V. Specific Expenditures

In its 1997 and 1998 Audit Reports (Exhibits 4 and 5, and errata filed November 8, 1999), ORA recommended numerous adjustments to the amounts PG&E recorded in the balancing account.⁸ ORA recommended $56.6 million in adjustments for expense-related items and $19.6 million in capital-related items recorded in calendar year 1997. It recommends $41.132 million in adjustments for expense-related items and $3.354 million in capital-related items recorded in 1998. Separately, TURN has recommended approximately $14 million in adjustments for expenditures recorded in 1997 and 1998. PG&E agreed, in some instances, to make the adjustments. PG&E agreed that $10.53 million was incorrectly recorded in the § 368(e) accounts. (See Summary Table of Resolved Issues, Appendix B, PG&E Opening Brief.) We discuss the disputed expenditures below.

1. Administrative and General ($27 Million)

ORA recommends certain reductions in the authorized expenditures because PG&E reclassified A&G expenditures and recorded them in subaccounts to which the § 368(e) enhancement applies. ORA recommends an $11.2 million reduction to reflect the impact of reclassification of A&G costs into operations and maintenance (O&M) costs recorded in 1997. One category of costs that were reclassified are "chargebacks." ORA recommends that A&G chargebacks totaling $15.1 million composed of $3.9 million, recorded in 1997, and $11.9 million, recorded in 1998, not be authorized as § 368(e) expenditures.

ORA describes chargebacks as an accounting mechanism whereby a company department charges another department for providing internal services. Chargebacks allow management to determine the full cost of providing services or products to an operating unit. ORA explains that the costs incurred to provide services to an operating unit are charged to the receiving operating unit through an appropriate O&M expense account. As such, chargebacks are internal costs for which there is management discretion and no invoice or verifiable bill exists, as would be available for external costs.

ORA states that the O&M chargeback reclassification occurred when PG&E implemented a new accounting system. ORA states, and PG&E appears to agree, that PG&E now charges to O&M expense accounts chargebacks previously charged to A&G accounts. ORA points out that PG&E's application does not request approval for only those accounts in which more was spent in 1997 or 1998 than in 1996. Instead, PG&E compares the lump sum total amounts spent in all the specified accounts for each year with the total amount spent in 1996. ORA argues that as a result of this accounting change, together with PG&E's lump sum approach, it cannot verify that the funds expended are incremental to those authorized in the 1996 GRC accounts. When ORA asked PG&E if the expenditures are incremental to the 1996 GRC A&G adopted amounts, PG&E's witness stated that she did not know, and that that was not a part of her analysis. (1 R.T. 58.)

TURN also addressed the reclassification issue in briefs. It argues that PG&E knew, but chose not to inform the Commission, that it had reclassified these expenditures before the Commission adopted D.96-12-077 wherein the Commission identified the subaccounts eligible for § 368(e) treatment. TURN states that in the absence of PG&E's reclassification, none of the expenditures or activities would have been eligible for recovery. TURN also gives an example of how the reclassification and recovery, as PG&E implemented it, could provide PG&E with a total recovery that exceeds actual costs, so that PG&E profits from reclassification. (See TURN Opening Brief, pp. 14-15.) TURN suggests that PG&E be given an opportunity to reduce the amounts recorded in its O&M accounts by an amount equal to the reclassified A&G, and then recalculate the amount of incremental spending in those accounts. This would ensure that PG&E would not profit from its reclassification of costs.

PG&E states that the A&G chargebacks were comprised exclusively of computer and telecommunications support functions and facilities. PG&E argues that these functions and facilities are essential to its distribution and transmission personnel in performing their safety - and reliability-related work. It rebuts ORA's argument that it cannot verify that the funds expended were incremental to the 1996 GRC-authorized levels by stating that a roughly equivalent amount of O&M-type costs were reclassified and are not currently recorded in the specified subaccounts. Therefore, PG&E argues that the Commission can safely assume that the inaccuracies end up as a wash.

