Parties requested time at the first day of evidentiary hearings to hold an informal workshop to address various tariff issues which they felt could lead to certain stipulations. In addition, several tariff issues were resolved at workshops convened by the Energy Division, and where issues were not resolved, substantial progress was made in narrowing the focus of the contentious issues. These tariff workshops are very valuable in our efforts to implement the complex world of electric restructuring. We congratulate the Energy Division and the participants on their successful resolution of issues and will hold other such workshops in the near future. Such settings are preferable to protracted hearings and more effective at allowing parties to discuss and resolve differences. We adopt the stipulations and consensus recommendations supported by all parties. We expand the application of certain recommendations so that additional information is provided to consumers, as we discuss below. As we move forward in implementing the new competitive generation framework, it is crucial that consumers have easily accessible and understandable information available to them, so that each customer can make informed choices.
As discussed above, primarily because of the rate freeze, CTC will be determined on a residual basis. This is true for bundled customers, direct access customers, and departing customers. This concept will be more fully developed in the unbundling proceedings. Therefore, parties have agreed that 2.4 cents per kilowatt hour should be used to approximate the market clearing price for the limited purpose of developing an estimate of the total transition cost level which is applicable for 1998. This number may be important for developing the rate reduction bond applications, which are also addressed in AB 1890.
The major issues regarding the terms and conditions of exemptions and departing load were either agreed to at the informal workshop or in Energy Division workshops. Parties generally agree that a uniform approach is preferable for all three utilities. Several issues were stipulated to at hearings and more detailed agreements were discussed at the workshops, including the following agreements: 1) to the extent possible, the billed CTC will be based on metered consumption, and 2) one of the options for determining the load of departing customers may include reliance upon third-party metering, so long as a verification of that meter reading is provided, and that each party shall bear its own costs for any verification process of those meter readings.
Section 369 provides that the CTC is applicable to all existing and future customers. Within this broad applicability for CTC there are three general categories of customers: 1) continuing utility full service customers; 2) customers that continue utility delivery services but obtain all or part of their energy from a provider other than the jurisdictional utility (direct access customer); and 3) customers that obtain all or part of their energy and delivery services from a provider other than the jurisdictional utility (departing load customer). PG&E, Edison, and SDG&E have indicated that tariffs identifying the CTC calculation for full service customers and direct access customers would be filed in the unbundling and direct access proceedings.
Parties reached agreement on a departing load customer’s ability to provide information from third-party metering to the utility as a basis for adjustments to CTC payment calculations. Participants discussed this stipulation and reached further agreement on metering and rate basis (i.e., the rate schedule to be used to calculate the CTC for departing customers) issues and how tariff language should reflect these agreements. First, parties discussed the various utility-proposed defaults for applying billing determinants to calculate a customer’s CTC; for example, whether to use an historical average or current metered data. SDG&E endorses using current metering information when available. PG&E prefers to use historical over current information, and Edison prefers current information but would settle for using historical metering information. In the workshop, all parties agreed that it would be inappropriate for a utility to require current metered information and that the optimal approach is to let the customer select the billing determinant. We agree with participants and will approve the updated modifications to utility tariffs which reflect this understanding (included as Attachments 7 and 8 to the Energy Division’s workshop report).
Participants also agreed that customers could change the rate basis used in their CTC calculation by providing current metered information to demonstrate that, if they were still taking utility service, they would be under a different rate schedule. We agree that this is reasonable. Although customers are under a rate freeze, they are not prohibited from moving from one frozen rate schedule to another. Since this option is available to full service customers, it should also be available to direct access and departing load customers. We therefore direct the utilities to include this option in direct access tariffs and full service tariffs, to the extent necessary, with the understanding that this particular language may be subject to adjustment based on findings in the direct access and unbundling proceedings.
