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 CRS charges, and the potential risk of making DA uneconomic for its program participants. These parties propose that the DA CRS be capped at a prescribed amount to limit the adverse economic effects on DA customers that would otherwise result from the rate increases that would be required to fully fund DA CRS, including the Bond Charges. The shortfall representing the difference between DA CRS costs and the revenues provided by DA participants would be someone else's responsibility, at least for a while. This proposal is a classic example of a cost shift that may violate the law, which prohibits unreasonable discrimination, and may contravene sound policy considerations.

A. Legal And Policy Considerations

In a recent order the Commission has expressed the view that the DA program has value for California, and that efforts should be undertaken to avoid making DA uneconomic for the customers who participate. While the Legislature suspended DA by enacting the provisions of Water Code 80110, it did not end DA nor did it repeal or modify the provisions of AB 1890 directing the Commission to "... take actions as needed to facilitate direct transactions between electricity suppliers and end use customers."⁹⁷ The cost shift issue posed by the DA CRS cap proposal is therefore not about ending or preserving direct access as a matter of philosophy. Rather it is about the use of subsidies to prop up DA under the conditions imposed on California by the Energy Crisis. We reject the proposal for caps at this time.

The Legislature and the Governor have made it very clear that cost shifting and subsidies are not permissible devices for use in propping up DA. In his message accompanying the veto of the major DA resumption proposal in the 2001 Legislative Session,⁹⁸ the Governor said:

I am returning Assembly Bill 9XX without my signature.

This bill would authorize end-use customers to aggregate their electric loads as individual consumers with private aggregators or as members of their local community with community choice aggregators.

Last June, approximately two percent of the customer load in the territory served by the three investor-owned utilities (IOUs) was receiving power from direct access providers. The Public Utilities Commission (PUC) recently suspended direct access, but the percentage of load subject to direct access transactions grew to as much as 13 percent or more prior to the suspension. That growth creates a significant and unfair cost burden for those customers who continue to receive power from the IOUs and the Department of Water Resources.

This rapid growth in direct access necessitates more concise cost-containment provisions for the remaining IOU customers than those contained in this bill, and those provisions should apply to all direct access contracts.

Moreover, this bill does not clearly authorize fees to cover costs that may result when direct access customers return to service with an IOU, which would create new and unanticipated procurement obligations for the IOU. Those new procurement obligations could come about solely because the direct access provider no longer chooses to provide service to its customers because of rising electricity costs, and instead passes that burden on to the IOU and its customers.

Any efforts to allow direct access must be equitable for all stakeholders.

The Legislature has similarly expressed its intent that all customers pay their fair share of energy costs, regardless of the identity of their supplier.⁹⁹

These policy considerations expressed by the Executive and Legislative branches militate against the use of a cap on the DA CRS to limit the ability of the utilities and the DWR to recover their costs. The legal barrier imposed by Public Utilities Code section 453, which prohibits granting unreasonable preferences to any customer or class of customer, is another obstacle for the proponents of a cap.¹⁰⁰ The cap proponents are explicitly contending for a rate preference in order to sustain a potentially unviable program of which they are the sole beneficiaries. Approval of the cap proposal potentially raises rates for non-participant customers, and implicates the credit of the utilities and the State of California. Again, we decline to approve a DA CRS cap at this time.

B. Arguments For And Against A Cap

The complexity of the cap determination on a record that is at best incomplete for this purpose is a further obstacle to approval of a cap on the DA CRS at this time. Before a DA CRS cap can be adopted, we must first address (1) what level of cap should be set, (2) under what conditions should the level of the cap be reevaluated, (3) what rate 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 ratepayer 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 ¢/kWh until the effective date of a Commission decision implementing a DA cost responsibility surcharge in the instant rulemaking (R.02-01-011). This reduction in the DA surcharge credit was intended to generate $391 million in revenues, thereby providing 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 CRS in this proceeding, bond charges in A.00-11-038 et al., "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. We noted that there was a risk of DA contracts becoming uneconomic, and 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)." But the Decision did not set a specific overall cap, "in deference to other proceedings." A recitation of the arguments and evidence in this proceeding suggests how complex determining the cap would be, and how rife with discrimination and preference the outcome.

CLECA and CMTA argue that a cap should be imposed on the maximum annual CRS that would be billed to DA customers. They claim 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.¹⁰¹ Both parties argue that this is inconsistent with the direction of the Commission.¹⁰² CLECA proposes caps of 2.0 ¢/kWh for PG&E and 2.25 ¢/kWh for Edison and 2.75 ¢/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, with the significant caveat that recovery would be "over time." The changes CLECA anticipates in these figures does not alter its conclusion, but its numbers only represent approximations. CLECA believes the Commission should utilize the actual figures in the ongoing DWR revenue requirement proceeding to develop utility-specific DWR exit fees for 2003, and combine them with the approved Bond Charges and the HPC, if one is applicable, under an overall cap. CMTA proposes a uniform cap of 2.0 ¢/kWh be adopted, along with balancing accounts to reconcile exit fee 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 direct access customers had fulfilled their HPC obligation and were current on their contribution to uneconomic DWR and URG costs. CMTA's recommendation in this regard is consistent with the Commission's recent decision concerning SCE's HPC.¹⁰³

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 (of approximately 2.5 ¢/kWh, though the actual rate varies by rate group) 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 rates 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.