Ensuring that the expenditures recorded in the § 368(e) accounts were incremental to the amounts authorized in the 1996 GRC is a fundamental step toward approving PG&E's expenditures. The Commission gave PG&E account-specific instructions in D.97-12-077, stating that the high degree of specificity was required "in order for the Commission to perform its future ratemaking duties and confirm . . . that the funds expended in [the balancing] account are in fact incremental to the funds authorized." (70 CPUC2d 207, 230, emphasis in original.)

PG&E admits that it did not determine whether the amounts recorded in the subaccounts were incremental to the A&G amounts authorized in the 1996 GRC. TURN's cross-examination and brief revealed that, under PG&E's A&G reclassification approach, PG&E could recover more A&G costs than it actually incurred. PG&E did not convincingly rebut TURN, focusing primarily on an assertion that TURN made its argument in briefs. Thus, we find that if PG&E were to profit from the incremental funding § 368(e) provided, this would be contrary to the intent of § 368(e) and D.96-12-077 and D.98-12-094.

ORA recommends that we not allow PG&E to recover these A&G expenditures in the § 368(e) accounts. TURN suggests that we give PG&E an opportunity to recalculate the amounts recorded. Presumably, the recalculated amounts would involve another round of evidentiary hearing, briefs, and proposed decision. The record is clear in this area and we will not give PG&E another opportunity to recalculate these items. The Commission's statements and findings in D.96-12-077 and D.98-12-094 gave PG&E clear direction that its expenditures must be incremental to the 1996 GRC authorized amounts, and that the assessment of whether the expenditures were incremental would include an account-specific level of review. PG&E should remove from its 1997 recorded expenditures the $15.1 million ORA disallowed A&G expenses,⁹ and PG&E should remove from its 1998 recorded expenditures the $11.9 million disallowed A&G chargebacks.

2. Advertising Expenses ($450,000)

ORA recommends that $450,000 in expenses described by PG&E as "advertising expenses" that were recorded under § 368(e) in 1998 should be removed. ORA acknowledges that PG&E later explained that the description assigned to the charges was in error. ORA states that PG&E claims the charges are associated with the costs of providing information to customers. ORA recommends removal because it believes that the costs should have been recorded in a different account, Account 909. On cross-examination, ORA stated that PG&E conceded that Account 909 applied to providing information to customers through public means. (Account 909 is described in Ex. 10, p. 11,855.)

PG&E unreasonably withheld adequate information until it served its rebuttal testimony. Regardless of the appropriate account that should have been used, we agree with ORA that these costs are not reasonably includable for recovery as an enhancement to system safely and reliability.

3. Automatic Meter Reading Costs ($499,295)

TURN points out in its testimony that PG&E includes the costs for a new AMR program in 1998. According to TURN, AMR is designed generally to reduce meter-reading expenses, and not to provide more reliable electric service. TURN argues that the only safety arguments that could be adduced for AMR would be that fewer meter readers might be involved in traffic accidents or suffer dog bites and sprained ankles on the job. TURN therefore recommends that the Commission not allow PG&E to recover $499,295 of costs in Account 597.

PG&E attempted to rebut TURN's arguments in rebuttal testimony and on the stand. It states that it is possible to use AMR to send signals to an outage information system to let PG&E know that groups of customers are out of power; and that it would facilitate PG&E diagnosis of the distribution system relative to where an outage may have occurred. In that way, PG&E argues, AMR could enable PG&E to respond more quickly.

TURN's cross-examination of PG&E's witness made it very clear, however, that while improved outage analysis is possible with AMR, the meters that are part of the AMR program at issue here do not provide such information to PG&E. Therefore, PG&E has failed to demonstrate that the $499,295 in 1998 AMR expenditures it recorded in Account 597 enhance transmission and distribution system safety and reliability. PG&E should not be allowed to recover these costs as § 368(e) expenditures.