Another metering issue discussed in the workshop was specific tariff language indicating that metering would be used for these purposes only if it was reliable. Non-utility parties believed the utilities’ proposed language relinquished the determination of reliability to the utilities. Participants agreed on language indicating that metering would be deemed reliable pursuant to standards in tariff Rule 17 (for PG&E and Edison; Rule 18 for SDG&E), or other standards that we might eventually adopt. For now, we find that it is reasonable to determine metering reliability for CTC purposes based on Rule 17 standards for PG&E and Edison and on Rule 18 standards for SDG&E. However, we note that there is some confusion regarding whether this standard would be the same for direct access and full service customers. In PG&E’s revised tariffs this language is included only in the section addressing CTC for departing load customers. In contrast, Edison’s tariffs include this language in the section of the tariffs applicable to all customers. To the extent that a customer could receive a CTC-related benefit by utilizing third-party metering, it is equitable to provide the same metering options all customers. Therefore we agree with Edison’s inclusion of this language in the section of tariffs applicable to all customers. PG&E and SDG&E shall incorporate this provision in their tariffs, again, with the understanding that this particular language may be subject to adjustment based on findings in the direct access and unbundling proceedings, such as, the establishment of specific metering standards.
As discussed above, § 369 provides that CTC is applicable to all existing and future customers. While the tariffs filed in this docket have focused on departing load customers, each utility took a different approach to the design of these tariffs. PG&E and Edison filed the most detailed departing load tariffs. For example, Edison’s tariff begins with a statement of the purpose of the CTC and then of the broad applicability of CTC. Following this is a section regarding CTC calculation, which provides the methodology for calculating the CTC for various kinds of customers, including those customers provided particular terms or treatment by assorted code sections. This section is where Edison details exemptions. Following this is a section detailing the CTC terms and conditions specific to departing load customers. This includes language regarding the obligation to provide notice, sign an agreement to pay CTC, and be subject to potential penalties and associated curative measures unique to CTC for departing load customers.
PG&E used a different approach which can best be understood by comparison with the Edison approach. PG&E’s entire tariff applies only to departing load customers. Because the PG&E tariff does not contain a section of generalized CTC language useful for all customers, PG&E would presumably have to repeat much of the language in its departing load tariffs in tariffs for direct access and full service customers. One other notable difference between the PG&E and Edison tariffs is that Edison’s language regarding special treatment of particular customers (as may be required by various code sections) is more detailed and provides important explanations of the PU Code. In contrast, the PG&E tariffs summarize the PU Code exemptions in two or three sentences and cite the PU Code. Presumably, a customer needing more information would be required to seek more detail in the PU Code.
SDG&E provided representative tariffs that it proposed to add to its tariffs for each rate schedule. These provide a description of CTC and a summary of exemptions that is more detailed than that provided by PG&E and less detailed than that provided by Edison. SDG&E’s lack of notice provisions, penalties and curative measures and other language specific to departing load customers reflects SDG&E’s proposal that unique terms are not necessary for departing load customers because it contends that existing tariff provisions for nonpayment of bills are adequate.
A primary consideration in evaluating tariff format issues is determining which format is likely to enhance the usefulness of the tariffs for customers. Customers cannot generally dedicate extensive time and effort to evaluating tariffs, so it is reasonable to attempt to ensure that the tariffs are as customer-friendly as possible. This is likely to be particularly important in the future, as competitive options become a reality and as customers take a greater interest in comparing service options. Tariffs should be designed so that the customer can easily understand the costs and implications of choosing various available service options. Another benefit of having all CTC tariffs in one place is that it eliminates the need for extensive cross-referencing to understand the implications of choosing various service options. [ Design of CTC tariffs will be an important consideration in this customer analysis. For example, a customer considering an alternative energy provider is likely to know its current energy rate is because this is provided in the bill. The customer would also presumably have an idea of the cost of energy from an alternative provider because this knowledge is likely to be what causes the customer to consider the alternative provider. What the customer needs to understand is the way its CTC charge and associated terms might change if it utilized the alternative energy provider. ] Providing CTC tariffs for full service, direct access, and departing load customers in the same area of the tariffs will help the customer assess the way its CTC calculation and terms might change under the various service alternatives. It is prudent to put this language and all generalized CTC language in a general tariff section applying to CTC for all customers, followed by more specific language delineating particular requirements for full service customers, departing load customers, and direct access customers. Edison’s tariffs are a useful model and begin with language necessary for all customers.
