7. Terms of the Distribution Settlement

7.1 Total Revenue Requirement

The Distribution Settlement adopts a 2003 electric distribution revenue requirement of approximately $2,493 million and a gas distribution revenue requirement of $927 million. The Settling Parties agree that PG&E's revenues at present rates are $2,257.44 million for electric distribution and $874.895 million for gas distribution. Therefore, the Distribution Settlement would result in an increase from present rates of approximately $236 million for electric distribution and $52 million for gas distribution.

When combined with the Generation Settlement, the Distribution Settlement would result in a 2003 generation revenue requirement of approximately $912 million ($2003). Compared to present rates of $874.264 million for generation, the Settlements would provide for an increase of approximately $38 million, or 4.35%.

As shown in Table 2, below, the TY 2003 revenue requirement adopted by the Settlements represents a significant compromise on the part of all parties.

Table 2

Comparison of Settlement to PG&E and ORA Litigation Positions

(Millions of Dollars)

	PG&E Comparison Exhibit	ORA Comparison Exhibit	Settlement Agreement	PG&E exceeds Settlement	ORA exceeds Settlement
Electric	2710	2446	2493	217	(47)
Gas	982	909	927	55	(18)
Generation	944	895	912	32	(17)
Total				304	(82)

On an overall basis, we agree with the Settling Parties that the TY 2003 revenue requirements provided in the Settlements are reasonable in light of the record before us. The Settlements represent a significant reduction to PG&E's TY 2003 revenue requirement request, and represent a reasonable compromise of the Settling Parties' positions regarding the issues resolved by the Settlement.

It is not clear that PG&E's revenue requirement would be as favorable to ratepayers through continued litigation as the revenue requirement provided in the Settlements, and as discussed further below, the Settlements resolve the issues within the zone of reasonableness such that we can find PG&E's rates to be just and reasonable.

7.2 Attrition

Attrition is the year-to-year decline in a utility's earnings caused by increased costs that are not offset by increased rates or sales. In order to protect utility shareholders from the effects of attrition to some extent, the Commission has adopted a ratemaking mechanism called the Attrition Rate Adjustment (ARA). The ARA mechanism was designed to "provide utilities with the reasonable opportunity of achieving their authorized rates of return during years in which they are not permitted under the Commission's rate case plan procedures to file for general rate relief but in which they still face volatile economic conditions." (D.85-12-076, Finding of Fact 1, 9 CPUC 2d 453,476.)

The traditional attrition mechanism provides for an advice letter filing, just prior to the attrition year, by the utility seeking increased rates based on the escalation of adopted TY GRC expense and rate base. A seven-year average of plant additions is used to account for rate base growth during the attrition period. The escalation rates are conventional indices such as the U.S. Department of Labor, Bureau of Labor Statistics' CPI, and DRI.

PG&E requested that we approve an ARA mechanism for the years 2004, 2005, and if applicable, 2006. PG&E's proposed mechanism was based on the traditional attrition mechanism adopted in D.85-12-076, and modified in D.92-12-057, with two additional components. First, for distribution attrition, PG&E proposed to modify the attrition mechanism to account for a higher-than-usual increase to medical benefits costs. PG&E also proposed to replace the Materials and Services Index (MSI) previously used to forecast non-labor escalation rates with individual price indices drawn from DRI/WEFA's Utility Cost Information Service (UCIS).¹⁴

Second, for generation attrition, PG&E proposed to modify the attrition mechanism to reflect its anticipated "ramp-up" in generation capital spending and O&M expense. PG&E's proposed method results in capital additions that significantly exceed the amount resulting from a seven-year average.

PG&E's proposed attrition mechanism would result in 2004, 2005, and 2006 revenue requirement increases of $74 million, $83 million, and $82 million for electric distribution and $28 million, $31 million, and $31 million for gas distribution. PG&E's proposal would result in estimated generation attrition increases of $56 million, $9 million, and $33 million for 2004, 2005, and 2006, respectively.

