaining the DA market. To guard against DA contracts becoming uneconomic, we stated in D.02-07-032 that "there should be a cap on the total surcharge levels imposed on DA customers (including the impact of any changes to PX credits)." D.02-07-032 did not, however, set a specific overall cap, and deferred the particular issue to other proceedings for further consideration.

Parties present a divergent range of DA CRS cap proposals. CLECA and CMTA argue that the combined effect of SCE's HPC, a charge to recover the DWR historical costs, a charge to recover the DWR Indifference Costs, and a charge to recover the above-market URG costs could make DA uneconomic.⁹⁹ Both parties argue that this is inconsistent with the direction of the Commission.¹⁰⁰ CLECA proposes caps of 2.0 cents/kWh for PG&E and 2.25 cents/kWh for Edison and 2.75 cents/kWh for SDG&E. Because of SDG&E's relatively higher costs, CLECA recommends a 20-year recovery period rather than a 15-year period. It was on the basis of the figures on Table 2 of CLECA's exhibit that Dr. Barkovich concluded that its proposed caps would accommodate full recovery of the HPC, the Bond Charge and the DWR charges over time.

CMTA proposes a uniform cap of 2.0¢/kWh be adopted, along with balancing accounts to reconcile DA CRS revenues and allocated costs. CMTA proposes that the Commission sequence the recovery of the various categories of costs under the cap with the HPC procurement costs receiving the highest priority, followed by uneconomic DWR and URG costs. Total charges would remain at the capped level until DA customers had fulfilled their HPC obligation and were current on their contribution to uneconomic DWR and URG costs. CMTA argues that its recommendation in this regard is consistent with the D.02-07-032 concerning SCE's HPC.

SCE believes that adopting a cap is appropriate, and consistent with the Commission's intention to maintain DA as a viable customer option. SCE believes, however, that a 2.0¢/kWh cap is too low, and that the cap should initially be set at a level to at least allow the recovery of SCE's HPC and the Bond Charge. SCE believes that setting the cap at 3.0¢/kWh will allow recovery of both of these items, with the condition that the first part of the revenues go to the Bond Charge (and to DWR) and the rest of the charges go to recovery of SCE's PROACT. Recovery of the PROACT will help SCE regain its credit worthy standing which was a top priority of the Settlement. Once the PROACT is recovered, SCE can reduce its charges to reflect the underlying cost of service, benefiting all customers. Setting the cap at 3.0¢/kWh will also accelerate the recovery of PROACT and allow the DWR above-market costs to be recovered sooner, which will benefit bundled service customers.

SCE argues that it should not be required to finance any deferred collections of DWR revenue requirement attributable to DA customers in excess of a cap. Because the amounts collected for DWR power are the property of DWR, and not the IOUs, SCE argues that DWR should be the entity financing these undercollections. DWR disagrees and proposes that it be paid first from any funds collected under a cap, with IOUs bearing the risk for covering their remaining costs through any remaining funds.

PG&E believes that a cap of 4 cents/kWh would be reasonable, based on the comparative level of bundled rates that would be the alternative for DA customers. PG&E proposes that the Ongoing CTC be deemed to be recovered first, then the DWR Bond Charges, leaving any shortfall attributable to the DWR. PG&E also proposes that the cap be differentiated by voltage level for Rate

Schedule E-20, consistent with underlying rates themselves, to reflect the differing line losses at different voltage levels.

If a DA surcharge cap limits the revenues recovered from DA customers for the DWR revenue requirement, then DWR must either receive less than its total revenue requirement for that year from customers, or must collect the DA shortfall from bundled customers. In the latter event, however, bundled customers would pay more than was allocated to them under the indifference calculation for that year.

PG&E proposes that DWR issue bonds to finance that shortfall. This approach would require the active participation of DWR in developing the bond issuance to finance the cap.