Therefore, we direct PG&E and SDG&E to revise their terms and conditions tariffs according to Edison’s model and the requirements outlined in this decision.; i.e., the tariff formats should include all generalized CTC tariff language in one CTC tariff having broad applicability and be followed with the tariffs specific to departing load customers, utility service and direct access customers. [ We understand that utilities planned to file CTC tariffs for utility service and direct access customers in the unbundling and direct access proceedings. These tariffs should also be filed in this docket.] PG&E and SDG&E should also reflect the language in Edison’s tariff section titled "CTC calculation." To the extent that PG&E and SDG&E must modify Edison’s language to reflect utility-specific exemptions or modifications, such modifications should reflect the detail and approach used by Edison. We also note that Edison’s definition of departing load is not included in the departing load tariffs, but in its Rule 1 definitions. In addition to adhering to the General Order 96-A requirements, PG&E, Edison, and SDG&E should also provide this definition at the beginning of its departing load section. In revising or developing tariffs as ordered here, utilities should abide by the following principles: 1) Utilities should work together to achieve the highest degree of uniformity practicable; 2) When tariff language is based on a utility proposal that has yet to be approved in the direct access or unbundling proceedings, the tariffs should reflect the utility proposals and this should be clearly stated. The full service and direct access CTC tariffs may require later modification to reflect decisions adopted in other proceedings. These modifications may be handled by augmented advice letter procedures, as we discuss below, or be addressed in a workshop. Additional guidance will be provided by ruling.
PU Code §§ 372 - 374 address exemptions from transition cost recovery for specific customers, customers’ end-uses, or customer classes.
Some parties believed that two types of exemptions were not adequately addressed in the pro-forma tariffs. On December 3, 1996, parties reached a stipulation regarding utility reflection of the PU Code § 372 exemption for onsite and over-the-fence generation committed to after December 20, 1995. During the terms and conditions workshop process, utilities updated their tariffs with language that acceptably reflects these exemptions. Essentially, this language better clarifies that: 1) the §372 (c)(1) exemption provided for self-generation units is for units whose construction had not commenced before December 20, 1995, as opposed to units whose construction had begun before this date, for which other exemptions apply, and 2) the exemption provided in § 372 (c)(2) applies only to over-the-fence arrangements between unaffiliated parties, rather than affiliated parties, for whom exemptions are provided in § 372 (a)(1). [ Section 372( c) provides, in relevant part, that "[t]he Commission shall authorize, within 60 days of the receipt of a joint application from the service utility and one or more interested parties, applicability conditions as follows: "(1) the costs identified in Sections 367, 368, 375, and 376 shall not, prior to June 30, 2000, apply to load served onsite by a nonmobile self-generation or cogeneration facility that became operational on or after December 20, 1995. "(2) The costs identified in Sections 367, 368, 375, and 376 shall not, prior to June 30, 2000, apply to load served under over the fence arrangements entered into after December 20, 1995, between unaffiliated entities." ] We agree with these recommendations and clarifications to the tariffs, because they are consistent with the law.
Section 330(v) establishes a fire wall as follows:
"Charges associated with the transition should be collected over a specific period of time on a nonbypassable basis and in a manner that does not result in an increase in rates to customers of electrical corporations. In order to insulate the policy of nonbypassability against incursions, if exemptions from the competition transition charge are granted, a fire wall shall be created that segregates recovery of the cost of exemptions as follows:
"(1) The cost of the competition transition charge exemptions granted to members of the combined class of residential and small commercial customers shall be recovered only from those customers.
"(2) The cost of the competition transition charge exemptions granted to members of the combined class of customers other than residential and small commercial customers shall be recovered only from those customers. The commission shall retain existing cost allocation authority provided that the fire wall and rate freeze principles are not violated."
(See also PU Code § 367 (e)(1).)
Therefore, the exemptions delineated above necessitate the establishment of the fire wall to ensure that no cost-shifting occurs and may lead to a 3-month extension of the collection period for the recovery of certain, specific exempted costs from the appropriate side of the fire wall. The fire wall is thus established to address revenue shortfalls due to exemptions. [ Pursuant to § 374(b), the fire wall does not apply to BART exemptions. CTC costs due to exemptions for BART will be paid for by all remaining PG&E customers.]
Section 367(a)(5) provides that to the extent that CTC-eligible costs are not recovered prior to December 31, 2001, due to revenue loss from irrigation district exemptions only, the utilities are allowed to extend its collection period (and therefore, the rate freeze period) to March 31, 2002, provided that, subject to the fire wall restrictions, only $50 million of this category of costs are eligible for recovery.
Therefore, the CTC amounts that would otherwise have been paid by exempt customers must be tracked according to the type of exemption and by class (i.e., large vs. small in compliance with the fire wall). The memorandum accounts and methodology that have been proposed by PG&E and Edison in Exhibits 7 and 10, respectively, are acceptable for tracking these exemptions. SDG&E should include similar language in its tariffs to implement this requirement.