For distribution attrition, ORA supported PG&E's method. For generation attrition, ORA also approved PG&E's proposed method - but not PG&E's forecast of 2004 and 2005 capital expenditures. Instead, ORA proposed that the Commission use PG&E's 2003 forecast of electric generation capital additions. ORA also proposed an additional year of attrition in 2006 and deferral of PG&E's next GRC to test year 2007. (Exhibit 304, p. 19-8.) ORA agreed with PG&E's request to file for attrition through an advice letter for attrition years 2004 and 2005, but proposed that PG&E be allowed the option to file an application rather than an advice letter for the 2006 attrition year if the traditional ARA mechanism did not allow PG&E a reasonable opportunity to earn the authorized rate of return.

Aglet advocated an attrition method that would calculate a revenue requirement for 2005 based on the 2003 revenue requirement times one year of forecast change in CPI. Aglet requested that the Commission deny PG&E's request for 2004 and 2006 revenue requirement adjustments, arguing that in light of the continuing low inflation and interest rates, a single distribution attrition allowance in 2005 would be appropriate. As for the change in the method of forecasting capital additions, Aglet argued that PG&E's request was unfairly slanted toward higher rates by isolating operational areas where it intends to spend more than prior year attrition formulas would indicate while providing no offsetting revenue reductions in areas where PG&E may intend to spend less. Aglet recommended that we require PG&E to file separate applications supporting its request for Diablo Canyon refueling outage adjustments and the Low Pressure Turbine Rotor Replacement project (LPTRR). Like ORA, Aglet supported deferral of PG&E's next GRC. (Exhibit 550, p. 13-14 and 15-17.)

The Distribution Settlement reflects the Settling Parties' agreement to defer the test year for PG&E's next GRC until 2007, and to provide PG&E attrition adjustments for 2004, 2005, and 2006, based upon an agreed-upon formula and implemented through advice letter filings. The proposed annual electric and gas distribution attrition adjustments for 2004 and 2005 would be equal to the previous year's authorized revenue requirement times the forecast change in the CPI for All Urban Consumers.¹⁵ For 2006, the proposed annual electric and gas distribution attrition adjustments would be equal to the previous year's authorized revenue requirements times the forecast change in CPI-All Urban Consumers plus one percent.

Notwithstanding the forecast change in CPI-All Urban Consumers, the Distribution Settlement provides for minimum and maximum revenue requirement attrition adjustments as follows:

2004 2005 2006

Minimum 2.0% 2.25% 3.0%

Maximum 3.0% 3.25% 4.0%

The Distribution Settlement would result in 2004, 2005, and 2006 estimated attrition increases of $62 million, $64 million, and $89 million for electric distribution and $23 million, $24 million, and $33 million for gas distribution.¹⁶

The Generation Settlement also provides for annual electric generation attrition increases for 2004, 2005, and 2006, equal to the previous year authorized revenue requirement times the forecast change in CPI-All Urban Consumers, including a minimum increase of 1.5% and a maximum of 3% for 2004 and 2005, and an additional 1% for 2006.

Under the Generation Settlement, the base revenue requirement for Diablo Canyon includes one refueling outage. If PG&E forecasts a second refueling outage in any one year, the authorized revenue requirement would be increased by $32 million ($2003) per refueling outage, adjusted for CPI using the same formula described above for attrition adjustments. The Generation Settlement also authorizes $3 million ($2003) per year for 2004, 2005, and 2006, for additional security costs at Diablo Canyon, plus an attrition allowance using the same formula described above for attrition adjustments. This would result in an estimated increase of $56 million for 2004, decrease of $9 million in 2003, and an increase of $33 million in 2006.

7.3 Discussion

The attrition mechanism originated in SoCalGas' 1981 GRC (D.92497, 4 CPUC2d 725,770 (1980)). An attrition adjustment for PG&E was first adopted in PG&E's TY 1982 GRC. In that decision, the Commission found that "an attrition mechanism is a necessity in this period, where the economy is unpredictable and volatile. We believe the adoption of indexing under these circumstances is a necessity to assure that PG&E will be able to recover its costs and also to protect ratepayers from possible overestimates of expenses."

In the same decision, at PG&E's request, the Commission adopted a new rate mechanism called the Electric Revenue Adjustment Mechanism (ERAM). The ERAM functioned in the same manner as the balancing accounts adopted to implement Public Utilities Code Section 739.10, discussed in Section 7.20 below, ensuring the full recovery of electric revenue requirements regardless of actual sales.