According to PG&E, with DWR funding the shortfall, customers would then be able to take advantage of the interest rate at which DWR can issue bonds. Under this approach, PG&E argues that bundled customers provide the same amount each year as they would to DWR if there were no cap. PG&E claims that DA customers pay less in the early years, and more in the later years as they bear responsibility for the bonds issued to finance the effects of the DA surcharge cap.

PG&E states that under the other approach, bundled customers would provide more to DWR in the early years, relative to the uncapped calculation, and less in later years. An "interest rate" would have to be established, to determine how much additional cost responsibility DA customers would have to bear in the future to "pay back" bundled customers for the extra amount they bore in the early years.

SDG&E favors levelization of annual fixed charges as a preferred approach to mitigating DA CRS, particularly given the relatively higher DWR costs experienced within its service territory. Levelization defers the impact of high-cost contract obligations in the early years to later years. SDG&E is also amenable to an overall cap on DA CRS in conjunction with levelization of the DWR component. SDG&E believes that a 2.7 cent rate cap, encompassing the individual rate components of the DA CRS, DWR Bond Charge, HPC Charge, and ongoing tail-CTC, would more than cover its costs if its positions were adopted, as set forth below:

DWR Ongoing 1.26 cents

DWR Bonds 0.51

HPC 0.00

CTC 0.70

2.47 cents

However, based upon updated DWR revenue requirements, SDG&E believes the Commission may well adopt a DWR Bond Charge higher than that proposed by SDG&E, pursuant to the terms of the SDG&E-DWR Servicing Agreement and/or the Rate Agreement. To the extent that this occurs, and results in the aggregate sum of the components exceeding the 2.7 cent cap, such a cap would result in an underrecovery of one or more SDG&E components under the cap.¹⁰¹

SDG&E states that under-recovery would result from the fact that, once adopted, the DWR Bond Charge becomes a non-bypassable charge that must be recovered pursuant to the SDG&E-DWR Servicing Agreement. In much the same fashion, the ongoing tail-CTC is also a non-bypassable charge that must be recovered. For PG&E and SCE, an HPC charge is expected to remain fixed for a period of one or more years. Consequently, the only remaining element to be under-recovered is the DA CRS.

To the extent that a DA CRS revenue recovery shortfall is caused by the cap, SDG&E believes the shortfall should then be recovered from that IOU's bundled customers and tracked for that IOU. At such time that adequate headroom exists under the cap, SDG&E argues that DA customers should reimburse bundled customers for that shortfall with interest calculated at the 90-day commercial paper rate. According to SDG&E, this headroom would develop over time as a result of the completion of the collection of the HPC charge, and possible changes in the level of the DWR Bond Charge and ongoing tail-CTC.

TURN and ORA raise the concern as to how the capping of DA CRS could adversely affect bundled customers who could potentially be burdened with shouldering the financing costs of excessive deferrals of DA cost responsibility.

Discussion

In accordance with the policy considerations in D.02-07-032, as described above, we conclude that a cap on the DA CRS needs to be adopted.

One consideration in setting a cap is to whether it is low enough to limit the charges imposed on DA to avoid making DA uneconomic. Yet, the evidence presented on this issue was subjective and limited to anecdotal accounts of discussions with industry representatives. Based on this limited evidence, we find little basis to quantify the precise relationship between the level of a cap and the number of DA contracts that may become uneconomic.

Another consideration in setting a cap is whether it is high enough to provide reasonable assurance that sufficient DA CRS funds will be collected over time to reimburse bundled customers for any funds they advance to finance the DA CRS cap. Because of the uncertain nature of the long-term forecasts presented in this proceeding concerning costs assignable be DA customers over the remaining life of the DWR contracts, no precise determination can be made as to the DA CRS revenues that will be generated over time to pay down the undercollections that will build up in the early years.