In its Phase 1A opening brief, MID disputes PG&E’s intention to collect a payment for public benefits programs from departing customers who begin taking exempted load from an irrigation district. MID believes that if PG&E is allowed to implement this practice, those customers will be paying twice for the same public benefits programs. Because the allocation and collection of nuclear decommissioning charges and public purpose benefits charges are not being considered in this proceeding, MID should raise this issue in the unbundling and ratesetting proceeding, as directed by ALJ ruling issued on January 31, 1997.
PG&E states that imputed post-2001 lump-sum amounts must be determined by December 31, 2001 for exempt non-irrigation district loads during the period from January 1, 2002 to March 31, 2002. PG&E further states that irrigation district customers will retain responsibility for making their own post-2001 CTC payments.
MID believes that a plain reading of § 374 and the sunset provision stated in § 374(a)(4) is that after March 31, 2002, a departing customer would not be exempted from transition costs; i.e., if MID has not utilized its 75 MW of load for which the exemption was provided by the sunset date, any remaining portion is no longer available as exempt load.
PG&E, on the other hand, states that the statutory language means that the exemptions of costs identified in §§ 367, 368, 375, and 376 expires as of March 31, 2002. Therefore, any irrigation district customers are no longer exempt from transition costs and must begin making their own payments for transition costs remaining to be collected after March 31, 2002. This will include employee-related transition costs (§ 375), restructuring implementation costs to the extent not recovered from any other source (§ 376), and transition costs related to power purchase agreements, which extend over the life of the contract.
We agree with PG&E. A plain reading of the statutory language does not indicate that any of the 75 MW are no longer available as exemptions, but that, in fact, these customers are no longer exempt from any transition costs accruing in the period after March 31, 2002. While PG&E has referenced Merced’s position with a discussion of the understanding of the parties during the drafting of AB 1890, such a discussion is irrelevant for these purposes. Again, we reiterate that at this point, the intentions and understanding of the parties in drafting the legislation does not matter; it is the language of the statute that is relevant. Furthermore, MID is incorrect in assuming that PG&E may seek to recover the $50 million from exempt customers; rather, the utilities may recover a maximum of $50 million in exempt costs from all other large customers during the January 1, 2002 through March 31, 2002 time period, a period during which the irrigation district customers are still exempt from these costs.
MID is also concerned regarding PG&E’s tariff language that provides that the utility will make the initial determination of eligibility for exempt status. MID states that PG&E’s requirements raise unnecessary hurdles to competition by requiring the customer to provide notice to PG&E of its intent to claim exempt status and by imposing the responsibility on the customer to file a motion for the evaluation of departing load CTC statement with the Commission, if the customer disagrees with PG&E’s assessment. MID recommends that because PG&E has an economic interest in finding no exemption, the utility should be required to challenge a claim of exemption by filing a motion with the Commission, and that the irrigation district supplier should be entitled to respond on behalf of the challenged customer.
PG&E states that the notification procedure is necessary, so that only those customers that are so entitled receive exemptions and so that adequate records can be kept for fire wall accounting purposes. PG&E’s proposed tariffs require that within 20 days after receipt of a departing load CTC statement, a departing load customer may file a "Motion for Evaluation of Departing Load CTC Statement" at the Commission in R.94-04-031/I.94-04-032.
Conceptually, we agree with PG&E. However, as we found in D.96-11-041, PG&E’s proposed process is cumbersome. We will adopt the same procedures for PG&E, Edison, and SDG&E which we found reasonable for PG&E in D.96-11-041. If a departing customer believes that the departing load statement does not comply with the terms and conditions of the tariffs and related decisions, it should notify the relevant utility in writing of the grounds for its belief within 20 days after receiving the departing load statement. If the utility does not accept the customer’s position, it should respond in writing within 5 days after receiving the customer’s notification. The utility and the customer should then confer to attempt to resolve the differences. If necessary, the parties may also consult with Energy Division staff to attempt to achieve resolution. If no resolution is reached within 10 days, the customer may then file the motion described in the proposed tariffs. The utility and the customer may agree to extend this 10-day period to allow for further negotiations or other resolution techniques. PG&E, Edison, and SDG&E should amend their tariffs to reflect these provisions.