But this avoids the issue of ongoing DWR costs and utility costs for which DA customers are responsible. The DA surcharge cap proposed for adoption in this proceeding would cover the surcharges considered in this proceeding; the ongoing CTC, the DWR Bond Charge, and the DWR power. When the Commission addresses PG&E's Historic Undercollection Charge (HUC), we must also consider how the DA surcharge cap relates to those charges.

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, however, arguing that DWR has no ability to issue additional bonds or to borrow additional monies to carry shortfalls in DA CRS obligations. DWR 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 ¢/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 NBC be deemed to be recovered first, then the DWR Bond Charges, leaving any shortfall attributable to the DWR NBC. 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.

Each third party - DWR, Edison and PG&E - is attempting to avoid the costs associated with fronting the money needed to cover the DA customers' costs. Each entity has strong arguments that they should not front and should not carry those costs; DWR because it has no legal authority, SCE because it has no financial capability. There is no basis for requiring them to subsidize the DA customers.

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.¹⁰⁴

PG&E proposes that DWR issue bonds to finance that shortfall. It is within DWR's authorized purpose for issuing bonds. Further, the $11.9 billion total bond issuance contemplated by DWR,¹⁰⁵ which does not take the effects of a cap into account, is well below the statutory limit of $13.4 billion set on DWR's total bond issuance.¹⁰⁶ This approach would require the active participation of DWR in developing the bond issuance to finance the cap. PG&E notes that DWR understands the concept, and did not raise immediate objections.¹⁰⁷

With DWR funding the shortfall, customers would then be able to take advantage of the interest rate at which DWR can issue bonds. According to PG&E, under this approach, bundled customers provide the same amount each year as they would to DWR if there were no cap. 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 ¢/kWh 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 DWR Bond Servicing and/or Rate Agreement(s). To the extent that this occurs, and results in the aggregate sum of the rate components exceeding the 2.7 ¢/kWh cap, such a cap would result in an under-recovery of one or more SDG&E rate components under the cap.¹⁰⁸

SDG&E states that an 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 DWR Bond 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, DA customers should reimburse bundled customers for that shortfall with interest calculated at the 90-day commercial paper rate. 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.

These arguments establish that third-party financing of costs - by utilities or by DWR - are not viable options. TURN and ORA raise the further concern as to how capping the DA CRS could adversely affect bundled ratepayers who could potentially be burdened with shouldering the financing costs of excessive deferrals of DA cost responsibility as well as fronting payment of ongoing DWR costs. In effect, their argument is that creating a preference for DA customers comes at a price for the non-participant customers, without any offsetting system benefits. There is no basis for capping the DA CRS at this time.

TURN and ORA argue that the Commission must address the risk a cap places upon bundled ratepayers. Financing any revenue undercollection produced by a cap must come from somewhere. (PG&E cross-examination, Tr. 1, pp. 15-120, McDonald/DWR.) Bundled ratepayers will pay the financing costs by default if another group or entity does not. (RT. 3, pp. 299-302, Marcus/TURN.) The financing will occur at the short-term balancing account rate, which TURN has calculated to be about 7%. (Ex. 18) Depending on the initial level of the cap and the resulting shortfall in revenues, this could result in a significant rate increase for remaining bundled service customers given the magnitude of the DA customer load.

A further consideration militating against imposing a cap is that a revenue shortfall will affect all of the Commission's initiatives to restore utility credit and support the DWR bonds. Funds remitted under the cap would be first applied to pay the bond charge, and secondly, to pay the 2003 DWR power charge. These sources would have first claim on the funds because DWR is entitled to timely reimbursement for both its bond charge and power charge. To the extent that DA customers do not pay for their share of these charges, they will have to be covered by bundled customers, and such a result would not promote bundled ratepayer indifference. 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. Moreover, the 2003 DWR revenue requirement has already been submitted to the Commission in A.00-11-038 for implementation, and no source of financing has been built into that revenue requirement to accommodate the financing of a cap.