In D.85-12-076, the Commission reconsidered the attrition mechanism and declined to eliminate it at that time, finding that even though attrition may create a "disincentive to manage cost escalation and seek cost efficiencies,"...a "three year rate case cycle with but one year of rate relief would not give the utilities a reasonable opportunity to earn their authorized rate of return." (19 CPUC2d, 453, 456.) The Commission also considered and rejected a staff proposal to apply an earnings test to the calculation of attrition year revenue requirements.

The Commission has since approved attrition adjustments in four of PG&E's GRCs (D.86-12-095, D.89-12-057, D.92-12-057, and D.00-02-046). In D.89-12-057, the Commission rejected PG&E's request to adjust the seven-year average to reflect a higher than usual increase in capital additions, finding that although the average approach may understate the costs of some projects and overstate the costs of other projects, the overall outcome is fair. In D.00-02-046, the Commission denied PG&E's request for an attrition increase for 2000, finding that neither high inflation, nor unpredictable changes in financial markets warranted attrition relief in that year, but allowed PG&E to file an application for attrition in 2001.

In this case, as in previous GRCs, the question we consider when deciding whether and through what method to grant attrition relief is whether the utility will have a reasonable opportunity to earn its authorized rate of return in the attrition year based on current and forecast economic conditions. PG&E acknowledges that this is the critical question, stating "if PG&E believes that it has the opportunity to earn its rate of return in a non-GRC year without attrition, then PG&E should, and has historically, forgone making a request for attrition." (Exhibit 24, p. 5-6.)

PG&E and Aglet each refer us to particular periods during which the Commission has granted or denied attrition as suits their objective. PG&E pointed to a twelve-year period during which the Commission has granted attrition in all but two of the years. Aglet pointed to the more recent five-year period in which the Commission has granted attrition relief only once. Viewed from either perspective, this history is consistent with our policy that attrition relief is not an entitlement or a method of insulating the company from the economic pressures which all businesses experience. This history is also consistent with the our prior finding that "Neither the Constitution nor case law has ever required automatic rate increases between general rate case applications." (D.93-12-043, 52 CPUC 2d 471,492.)

The attrition mechanism proposed in the Settlements would grant PG&E attrition adjustments in each of the years 2004, 2005, and 2006, with the adjustment tied to the level of inflation, as measured by the CPI- All Urban Consumers. The annual changes in the adopted revenue requirement would be calculated by escalating the previous year authorized Revenue Requirement using CPI. The attrition mechanism would also "guarantee" a minimum attrition adjustment regardless of the level of inflation or the level of the utility's earnings.

As with the other areas of the Settlements, the Settling Parties assert that the attrition agreement is reasonable because it represents a compromise between the positions of the parties, and because the revenue requirement adjustments calculated by the CPI method are estimated to be less than the revenue requirements that would have been calculated by PG&E's proposed model under a variety of inflation rates. However, the parties' agreement to the particular number or approach is not sufficient to deem it reasonable; we must be able to find the settlement reasonable in light of the whole record in order to approve it.

We believe that approving a "minimum" increase in the adopted revenue requirement regardless of whether or not PG&E has been able to earn its authorized rate of return is inconsistent with the Commission's policy that attrition adjustment should reflect an "opportunity" to earn the authorized rate of return and not a "guarantee." Taken to an extreme, approval of the proposal would grant PG&E a guaranteed increase in revenue requirement even in the event of deflation, an outcome that is clearly unreasonable.

Although we are generally reluctant to alter the results of a good faith negotiation process, we must do so if we find that the public interest is in jeopardy, as is the case here. We approve the framework offered by the Settling Parties that provides for automatic attrition adjustments for each of the attrition years 2004, 2005, and 2006, tied to the level of CPI-All Urban Consumers, but modify the Distribution Settlement to eliminate the provision for a "minimum" attrition increase. We do not believe that this modification deprives PG&E of the opportunity to earn its authorized rate of return. Although initially PG&E requested a higher-than-usual forecast of generation capital additions, according to PG&E witness Berman, the increase in the generation capital additions forecast was primarily associated with reliability work in hydro operations and the replacement of low-pressure turbine rotors in nuclear generation. (RT 1494:11-15.) As part of the Generation Settlement, the Settling Parties have agreed that PG&E's proposed low-pressure turbine rotor replacement projects will be reviewed as part of the TY 2007 GRC and PG&E will file a separate application for the steam generator replacement project.¹⁷ The Generation Settlement also includes PG&E's agreement to remove the Selective Catalytic Reduction Project from its forecast.