An area of transition cost tariff proposals that resulted in extended dialogue among workshop participants was provisions for penalties applied to departing customers for failure to provide notice and failure to pay CTC. For the most part, Edison derived its departing load tariffs from the PG&E tariffs, so their initial tariff proposals were similar. SDG&E disagreed with using unique penalties for transition costs for departing load customers. SDG&E prefers to rely on the penalty mechanisms already included in its tariffs for transition cost penalties.
We disagree. First, transition costs for departing load are distinguishable from other utility charges in that the utility has limited or no ability to threaten termination of service if the customer fails to meet its obligations. It is reasonable to develop unique penalty procedures to ensure that departing load customers cannot bypass transition costs and increase the transition cost burden on full service and direct access customers. Second, departing load transition cost charges are of a much greater magnitude than would customarily be associated with a few months of missed bills. It is reasonable to develop special procedures that allow the customer enhanced opportunities to cure the problem. For these reasons, we will order SDG&E to mirror the PG&E and Edison tariffs regarding the departing load transition cost penalties, modified as discussed below.
Participants also discussed whether there is any reason to utilize a different penalty procedure for customers who fail to provide notice of departure as opposed to customers who fail to make CTC payments. Workshop participants agreed that different penalty procedures are appropriate and that the Edison and PG&E proposals for penalties for failure to provide notice are adequate. We approve this consensus agreement, authorize PG&E and Edison to implement the departing load penalty for failure to provide notice of departure as presented in Attachments 7 and 8 of the Energy Division workshop report issued on January 24, and also order SDG&E to draft tariffs to include the departing load penalty for failure to provide notice of departure.
PG&E and Edison proposed a penalty for departing load customers who do not pay CTC which involved issuing a notice to cure if payment is not received by the end of the payment grace period. If the customer does not remit the missed payment within 20 days of the notice to cure, PG&E and Edison would immediately pursue the lump-sum payment described below. At the beginning of evidentiary hearings, ORA indicated that it disagreed with these utility procedures but would set them aside for discussion in the transition cost terms and conditions workshop. During the workshop, ORA introduced a proposal that would add another stage between a customer’s failure to comply with the notice to cure and the utility’s pursuit of the lump-sum payment.
In this so-called two stage approach the utility would respond to the customer’s failure to satisfy the notice to cure by issuing a notice to provide payment and deposit. The customer would have the opportunity to respond to this notice by becoming current on its missed CTC payments and providing a deposit in the amount of two times the missed payments (i.e., four monthly CTC payments within 30 days of the notice to provide payment and deposit. If the customer provided this payment and deposit to the utility, the matter would be resolved. If the customer failed to provide this payment and deposit by the end of the 30-day grace period, the utility would then pursue the lump-sum payment. The net effect of the ORA proposal is that the customer that fails to meet the original notice to cure is provided a second remedy at a cost much lower than the cost of the final lump-sum payment. This two-stage approach also allows the customer an additional 30 days before facing utility pursuit of the lump-sum penalty.
Workshop participants agreed that the two-stage approach is preferable to the original utility proposals. We agree, the most persuasive reason being that it provides an additional cushion for human error. Departing load customers may include large industrial customers, but may also include residential and small commercial customers who opt out of the utility’s delivery system. Customers who forget to make a CTC payment or fail to arrange payment of bills during an extended vacation or sick leave should be provided a more relaxed initial penalty before the utility pursues a penalty as dramatic as the lump-sum payment. Therefore, PG&E, Edison, and SDG&E shall revise their tariffs to reflect this modified penalty process, with modifications to the lump-sum payment as detailed below. [ We note that a uniform grace period is required for purposes of this penalty only and clarify that this change in grace period will not apply to any other aspect of the utilities’ tariffs.] We order SDG&E and Edison to implement the extended grace periods for purposes of the departing load transition cost penalty for failure to pay CTC. (See Energy Division’s Workshop Report, Table 1.)
Certain details must be resolved in order to implement the two-stage penalty. First, we recognize that the utilities might have differences in the way they treat customer deposits, pursuant to Rule 7 of their existing tariffs. An example is that PG&E’s computation of interest on deposits differs from that of SDG&E and Edison in the frequency of the compounding. In general, these differences have no substantive policy implications, and the utilities should therefore implement this penalty with the understanding that they will treat the deposit with the same rules already established by existing Rule 7.