4. Common Plant "Unbundling" ($19.5 Million)

Two of the accounts the Commission identified for possible § 368(e) recovery relate to common plant: Fleet, Equipment and Tools, and Telecommunications Equipment. TURN argues that the Commission must limit the cost recovery associated with these common plant programs to those portions of the costs that may reasonably be allocated or assigned to functions that enhance system safety and reliability. Costs associated with PG&E's gas operations, and with its generation activities, TURN argues, should be excluded entirely, and those associated with transmission activities should be excluded as of April 1, 1998. TURN argues that PG&E is seeking to recover any amount of actual common plant expenditures that exceeded the total 1996 GRC-adopted level, including, for example, the costs of gas service trucks. TURN recommends reducing PG&E's unbundled common plant capital spending by $5.6 million in 1997 and by $13.9 million in 1998.¹⁰ These amounts leave untouched the amounts unbundled to distribution for corporate services, which TURN argues, is overly generous to PG&E. TURN's recommendation applies the results of the unbundling study that PG&E filed as part of its 1999 GRC.

PG&E argues that it complied with our prior orders in accounting for common plant costs. It argues that to unbundle the common plant costs as TURN recommends would have resulted in common plant costs being allocated twice - once in the setting of the annual base revenue increases, and again in the calculation of the incremental amount. PG&E argues that such "double-counting" is unfair, unreasonable, and would understate the incremental amount recoverable.

PG&E also argues that if any unbundling of these costs is to occur now, the Commission should not apply the results of PG&E's unbundling study. PG&E argues that the Commission should apply the "four-factor method." PG&E states that it is the "unbundling method known at the time." (Ex. 3, p. 4-3.) PG&E does not describe the method or provide any citation to prior use of the "four-factor method" by the Commission.

We agree with TURN that it is appropriate to unbundle costs to the extent reasonably feasible to achieve the intent of § 368(e). As we stated above in our discussion of the standard, it is not enough to merely establish an account, record dollars in that account, and track those dollars. PG&E must demonstrate that the expenditures enhance or improve transmission and distribution system safety and reliability. The dollar values TURN recommends for removal from § 368(e) recovery are derived using PG&E's unbundling study. PG&E's argument does not explain how double-counting would occur if the Commission adopted TURN's recommendation. PG&E did not rebut the testimony TURN submitted, and it waived the opportunity to cross-examine TURN's witness, so there is no underlying record to explore to better understand PG&E's "double-counting" argument. In fact, it did not raise the issue of "double-counting" until the filing of briefs. As TURN points out, PG&E's argument relies on factual assertions that were not made on the record, and that are not subject to judicial notice or other extra-record citation. We will make the disallowance. $5.6 million and $13.9 million should be disallowed from PG&E's recovery of unbundled common plant capital spending in 1997 and 1998, respectively.

5. Distribution and Customer Service
Support Costs ($13.31 Million)

At issue is whether DCSS Account Expenditures for clerical support services for electric distribution system operations, maintenance and construction personnel that are recorded in the DCSS expenses should be excluded from recovery because they do not directly enhance system safety and reliability. ORA does not dispute that DCSS expenses might be necessary to maintain the same level of service, but rather points out that PG&E does not explain how such incremental DCSS spending actually increased system safety and reliability. ORA states that PG&E has never asserted that DCSS funds were spent for the purpose of improving safety and reliability. ORA argues that $7.01 million and $6.30 million in 1997 and 1998 DCSS expenses, respectively, should be disallowed.

PG&E argues that it is necessary to provide clerical support to the operations, maintenance and construction personnel that are directly providing a safe and reliable system. PG&E contends, again, that the costs of activities that are required to maintain the transmission and distribution system should be recoverable through § 368(e). Also, PG&E claims that the dollar figures ORA recommends represent removal of all the expenditures associated with DCSS, and presume that all of the costs associated with DCSS are incremental to the 1996 GRC-adopted levels. This presumption, PG&E argues, contradicts ORA's argument that PG&E has failed to demonstrate that its costs are in fact incremental, and reveals that ORA is attempting to maximize the total recommended downward adjustment in allowed § 368(e) recovery.