In the absence of sufficient and persuasive empirical evidence concerning the precise economic sensitivity of DA to various levels of caps, we must weigh the potential impacts of adopting a cap at either the high end or low end of parties' recommendations. Not only do we consider the adverse impacts of imposing a cap that is either too high or to low, we also consider whether effects will be experienced now or in the future. Another consideration is who will pay the interest charges to finance the excess portion of the DA CRS above the cap. We conclude that in order to preserve bundled customer indifference, the interest charges required to finance the cap must be borne by DA customers. If bundled customers were required to fund interest charges to finance DA customers' cap, they would no longer be indifferent since those interest charges would increase total bundled customers' costs. Therefore, any cap that is imposed must include within it any interest charges required to finance the excess above the cap.

The timing is also a relevant consideration in setting a cap. The potential risk to bundled customers of setting a low cap is in the potential for large undercollections to build up to a point where bundled customers would be forced to absorb at least some of the debt because DA customers would be financially unable to pay it. This risk grows as a function of time. Thus, bundled customers exposure to this risk is felt less initially and more over time as any potential undercollection builds up. The timing effects just the reverse in the case of DA customers. The potential risk to the DA program in setting a high cap is felt more at the front end when DA CRS is initially established. If the initial cap is set too high to permit DA contracts to remain economically viable, the risk is that those DA customers will leave the DA program. Because the level of the DA CRS is projected to be lower in the latter years of the DWR contracts, there will be more flexibility to adjust the cap in the future as compared with today when costs are comparatively high. The balance of risks associated with a cap favors setting an initial cap on a more cautious basis. In D.02-07-032, we observed that a cap of 2.7 cents/kWh might be a reasonable cap. Thus, the DA community was alerted that this preliminary figure could be at least a potential starting point for a cap.

Parties failed to present any convincing evidence that this preliminary assessment should be significantly raised, particularly as initial DA CRS is set. Parties proposing caps as high as 4 cents/kWh did not provide persuasive evidence that a cap this high could be imposed without conflicting with the Commission's policy objective that the economic viability of DA should not be adversely affected. Although certain comparisons were made with bundled rates to argue that a 4 cents cap would still be less than bundled rates. We do not find such a comparison to constitute convincing proof that DA contracts could survive such an increase in electricity charges. It is not clear that the choice facing DA customers is necessarily bundled versus DA rates. In the face of sufficiently high bundled rates, the choice may instead, at least for some customers, be between DA rates or departing the utility system permanently either through business failure or relocation outside of California.

The other reason cited for the 4 cents cap is to avoid the build up of excessively high DA undercollections that could become the burden of bundled customers. While we acknowledge the validity of concerns regarding the potential risk of bundled customers becoming burdened with excessively large undercollections, we view this risk as a potential problem that could grow over time, but not as an impediment to setting a cap lower than 4 cents, as we adopt below, at least for an initial period. We reserve the option of revisiting the potential size of the cap or the terms under which it will apply after conducting a further inquiry into the potential means of financing the cap and ensuring that DA customer will bear responsibility for financing the cap and for paying off any undercollections over time.

We also conclude that the 2.0¢/kWh cap proposed by CLECA and CMTA is too low to cover the requisite components of DA CRS without triggering unduly large deferred balances.

In the absence of any positive evidence to the contrary other than subjective assertions of certain witnesses, we conclude that an initial cap set at the level of 2.7 cents/kWh represents an appropriately cautious starting point for a cap, particularly at the very beginning of instituting these charges. In the interest of caution, we find it prudent not to impose any abrupt change from the level the Commission has previously observed as as possibly reasonable cap value. An initial cap at this level will promote a bridge on continuity with the preliminary policy assessment on this issue that we made in D.02-07-032. Thus, we conclude that an initial cap of 2.7 cents/kWh is consistent with the overall goal of seeking to preserve the economic viability of the DA program.

Although the total DA CRS requirements are expected to exceed 2.7 cents/kWh in the early years, these DA CRS requirements are forecast to decline over time. SCE is expected to fully recover its HPC in 30 to 32 months after January 1, 2003. The termination of the HPC will free up one cent/kWh for recovery of other ongoing DA CRS elements and any deferral amounts at least for SCE. In addition, based on the long-term forecasts presented in this proceeding, the DWR power charge applicable to DA CRS is expected to decline over subsequent years such that the overall DA CRS elements will drop well below the 2.7 cent cap. Thereafter, DA CRS collections are expected to yield a surplus to pay down prior undercollections. CLECA's Exhibit 28, Table 1 illustrates how over 15 years, the DA CRS declines under the total portfolio approach utilizing Henwood modeling assumptions.