Second, one understanding reached during the workshop was that the two-stage penalty procedure would be available to the customer only for the first instance in which the customer fails to pay CTC without response to the notice to cure. We agree that this is a reasonable approach. Upon being reminded of the importance of meeting the CTC obligation during the first invocation of the two-stage penalty, the customer should gain an understanding of the need to stay current on its transition cost obligations.
Finally, the workshop report reflects an agreement among participants that, having collected a deposit once using the two-stage penalty, the utility could apply deposit amounts toward CTC payments in the event the customer again fails to meet CTC payments. However, we find that this agreement violates Rule 7 provisions for the appropriate use of deposits. We therefore clarify that the utility cannot draw on a customer’s deposit to meet missed CTC payments, with the following exceptions. Edison’s Rule 7 allows for the application of deposits to the customer’s closing bills at the time the customer discontinues taking service from the utility. A parallel interpretation should be allowed for Edison so that deposits may be applied to outstanding departing load transition costs at the end of the transition period. To the extent that PG&E’s and SDG&E’s Rule 7 tariffs allow for such application of deposits to closing bills, PG&E and SDG&E should also allow for application of deposits to outstanding Departing Load CTC at the end of the transition period.
The utilities have proposed a lump-sum payment to be applied in the case of penalties and which is also to be collected on March 31, 2002, in lieu of the monthly obligation. We discuss the penalty provision first.
The Farm Bureau has expressed concerns that the lump-sum payment associated with the departing load penalties for failure to provide notice or pay CTC is unnecessarily large, and is linked to a customer’s total bill rather than only the uneconomic portion of the bill. Therefore, the Farm Bureau believes that linking the lump-sum payment to these additional amounts (i.e., the entire bill) unfairly penalizes the departing customer. We use this opportunity to address concerns not only that calculation of the lump sum may be inequitable, but that the lump-sum payment requirement could be anticompetitive.
Used as a penalty, we do not believe that the lump-sum payment is anticompetitive. We note that a departing load customer has ample opportunity to avoid the lump-sum penalty by providing notice to the utility and meeting its monthly transition cost obligations. In addition, we have now required that the tariffs provide a reasonable opportunity to correct the situation to avoid the lump-sum penalty. Therefore, we do not believe that it is reasonable to incorporate the lump-sum penalty into any decisions to utilize alternatives to utility distribution and energy services. This would be analogous to basing a cost-effectiveness analysis on the assumption that the customer would fail to meet simple obligations such as paying its bills. In general, we find this to be an unreasonable assertion. Customers that choose to utilize alternative energy and distribution services are likely to be aware of what their obligations would be if they pursue these alternatives, including their obligations to provide notice and meet monthly transition cost obligations. [ Our requirement that each utility provide clear and precise tariffs for all customers will help to ensure that customers understand these obligations. ] Therefore, we conclude that, used as a last resort, the lump-sum payment is unlikely to be anticompetitive.
However, we agree that there is an equity issue associated with the lump-sum payment. If the lump sum represents an amount greater than the customer’s actual net present value transition cost obligation at the time that the penalty is levied, that customer pays more than its fair share of transition cost obligation. If the lump sum is an amount less than the customer’s net present value transition cost obligation at the time the penalty is levied, the customer would pay less than its fair share of transition costs, leaving other customers to pay the remainder. The optimal outcome is for the lump-sum penalty to reflect the best estimate of its remaining transition cost obligation when the penalty is levied. [ We also note that if the lump-sum payment were lower than the customer’s net present value transition cost obligation , then it would provide an incentive to pursue alternative generation, and take actions to incur the lump-sum penalty. Conversely, if the lump-sum payment were higher than the customer’s net present value transition cost obligation, a customer that believes it cannot adequately provide notice of departure or meet CTC payments would, in fact, have a disincentive to pursue alternative generation. However, if the lump-sum payment accurately reflected the customers net present value transition cost obligation, then the lump sum is competitively neutral.] If this outcome can be achieved, it also serves as a response to mitigate the Farm Bureau’s concerns about the lump sum being based on the customer’s total bill rather than only the uneconomic portion of the bill.
PG&E’s derivation of the lump-sum charge to be applied to customers that miss CTC payments appears to be consistent with this optimal outcome. PG&E states that the proposed lump-sum payment ". . . is neither a ‘penalty’ nor is it meant to be unnecessarily punitive, but rather is intended to provide a reasonable ‘amount certain’ for the customer’s total CTC responsibility . . . ." (Exhibit 6, p. 6.) Although PG&E also states that the lump sum represents an "upper range" estimate, the approach provides a good starting point for developing an optimal lump-sum amount. Two modifications to PG&E’s original lump-sum proposals are necessary for the lump sum to effectively represent a best estimate of the customer’s remaining transition cost obligation.