We find that authorizing an automatic CPI-based attrition mechanism by advice letter for the years 2004, 2005, and 2006, including a one percent adder to the attrition adjustment in 2006, as well as specific adjustments for additional refueling outages and increased security costs at Diablo Canyon, will provide PG&E with a reasonable opportunity to earn its rate of return in the attrition years, consistent with our attrition policy. Although the adopted attrition mechanism will significantly reduce the risk PG&E will face in the attrition years, it will not completely eliminate risk. This is also consistent with our attrition policy.

7.4 Administrative and General (A&G) Expense

7.4.1 Introduction

A&G expenses are general expenses not directly chargeable to any specific utility function. They include general office labor and supply expenses and items such as insurance, casualty payments, pensions and benefit expenses, consultant fees, regulatory expenses, and stock and bond expenses.

PG&E, ORA and TURN all took positions on A&G expense issues. Based on a detailed audit of PG&E's A&G expense forecast, ORA recommended adjustments to PG&E's TY 2003 A&G expense forecast in the following areas: the allocation of holding company costs to the utility, Corporate Services Department total costs and the allocation of those costs to capital, below-the-line (e.g., bankruptcy-related costs) or to affiliates, the Performance Incentive Plan, Benefits (including medical, dental, and vision plans, service awards, employee relocation, and tuition reimbursement), Property Insurance, Third Party Claims, Directors and Officers Liability insurance, seismic upgrade projects, and various accounting adjustments. PG&E and ORA also differed on the amount of various A&G costs to capitalize.

TURN also recommended reductions to PG&E's A&G expenses in the areas of Holding Company costs and allocation of additional costs below-the-line for the Revenue Requirements, Internal and External Communications, and Affiliate Rules and Regulatory Compliance Departments.

TURN generally agreed with ORA's recommended adjustments, and offered additional testimony in areas where TURN recommended further adjustments to PG&E's request. For example, TURN would allocate a small percentage of the costs of the Internal and External Communications Department to below-the-line on the basis that ratepayers should not be funding anti-municipalization efforts. TURN notes that a number of the publications developed by this department related to municipalization. In the Revenue Requirements Department, TURN recommended that a normalization adjustment is required to reduce GRC contract expenses to take into account that a GRC is not filed each year. TURN's adjustment would provide for a contract cost of approximately $1.3 million, compared to PG&E's requested $2.58 million. TURN also recommended that the cost of affiliate compliance for non-tariffed products services should be allocated on a 50/50 basis between ratepayers and shareholders, instead of entirely to ratepayers as ORA proposed. TURN noted that the difference in allocation is small, only $28,225, but the principle of assuring that shareholders pay all relevant affiliate compliance costs is important.

TURN's position on A&G expense is $853,700 lower than ORA's Comparison Exhibit position. (Exhibit 100, p. 3-6.) The following table compares PG&E's A&G request and ORA's recommendations.

Table 3

PG&E's and ORA's Positions on Total Utility A&G Expenses¹⁸

(Thousands of 2000 dollars)

Account	Description	PG&E	ORA	Difference
920	Salaries	139,035	112,416	(26,619)
921	Office Supplies and Expenses	23,334	17,276	(6,059)
922	A&G Capital Transfer	(20,960)	(17,066)	3,893
923	Outside Services	116,979	60,161	(56,818)
924	Property Insurance	15,531	10,859	(4,492)
925	Injuries and Damages	75,970	70,458	(5,511)
926	Pensions and Benefits	287,917	192,843	(95,074)
928	Regulatory Commission Expenses	(0)	(0)	(0)
930	Miscellaneous General Expenses	86,909	86,909	(0)
935	Maintenance of General Plant	11,233	6,310	(4,922)
	Total A&G Expenses (2000 $)	735,767	540,165	(195,602)

As can be seen in Table 3, the largest differences between the two forecasts appear in Account 920 (Salaries), Account 923 (Outside Services), and Account 926 (Pensions and Benefits). Account 923 includes the charges to PG&E from PG&E Corporation, its parent company (the holding company). The difference in Account 926 relates primarily to PG&E's requested contribution to the Retirement Plan trust, discussed in Section 9.1 below.