CLECA's calculations in Exhibit 28, however, provide only an illustrative rough indication of how collections of DA CRS over an extended period could generate a surplus in later years that could be used to pay down undercollections in initial years resulting from its proposed cap. We recognize that various assumptions in CLECA's illustrative calculations do not necessarily reflect the actual charges that will apply during those periods.

We remain concerned regarding potential longer term effects of large undercollections that could accrue as a result of continuing to apply a 2.7 cents/kWh cap, particularly in the case of SDG&E. We direct, therefore, that the assigned ALJ to issue a ruling setting a schedule to develop a further record on the level of cap that would be appropriate, given the need to achieve payback of the undercollection resulting from the DA cap with interest over a reasonable period. In order to mitigate any potential risk of accumulating unacceptably high undercollections due to the 2.7 cents cap continuing over an extended period, we direct that these further proceedings be expedited. By July 1, 2003, we expect to place an order on the Commission agenda for consideration of the appropriate cap to apply for each of the utilities thereafter.

The period of time between now and July 1, 2003 will be short enough to guard against an extended period of accumulation of undercollections, but long enough to provide for a more thorough record on which to base further assessments concerning the size of any cap, and related issues such as the appropriate compensation for the cost of money associated with bundled customers' financing of the cap undercollection, and the frequency and manner of subsequent adjustment of the cap. To the extent that we determine that the interim 2.7 cents/kWh cap needs to be adjusted for one or more of the utilities, we shall revise the cap accordingly. In setting any cap adjustment subsequent to July 1, 2003, we shall take into account any undercollections that have already been incurred through that date, to set the cap going forward so that any undercollections previously incurred can be paid down in full, with interest, over a reasonable time horizon.

The record has already been developed to some extent regarding the long term forecasts of DA CRS under both the Navigant and Henwood modeling approaches. We do not intend to relitigate controversies that were the subject of this proceeding concerning the relative merits of the differing modeling conventions and forecast assumptions between Henwood and Navigant. We have expressed our preference for the Henwood assumptions as likely being more indicative of the market price for sales of surplus power and new generation additions over the forecast period, although we realize that neither the Navigant nor the Henwood assumptions necessarily provide a particularly high level of confidence as to actual results over time. We also recognize that the actual DA CRS elements adopted for 2003 must be consistent with the methodologies being implemented in A.00-11-038 et al. which utilize the Navigant model. While recognizing the uncertainties inherent in any long-term forecast, however, we still must use the best information available to assess what level of cap will generate revenues of a sufficient magnitude to pay down the undercollections resulting from a cap as well as to pay appropriate interest charges to compensate bundled customers for the cost of money.

For purposes of the developing a further record on the determination of a cap for each of the utilities beyond July 1, 2003, we will thus build upon the forecasting of DA CRS that has already been received into this record. To the extent that more updated information is relevant, however, we shall consider supplementing the existing record to receive appropriate updated information. We already have updated information concerning DWR bond charges with the adoption of our recent order in A.00-11-038 et al. We also expect to have updated data from the proceedings in A.00-11-038 et al., as to the DWR power charges upon adoption of a decision that will be in effect for 2003. Moreover, subsequent analysis of the effects of a cap on DA CRS collections can be more focused in that we have now adopted a methodology for computing indifference costs based generally on the CLECA approach which has been termed the total portfolio method.

Recognizing that any forecasts on which we base our findings concerning a cap will be subject to the uncertainties of subsequent years' events, we also direct the ALJ to consider appropriate measures for ongoing periodic reassessment of the adequacy of the level of any cap. Possible trigger mechanisms should be considered that would require reassessment of whether to adjust the cap either upward or downward to ensure that over time, the cap is sufficient to provide reasonable assurance that bundled customers will be indifferent over time for the effects of DA migration.