We share ORA's concern that PG&E did not argue how the DCSS expenditures improve safety and reliability in its direct showing. We will accord little weight to rebuttal testimony that serves only to criticize ORA or TURN when PG&E made an inadequate showing to justify the reasonableness of its actions. We will make the disallowance. We will reduce PG&E's recovery of DCSS expenditures under § 368(e) by the $13.31 million ORA recommends.

6. Electric Industry Restructuring Costs
($2.06 Million)

ORA contends that $3.9 million of costs incurred in 1997 relating to electric industry restructuring implementation should be excluded from § 368(e) recovery. PG&E describes these costs as including labor and expenses associated with the design, development, and implementation of Independent System Operator (ISO) operational systems, physical facilities, business systems, business rules and protocols. PG&E also describes these costs as transmission reliability-related costs. PG&E has agreed that $1.84 million of these costs should be removed since recovery of them was requested and granted in two other proceedings, leaving recovery of $2.06 million contested.¹¹

Like the CEMA costs discussed elsewhere, ORA argues that these costs did not enhance system safety and reliability and should have been included in PG&E's application to recover electric restructuring costs pursuant to § 376.¹² ORA asserts that these costs would not have been incurred if electric industry restructuring had not been implemented. ORA maintains that costs incurred to implement restructuring that are not funded in the 1996 GRC may be recovered under § 376. ORA claims that prior to the settlement, PG&E had carefully detailed where costs associated with electric industry restructuring implementation were being recovered but made no mention of its effort to recover such costs in this proceeding. ORA concludes that as long as such costs were properly included in PG&E's § 376 application, regardless of whether the Commission approved their recovery in adopting the settlement, they are ineligible for recovery under § 368(e). Without stating it explicitly, ORA seems to be concerned that PG&E is attempting to recover electric restructuring costs above and beyond the recovery of such costs recommended in the settlement and ultimately approved in D.99-05-031, in conflict with the settlement adopted in that decision.

TURN again points out that the mechanism for recovery - pursuant to § 368(e) vs. § 376 - is important. TURN argues, and PG&E does not appear to contest, that the costs recorded were entirely devoted to the development and implementation of the ISO, and are, therefore, transmission expenses. Recovery here, TURN explains, would allocate these transmission expenses on a distribution-EPMC basis. TURN argues that this outcome is contrary to the settlement equal percentage of marginal costs (EPMC) approved in D.99-05-031, which stated that costs such as these would be categorized as "internally managed restructuring costs" and be recovered through a one-time debit to the Transition Revenue Account (TRA). TURN states that although the Commission is presently considering proposals to change the allocation, none of the proposals would assign as high a proportion of these costs to small consumers as would allowing recovery of them in this proceeding.¹³

PG&E claims that the electric restructuring costs at issue here were not included in its § 376 application. It argues that § 376 is not the exclusive means of recovering electric restructuring costs, and that these costs were not required to be included in PG&E's § 376 application. They were not included, argues PG&E, because contrary to ORA's assertions, the standard for recovery under § 376 differs from that under § 368(e). PG&E claims that § 376 cost recovery was limited to costs incurred to perform tasks different from the tasks funded in the 1996 GRC, and that the costs must be one-time only type costs. PG&E states that the restructuring costs at issue here are costs that it would incur regardless of electric industry restructuring.

In D.99-05-031, the Commission stated that costs eligible for § 376 treatment must be incremental to those costs (1) covered in current rates, and (2) that relate to ongoing utility business. (D.99-05-031, p. 20.) In that decision, the Commission also adopted guidelines regarding § 376 treatment and cost recovery issues, including the following:

1. Identification and recovery of all restructuring implementation costs shall be addressed in this proceeding. Restructuring-related costs other than restructuring implementation costs, shall be recoverable from customers.