ORA recommended a reduction of $26,619,000 in Account 920 primarily related to PG&E's Performance Incentive Plan (PIP) forecast. The PIP is a short-term incentive pay plan that covers approximately one-third of PG&E's workforce. PIP payments are earned during the plan year and paid in March of the following year. The annual payments are based on the employee's participation rate and the PIP score for the department in which the employee works. The participation rate is a fixed percentage of the employee's base pay, and varies by employee category. The PIP score can range from 0.0 to 2.0 and reflects the department's actual performance compared to annual performance measures. PG&E requested $139,035,000 in Account 920, of which $41,622,000 ($2000) is PG&E's 2003 PIP forecast. ORA recommended adjusting Account 920 to require shareholders to fund 50% of the PG&E's forecast PIP expenses, consistent with the Commission's decision in D.00-02-046.

ORA recommended a reduction of $56,818,000 in Account 923, the majority of which ($40 million) is related to ORA's contention that PG&E failed to comply with the Commission's holding company policies as explained and affirmed in D.00-02-046. In D.00-02-046, the Commission found that PG&E does not benefit from the non-regulated activities of PG&E Corporation or PG&E's affiliates and that it is reasonable to allow in utility rates only holding company charges that reflect services that are clearly needed by the utility and that are provided efficiently, without duplication of effort. ORA maintains that PG&E's holding company cost allocations result in a significantly overstated A&G expense forecast, by including in the forecast costs for services that are not clearly needed by the utility as well as costs for services that provide no benefit to the utility. (Exhibit 306, p. 1-3.) ORA recommended adjustments include, but are not limited to the following:

· Allocating 100% of the Holding Company General Counsel Department costs to affiliates to reflect that the Utility has its own SVP General Counsel and a Deputy General Counsel. (Exhibit 306 p. 7-17.)

· Reducing PG&E's proposed allocation of Holding Company Law Department costs to the Utility from 75.98% to 20%. (Exhibit 306 p. 7-24.)

· Allocating 100% of the Holding Company CFO Department labor and material costs to affiliates to reflect the fact that PG&E has its own CFO and does not need to purchase financial management services from the utility. (Exhibit 306 p. 8-6.)

· Reducing the utility allocation of the Holding Company Human Resources department from PG&E's allocation of 89.5% to 28.32% to reflect the actual activities of the department.

· Reducing the utility allocation of Corporate Accounting costs by 68.85% to reflect the fact that the need for the Holding Company stand-alone general ledger, consolidated SEC reporting, and separate Holding Company budget reporting functions are incremental requirements directly attributable to the formation of the Holding Company. (Exhibit 306 p. 8-15.)

ORA also noted that PG&E expects to continue to incur substantial bankruptcy litigation and POR costs in TY 2003. Although PG&E's stated policy is to charge incremental bankruptcy and POR costs to shareholder funded below-the-line accounts, ORA believes that PG&E failed to allocate all of the incremental costs attributable to its bankruptcy proceeding and POR implementation activities to the below-the-line accounts. ORA also recommended several adjustments to the below-the-line category related to the costs of public relations activities designed to enhance PG&E's general corporate reputation, and costs associated with influencing elections and the decisions of elected government officials. ORA's recommended allocation factors allocate $5.5 million more to the below-the-line accounts for utility departments than PG&E's request. Examples of ORA's allocation adjustments include:

· Increasing the allocation of the Media Relations Department costs to the below-the-line category by 15.73% to remove incremental POR costs and the costs of corporate image enhancement.

· Allocated 58.28% of the VP Governmental Relations Department's costs to the below-the-line category to eliminate political advocacy, image enhancement and incremental bankruptcy costs.

· Increased the below-the-line allocation of the Local Governmental Relations Department to 31.4%.

· Allocated an additional 35.6 % of the External Relations Department's cost below-the line to reflect the costs of political advocacy and image enhancement. ORA notes that key activities of the External Relations Department include organizing support from individuals and organizations for company initiatives such as the POR, GRC and legislation.