For purposes of the analysis of the payback period for the undercollections generated under the cap, we are particularly interested in the maximum level of undercollection that would be generated by each of the utilities under various cap scenarios and the maximum number of years required for payback under those scenarios. We shall consider these measures under the various cap proposals that have been offered by parties to this proceeding.

While we are developing a further record on the effects of various capping scenarios on the risk, duration, and timing of payback of any undercollections, we also intend to consider any further evidence that would be relevant concerning the risk of rendering DA contracts uneconomic. We shall direct the ALJ to provide the opportunity for parties to present further evidence on this question as well, so that a balanced assessment can be made concerning the effects of caps on both bundled customer indifference and continuing the economic viability of DA.

Consistent with our prior D.02-07-032 in the SCE HPC PROACT case, the cap will include the impact of any changes to the PX (DA) credits. When PG&E and SCE move to bottoms up DA billing, there will no longer be a DA credit and there will be no need to include this credit. Until then, the impact of changes to the credit will be included. We decline to include changes in transmission and distribution (T&D) rates for DA customers, within the cap, as proposed by the Irvine Company. These costs are outside the scope of the procurement and generation costs which are the subject of this proceeding.

The DA surcharge cap should cover the surcharges considered in this proceeding: the Ongoing CTC; the DWR Bond Charge; the DWR power charges and SCE's HPC. When the Commission addresses PG&E's Historic Undercollection Charge (HUC), we must then consider how the DA surcharge cap relates to those charges.

Funds remitted under the cap shall be first applied to pay the bond charge, and secondly, to pay the 2003 DWR power charge and then to pay SCE's HPC. The DWR sources must have first claim on the funds because pursuant to the Rate Agreement that was implemented pursuant to AB 1X, DWR is entitled to timely reimbursement for both its bond charge and power charge. Although certain parties have suggested that DWR might be able or willing to assist in financing at least some portion of DA customers' share of DWR power costs in excess of a cap, DWR has claimed that it is not able to engage in such financing.

In order to provide sufficient funds from the DA CRS to cover its HPC, we shall permit SCE to recoup its one cent HPC from the 2.7 cents DA CRS proceeds. Any remaining shortfall in DWR power charges attributable to DA customers will have to be remitted to DWR on an interim basis from bundled customers' funds. To the extent that any bundled customers' funds are used to remit any portion of the DA share of DA CRS costs, an interest charge shall be assessed on DA customers to secure funds to reimburse bundled customers for the use of their money. The interest charges due to bundled customers for the advance of such funds shall be assessed upon DA customers as part of their cumulative obligation under the DA CRS in excess of the 2.7 cents/kWh cap, and credited as a future reduction for the bundled customers.

The interest rate to be charged to DA customers for the financing of the cap shall be at the interest rate applicable to the DWR Bond Charge on an interim basis. We believe further inquiry is appropriate regarding longer term arrangements for the costs of financing of the DA caps. The ALJ shall take further comments on this issue.

In later years, bundled ratepayers will be reimbursed, with interest, on the funds they provided on an interim basis to cover a portion of the DA CRS. The reimbursements to bundled customers will be funded from surplus proceeds expected to be recovered from DA customers as the level of DA CRS declines over time.

As another measure to protect bundled customers, we shall require that any DA customer that returns to bundled service must still pay off their share of the unrecovered DA CRS charges resulting from the cap. We direct the ALJ to issue a procedural ruling on outstanding issues relating to the cap.

We adopt the 2.7 cents/kWh as a cap on the maximum level that may be charged under the DA CRS. Accordingly, those continuous DA customers that are excluded from paying ongoing DWR power charges will not be required to pay the full 2.7 cents/kWh to the extent their actual DA CRS obligation is less than the 2.7 cents cap.

We shall also adopt TURN's recommendation that any financing of the cap shall be retained with the same customer classes that benefit from the cap.