This disposition of funds would place utility cost recovery in jeopardy, and in turn undermines the ability of the Commission to effectuate the transition from DWR to utility energy procurement, which must happen by January 1, 2003.¹⁰⁹

C. Issues For Further Consideration In Establishing A DA CRS Cap

We have rejected a cap at this time. However, there are several issues that might usefully be explored for use in a cap determination in the future, after the actual DA CRS has been developed and we have empirical evidence about its affect on DA customers. One consideration in setting a cap is to limit the charges imposed on DA to avoid making DA uneconomic. Yet, the evidence presented on this issue was limited to subjective judgment and anecdotal accounts of discussions with industry representatives. Based on this limited evidence, we find little basis to quantify the relationship between the level of a cap and the number of DA contracts that may become uneconomic. In the absence of good empirical evidence concerning the 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 CRS above the cap. We conclude that in order to preserve bundled ratepayer 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 affects 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 CRS is initially established. If DA contracts become economically non-viable in fact, the risk is that those DA customers will exit the DA program. Because the level of the CRS is projected to be lower in the latter years of the DWR contracts, there might be more flexibility to develop a cap in the future as compared with today when costs are comparatively high and the risks of cost shifting are great. That circumstance may change.

Once the actual level of the DA charge is established and we have concrete empirical evidence of its impact on DA customers, the issue of a cap may become more amenable to resolution. In D.02-07-032, the Commission has stated that a cap of 2.7 ¢/kWh may be a reasonable cap. Thus, the DA community is already aware of this preliminary figure as at least a potential starting point for a cap.

Parties failed to present any convincing evidence that this preliminary assessment is at an appropriate level. Parties proposing caps as high as 4 ¢/kWh did not provide convincing evidence that a cap at this level could resolve the policy dilemma of avoiding subsidies while avoiding making DA uneconomic. Although certain comparisons were made with bundled rates to argue that a 4 ¢/kWh cap would still be less than bundled rates, and that a rate increase of that magnitude would be less than the rate increase that bundled service customers sustained in July 2001, we cannot find such a comparison to constitute proof that DA contracts could survive such a rate increase.

The other reason cited for the 4 ¢/kWh 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.

On the other hand, a 2 ¢/kWh cap, as proposed by CLECA and CMTA, is clearly too low to cover the requisite components of CRS without triggering unduly large deferred balances. The cap must be high enough to recover the Bond Charge, the Power Charge and SCE's HPC. SCE's ability to regain creditworthy status, and resume procuring electricity to fulfill its net short, is directly linked to its ability to recover the PROACT balance. Therefore, it is important that the HPC is recovered from all DA customers in a timely manner. Pursuant to D.02-07-032, the Commission has adopted a 1 ¢/kWh HPC for SCE as part of the exit fees to be collected under the cap after a decision in this proceeding is issued.

To the extent that funds provided by DA customers under the 2.7 ¢/kWh are not sufficient to cover both the bond charge and to pay for DA customers' share of the 2003 DWR power charge, any shortfall would have to be remitted to DWR from bundled customers' funds. To the extent that any bundled customers' funds are used to remit any portion of the DA share of 2003 DWR power costs, an interest charge would have to be assessed on DA customers to reimburse bundled customers for the use of their money. The interest charges due to bundled customers for the advance of such funds would be deducted from the gross proceeds from the DA CRS paid under the 2.7 ¢/kWh cap, and credited against the bundled customers pay to DWR. To the extent that after payment of the DWR-related obligations, there were insufficient funds remaining to pay the utilities for above-market URG-related costs, the utilities would have to arrange financing for that amount. It would be an unprecedented and untenable imposition on the credit of the utilities to require them to finance a rate reduction for DA customers.

An initial cap set at the level of 2.7 ¢/kWh might represent an appropriately cautious starting point for a cap, particularly at the very beginning of instituting these charges. It would not impose any abrupt change from the level the Commission has previously referenced as possibly being a reasonable cap value. A cap at this level would promote a bridge on continuity with the preliminary assessment on this issue that the Commission made in D.02-07-032. Once the actual DA CRS is established and we have empirical evidence, as distinguished from hypothetical scenarios, about the impact on DA customers and their ability and willingness to sustain DA relationships, we can revisit the issue and determine whether a cap at the 2.7 to 3.0 ¢/kWh level affects the balance between preserving the viability of the DA program and avoiding subsidies and preferences. We reserve the option to develop a cap prospectively if we determine that such a cap will protect bundled ratepayers against the risk of excessive undercollections imposed by any cap level.

Consideration should be given to alternatives such as having DA customers provide some form of security or collateral to support the repayment of debt generated by the caps. The goal of such collateralized security will be to provide protection against bundled ratepayers bearing potential risk for nonpayment by DA customers, and to attract sources of financing for the debt under favorable arrangements.

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

453. (a) No public utility shall, as to rates, charges, service, facilities, or in any other respect, make or grant any preference or advantage to any corporation or person or subject any corporation or person to any prejudice or disadvantage.

...

(c) No public utility shall establish or maintain any unreasonable difference as to rates, charges, service, facilities, or in any other respect, either as between localities or as between classes of service.