2. Only those costs expended to accommodate implementation of the ISO, Power Exchange, and direct access until December 31, 1998 shall receive § 376 treatment. Therefore, costs incurred after 1998 are not eligible for § 376 treatment and the costs of operating these programs on an ongoing basis are not eligible for § 376 treatment.

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13. Restructuring implementation costs shall be recovered through a debit entry to the TRA and shall not be assigned to separate cost categories such as transmission, distribution, etc. (Id., pp. 23-24, emphasis added.)

Moreover, the Commission found that costs incurred to establish the new market structure, "i.e., accommodate the implementation of the ISO" are eligible for recovery through § 376. (Id., p. 19.)

The specific costs at issue here were described in Exhibit 11, which includes PG&E's descriptions of the work orders associated with the costs. As TURN pointed out, all of the activities were related to the development and implementation of the ISO. For example, labor and expenses associated with the ISO's physical facilities in Folsom, California; preparation of functional diagrams and vendor bid documents for the ISO's settlement and billing systems; and stakeholder discussions on how the ISO's operation systems should function. All of the activities and the associated costs are restructuring implementation costs specific to development and implementation of the ISO.

At a minimum, PG&E should have identified these costs in its § 376 application. In D.99-05-031, the Commission clearly stated that all restructuring implementation costs were to be identified in that proceeding. In fact, parties supporting the settlement argued that the settlement was in the public interest precisely because it identified and addressed the overlap issues with other proceedings and provided a clear roadmap for their resolution. Apparently other parties believed PG&E had identified all restructuring implementation costs, and the settlement struck among those parties was, at least in part, predicated on that assumption. In D.99-05-031, the Commission summarized the following understanding:

PG&E expects to incur $114.3 million in restructuring implementation expensed costs and $11.6 million in capital costs, for a total of $125.9 million. Out of this total, PG&E has subtracted $13.6 million for which it expects to seek recovery in other forums, externally managed costs of $62.2 million for 1997 and 1998, and a settlement reduction of $10 million.

PG&E did not make an exception for recovering some restructuring costs in § 368(e).

PG&E cannot now credibly come to the Commission and state that it did not include all restructuring implementation costs in the § 376 proceeding. PG&E's statements to that effect undermine its § 376 settlement. We will not allow recovery here of the electric restructuring implementation costs that PG&E failed to bring to our attention in A.98-05-004 et al. To do so would undermine the Commission's settlement process.

Further, given how PG&E defines costs eligible for § 376 recovery, we cannot conclude that the costs at issue were ineligible for recovery in its § 376 application. Performing the task of, for example, designing and developing the physical facilities for the ISO in Folsom is different from the tasks funded in the 1996 GRC, and the costs incurred to perform that function are one-time only type costs. These costs are clearly unrelated to enhancing system safety and reliability. Therefore, we find that PG&E should not be allowed to recover the remaining $2.06 million in contested electric industry restructuring costs under § 368(e) and that these costs should be excluded from 1997 expenses.

7. Pole Test & Treat Costs ($2 Million)

TURN argues that PG&E should not be allowed to recover amounts for the pole test and treat program, which should be the responsibility of the joint owners of the poles, like telecommunications utilities. It argues that in 1996 and 1997, PG&E recovered $2.22 million and $2.023 million, respectively, from joint owners. TURN contends that it would be unreasonable for the Commission to assume for ratemaking purposes that the telecommunications utilities will "get off the hook" for their traditional responsibility to maintain joint poles. (Ex. 24, TURN/Marcus, p. 4.) TURN proposed two remedies: (1) deduct $2 million in imputed revenues from the amount PG&E is allowed to recover under § 368(e), or, (2) in the alternative, direct PG&E to establish an accounting mechanism that will ensure that ratepayers receive the full benefit of any reimbursement ultimately made to PG&E by its joint pole owners.