First, the lump sum must account for transition cost amounts already paid by the customer. To make the customer pay the full original lump sum even if that customer had met monthly transition cost obligations as a full service or direct access customer would be a double collection of some of that customer’s transition cost obligation. In fact, the lump sum originally proposed by PG&E for customers that failed to pay CTC attempted to account for cumulative payments received. This lump-sum penalty is scaled to the number of months remaining in the transition period. PG&E indicates that the scaling formula is "reasonably representative of the upper range of current estimates for the company’s outstanding total unamortized CTC requirements . . . ." (Exhibit 6, p. 14.) Although this is somewhat different from scaling an individual customer’s lump-sum penalty to reflect that customer’s actual CTC contributions to date, such a customer-specific penalty may be infeasible. PG&E’s approach is a reasonable approximation.
In contrast to its proposed penalty for failure to pay CTC, PG&E’s original lump-sum proposal for the penalty for failure to provide notice was not scaled to reflect cumulative transition cost collections, but was fixed at two times the customer’s reference period bill. As proposed, this penalty could result in a double counting of CTC by failing to reflect a customers’ CTC payments made before departure from utility distribution services. ORA raised this point in its testimony, and PG&E agreed in its rebuttal that the lump-sum penalty for failure to provide notice should also be scaled in a fashion identical to the penalty for failure to pay CTC. The most recent versions of the PG&E tariffs reflect these changes.
The most recent version of the Edison tariffs regarding both penalties for failure to provide notice and failure to pay CTC also use a lump-sum penalty calculation that would to some extent reflect that customer’s CTC payments made before enforcement of the lump-sum penalty. Edison used a different approach for calculation of the lump-sum payment. In Edison’s proposal, if the lump-sum penalty must be assessed on the customer, the lump-sum payment would equal that customer’s monthly CTC payment amount multiplied by the number of months remaining in the transition period. This approach seems more straightforward on initial evaluation, because it is based on actual monthly CTC payments. However, under the rate freeze, the customer’s monthly CTC payments are not based on any estimate of that customer’s CTC obligation, but rather on the residual of the frozen rate less all other charges. Therefore, actual monthly CTC payments might fluctuate greatly, and would certainly have no direct bearing on or reflection of the customer’s total transition cost obligation. For this reason, we will order Edison to change its lump-sum penalty calculation to one similar to PG&E’s. We also order SDG&E to incorporate these provisions in its tariffs.
Second, the lump-sum amount must be trued-up to reflect changes to the utility transition cost requests that will be addressed in Phase 2 of this proceeding. The utilities’ estimates of the customer’s full transition cost obligation used to develop the lump-sum payments are obviously based on each utility’s request for transition costs in this proceeding. The lump-sum payments should be scaled up or down proportionately to reflect our decisions in these proceedings and the Diablo Canyon proceeding, A.96-03-054, as well as D.96-12-083 regarding Palo Verde Nuclear Generating Station.
We realize that this process involves a certain amount of forecasting. Although this is a prospect we have sought to avoid when possible, it appears the only reasonable means of achieving our goal of making the lump-sum payment reflect departing load customer’s total net present value transition cost obligation. We also note that participants to the workshop have implicitly accepted use of these forecasts by agreeing for the most part with the use of a lump-sum payment in penalty mechanisms for departing load. In any case, the number of customers to which these kinds of penalties would apply is small, which means that the magnitude of potential forecast risk will be small in the aggregate.
Therefore, after issuance of the Phase 2 decision, the utilities shall file revised terms and conditions tariffs for departing load that reflect these changes in transition cost forecasts and includes the most recently adopted updates of costs. In the meantime, the utilities and other parties should consider a method that can be used to scale the lump-sum penalty calculation mechanism when the Phase 2 decision is issued. PG&E stated that the estimate behind the lump-sum payment represents an upper range for the customer’s transition cost obligation. Among other things, parties might work together to reach agreement on whether the lump-sum payment should be scaled to represent an upper-, mid-, or low-range estimate. Parties may also work to reach agreement on a stipulated long-term price forecast, the use of which would be strictly limited to scaling of the lump-sum payment. This may be an appropriate subject to discuss in workshops to be held later this year. Further guidance will be provided by ruling at a later date.