PG&E argues that no party questions that pole test and treat costs enhance transmission and distribution system safety and reliability, or that they satisfy the requirements for § 368(e) recovery. PG&E does not object to the Commission establishing a memorandum account to track any reimbursements PG&E may receive for pole maintenance. PG&E points out, however, that Pacific Bell Telephone Company (Pacific Bell),¹⁴ the predominant joint owner of its poles, has stated that it is not bound by General Order (GO) 165 and, therefore did not anticipate participating financially in the pole test and treat program. PG&E states that "[w]hile TURN and PG&E [the utility] may disagree with this interpretation of GO 165, the fact remains that Pacific Bell has not reimbursed [the utility] for test and treat work done on joint poles in 1998." (Ex. 3, PG&E Co/Carruthers, p. 3-8.)

The test and treat program is conducted to comply with GO 165. The purpose of GO 165 is to establish minimum requirements for electric distribution facilities inspection, condition rating, scheduling and performance of corrective action, record keeping, and reporting, in order to ensure safe and high-quality electrical service. The Commission considered recovery by PG&E of costs associated with wood pole test and treat programs in the GRC. (D.00-02-046, pp. 164-165.) The Commission disallowed PG&E's proposed forecast adjustment of $3,200,000 for its supplemental pole test-and-treat costs. In doing so, the Commission stated:

PG&E's [the utility's] attempt to convert the underlying issue for this adjustment to the question of whether Pacific Bell or any other telecommunications utility will share costs of testing and treating jointly owned poles does not change the fact that the underlying cost pertains to a supplemental maintenance program. That program grew out of the Bain report and is associated with PG&E's past inadequate maintenance practices, when PG&E gave inadequate attention to pole test-and-treat activities. PG&E has not shown that it is reasonable to charge ratepayers for this expense through this GRC. We support appropriate cost sharing for the costs of testing and treating jointly owned poles. However, this is not the appropriate proceeding to resolve alleged deficiencies in GO 165.

As we stated in the GRC decision, cost sharing for the costs of testing and treating jointly owned poles is appropriate. We expect that the utilities that have joint pole arrangements with PG&E and have traditionally borne a responsibility to share in the costs of maintaining joint poles will continue to do so.

We agree with TURN that PG&E should not be allowed to keep funds that are reimbursement of costs for the testing and treating of jointly owned poles and recover amounts for the program from ratepayers. The record in this proceeding indicates that PG&E, when faced with what appears to be a dispute over a delinquent payment for a service it rendered (testing and treatment of wood utility poles), is seeking compensation from ratepayers to make it whole, rather than pursuing payment from the other party. It has apparently been taking this approach with respect to the approximately $2 to $3 million annually it is owed by joint owners of poles since 1998. It is not in the public interest to allow PG&E to recover these funds from ratepayers in this proceeding, because we would then be removing any remaining incentive it may have to pursue payment from joint pole owners. Therefore, we will adopt TURN's recommendation to not allow PG&E to recover under § 368(e) the $2 million identified as costs incurred for its pole test and treat program.

8. Vehicles Used for Metering ($929,000)

TURN points out that PG&E included in its request $929,000 of common plant costs incurred to purchase vehicles used for metering. Because metering does not preserve the reliability of the electric distribution system, TURN argues that these costs should be deducted. PG&E argues that vehicles purchased for use in metering are "available for emergency response duties" and "could be used" as part of its response to emergencies on its transmission and distribution system. (Ex. 3, pp. 3-9 and Opening Brief of PG&E, pp. 15-16.)