Departing load tariffs originally filed by PG&E and Edison required departing load customers to make a final lump-sum CTC payment on March 31, 2002 or at some other time as determined by the Commission. This lump-sum payment would not be pursued as a penalty for failing to provide notice of departure or failure to pay CTC, but instead would be required of all departing load customers. Non-utility parties disagreed with this proposal, stating that the final lump-sum payment could be large and impose a hardship on departing load customers. Workshop participants agreed that it would be reasonable to offer departing load customers the option to make a final lump-sum CTC payment or some form of continuing periodic transition cost payments. Participants agreed that these periodic transition cost payments would not necessarily be an extension of monthly payment arrangements for the duration of the remaining transition cost recovery period, but recommended that the Commission should address the frequency and duration of the payment options at a later date.
We agree that requiring a final lump-sum payment of remaining transition cost obligation could impose significant hardship on departing load customers. This would also place significant forecast risk on customers and shareholders. We approve of the recommended approach to evaluate and establish periodic payment options for departing load transition cost obligations after 2001. These obligations include ongoing costs eligible for continuing recovery and those costs which have been allowed to be deferred including employee-related and restructuring implementation transition costs. To implement this recommendation we will order utilities to file applications no later than January 30, 2001 which propose a method for continuing periodic transition cost payment arrangements for departing load customers. These applications should also provide forecasts of remaining transition cost obligations of departing load customers that would be used as a basis for the final lump-sum payment option and a method to determine the way lump-sum payments would reflect continued periodic CTC payments in the event that a customer should choose to make the lump-sum payment sometime during the proposed periodic payment period.
We have provided parties augmented procedures for review of interim transition cost tariffs. We intend to continue this practice and asked workshop participants to recommend a procedural means to continue to offer this enhanced opportunity for reviewing future utility proposals to modify transition terms and conditions tariffs. For 1997, participants recommend two means of reviewing proposed tariff changes. First, participants suggested that some review and discussion could take place in the workshops scheduled to address balancing accounts that are planned for the summer. Second, participants suggested that it may be appropriate to expand the standard advice letter filing service list to include those parties with broader restructuring-related interests and doubling the protest period from 20 to 40 days. PG&E recommends that a 30-day protest period for significant update filings, following instructions from assigned ALJs, would strike a reasonable balance between preserving existing advice letter time lines and giving parties the necessary additional time to respond to important restructuring filings. Participants also agreed that parties have the option to request that an advice letter be turned into an application, which would result in an even greater opportunity to scrutinize the tariff proposal. During the transition period (1998-2001), participants agreed that modifications to tariffs could be reviewed in advice letter filings subject to the same extended opportunities for review or in the annual transition cost proceedings.
We agree that additional workshops may be necessary to review proposed CTC terms and conditions tariffs in 1997, particularly because parties have not yet seen these tariffs for full service and direct access customers. Whether workshop activity addressing CTC terms and conditions tariff issues should take place in potential balancing account workshops or in separate workshops is unclear at this time. Additional procedural guidance will be provided by a later ruling.
Once the Phase 2 decision is adopted, utilities will be required to formally file tariffs by advice letter. We will utilize suggestions for an augmented advice letter process. The advice letter should be filed on each utility’s standard advice letter service list, the service list for R.94-04-031/I.94-04-032, and the service list for this docket. We adopt PG&E’s recommendation for expanding the protest period to 30 days. This procedure has been used previously to allow for protests to utility postings of the monthly QF energy payments. We will evaluate the responses to future advice letter filings to determine whether other tariff changes require additional workshop review.
After 1997, it is reasonable that the utilities use either the annual transition cost proceeding or the advice letter process to make tariff modifications, depending on the timing and the ramifications of such requests. The primary reason for the extended service and protest period for 1997 is to provide for both the busy procedural schedule for all restructuring-related initiatives and new restructuring-related tariffs. We may not need such augmentations to the advice letter process during the entire transition period, but will retain them at least for 1998. We will revisit this issue in the 1998 transition cost proceeding. We also note that parties may use protests to advice letters requesting that tariff modifications be turned into applications. We caution the utilities not to abuse the advice letter process by using them to request authorizations that would more appropriately be sought in an application.