TURN counters that PG&E's witness testified that these emergency response duties would likely arise only during Class 3 and Class 4 emergencies; that during the last five years, PG&E has experienced no Class 4 emergencies, and approximately 10 Class 3 emergencies lasting from one to five days each. Given this information, TURN estimates that these vehicles would be needed for emergency response less than 3% of the time. TURN also states that, as illustrated by Ex. 7, the trend with PG&E's meter reading vehicle fleet numbers increasing is counter to the trend for its electric distribution vehicles that show a 20% reduction from 1997 to 1998. TURN argues that if PG&E's real concern was to provide for vehicles during emergency responses, it would have retained more of the vehicles involved in the daily operation of the distribution system, rather than reducing the numbers of those vehicles across-the-board.

In its defense, PG&E argues that nothing in § 368(e) or the Commission's implementing decisions suggests that the funds "can only be used to purchase items that are actually used for specific purposes a certain percentage of the time." (Reply Brief of PG&E, p. 24.)

It is appropriate for PG&E to utilize its available vehicle fleet as necessary in emergency response. PG&E is correct that the statute and our implementing decisions do not include any "minimum use" criteria for evaluating whether a particular expenditure is eligible for recovery through § 368(e) funds. The statute does require that the funds "be used by the utility for the purposes of enhancing its transmission and distribution system safety and reliability." PG&E's argument, taken to its extreme, could result in just about any expenditure being eligible for recovery through § 368(e) funds. All the services PG&E performs (like customer service), and their associated expenditures (for example, the phone system costs), "could" come in to play in response to an emergency, and be "available for emergency response duties."

It is clear from this record that the vehicle expenditures were made for the purpose of providing metering services, which are services not generally associated with transmission and distribution system safety and reliability. Secondarily, the vehicles are available for emergency response. The $929,000 of common plant costs incurred to purchase vehicles used for metering should be excluded from recovery through § 368(e).

9. Year 2000 Compliance Expenses ($940,000)

ORA recommends that $940,000 in 1998 expenses and $1.46 million in 1998 capital spending associated with year 2000 (Y2K) embedded system costs be excluded from recovery under § 368(e). ORA argues that PG&E cannot demonstrate that its Y2K spending has demonstrably enhanced transmission and distribution system safety and reliability. ORA states that, at most, the spending avoids a potential one-time problem that would not have degraded system safety, and only would degrade reliability if the system experienced an outage as the clock reached the year 2000. ORA argues that this spending is not akin to preventive-type activities such as tree-trimming in that tree-trimming is an activity that addresses an actual, rather than a potential, problem.

PG&E explains that its Y2K expenses were incurred for inventorying, assessing, testing, and remediation to embedded systems and applications associated with its distribution system.

PG&E was granted a base rate increase in D.00-02-046 date February 17, 2000, in A.97-12-020. That was the appropriate proceeding, with a 1999 test year, where PG&E should reasonably have foreseen and litigate the need for Y2K-related cost recovery in retail rates. However, the benefit to system reliability is indirect at best, PG&E is obliged to have a working system to serve its customers and it fails to justify the amount recorded in the SSRA for § 368(e) costs resulted in any enhancement as envisioned in § 368(e). The end of the millennium was foreseeable by the authors of Assembly Bill (AB) 1890 and they did not include it in § 368(e). We disallow the expenses for § 368(e) purposes.

10. "Time Saving Proxy" Calculation

TURN proposed that to save time and not allow another round of testimony on the reasonableness of its filing (which PG&E clearly chose not to make in a timely fashion) that the Commission should apply the same percentage of the ORA and TURN proposals adopted to the total requested by PG&E in this application. Despite the weakness of PG&E's initial showing, and the limited weight we accord its rebuttal testimony, TURN and ORA did conduct their own analysis and make specific recommendations. PG&E responded to discovery, and the parties did not argue that PG&E obstructed them. For these reasons, we are able to consider the merits of each and every objection raised by TURN or ORA, despite the inadequacy of PG&E's initial showing. Only those disallowances that are specifically identified and justified by the parties are adopted in this decision, and no "time-saving proxy" calculation is required.