ORA also argued that PG&E's capital allocations in its TY 2003 forecast are inconsistent with the incremental cost approach adopted in D.00-02-046 and significantly overstate A&G expense. ORA explained that under the adopted approach, the criterion for determining incremental costs is the extent to which a department's activities would be reduced in the absence of ongoing construction activities. (D.00-02-046, mimeo., p. 287.) ORA recommended specific adjustments to utility department labor and materials costs resulting in the allocation of $5.6 million more ($2000) to capital than PG&E's factors. Examples of specific adjustments include:

· ORA allocated 14.42% of the Benefits Department cost to capital to reflect the fact that the activities in this department are a function of employee levels. Construction activities accounted for 31.3% of PG&E's total labor costs in 2002; therefore, PG&E's workforce would be approximately 30% lower in the absence of its ongoing construction program.

· ORA allocated 14.29% of the Compensation Department cost to capital to reflect the fact that a reduction in construction activities would reduce PG&E's workforce, resulting in a reduction in the compensation workload. PG&E allocated 0% of this Department's cost to capital.

· ORA also argued that PG&E made an error in its allocation of PIP costs to construction, resulting in an overstatement of A&G expenses by $10.6 million. PG&E allocated 6.76% of its 2003 PIP forecast to capital. ORA argues that a correct application of the labor burden procedure (using O&M labor to allocate costs) results in the capitalization of approximately 32% of PIP costs at the target payout of 1.0 in 2002.

ORA also recommended several forecast adjustments related to labor, materials, and contract amounts. The labor adjustments reflect ORA's position that PG&E's forecasts for 9 of the 42 utility departments reflect staffing levels that significantly exceed historical and current levels. For each staffing adjustment, ORA also made a corresponding adjustment to materials.

7.4.2 Settlement Amount

The Distribution Settlement would adopt overall (total utility) A&G expense of $585 million ($2000). This compares to PG&E's total A&G forecast of $735.8 million as presented in the Joint Comparison Exhibit. (Exhibit 100, p. A-24) and ORA's recommended overall A&G expenses of $540 million.

The Settlement amount for A&G expense does not include PG&E's request for the pension contribution.¹⁹ After adjusting to remove the amount associated with PG&E's pension fund request, the Distribution Settlement represents a $64 million reduction from PG&E's request in total A&G and an increase of $45 million in costs compared to ORA's position.²⁰ The Settlement would also adopt specific capitalization rates for the A&G accounts to which they apply.²¹

7.4.3 Discussion

The difference between the agreed-upon amount for A&G expenses, $585 million, and the parties' positions, is extremely large, ranging from a $64 million reduction to PG&E's request to a $45 million increase in ORA's recommendation. That the Settling Parties were able to bridge this gap and reach agreement is remarkable.

While ORA's and TURN's analyses have cast substantial doubt on the reasonableness of PG&E's A&G forecast, all of ORA's and TURN's recommendations are not equally persuasive. The primary areas of concern to ORA and TURN include: (1) the allocating of holding company costs to the utility, (2) the allocation of below-the-line costs to the utility, (3) the request for ratepayer funding of 100% of the PIP costs, (4) certain of PG&E's allocations to capital, and (5) forecast adjustments.

PG&E admits that its forecast includes the costs of certain items not adopted in PG&E's last GRC (e.g. a portion of Performance Incentive Plan payments and certain support costs billed by PG&E Corporation) but argues that its showing in the instant proceeding clearly demonstrates that these costs are reasonable.

ORA does not question that the holding company provides, in certain areas, services that are both needed by the utility and that benefit the utility, but nevertheless contends that certain adjustments are necessary. PG&E takes issue with ORA's function-by-function adjustments to PG&E's holding company allocations. PG&E contends that ORA's analysis is fundamentally unfair because it calculates the incremental costs that would be avoided but for the holding company without giving due consideration to the benefits created by the formation of the holding company. In rebuttal, PG&E provided general estimates of the cost that the utility would have to incur to replace the services provided by the holding company if the holding company did not exist. Based on these estimates, PG&E argues that the existence of the holding company provides substantial benefits in terms of economies of scale.

When tested under cross-examination, certain of PG&E's estimates were not convincing. For example, when asked why the utility would need to add four individuals in the relocation services section of the Human Resources department to perform less work than is currently being performed by three individuals in the holding company Human Resources department, PG&E witness Clark simply responded that four individuals represents the staffing level initially transferred to the holding company in 1998, (RT 2510:8-9) without adjusting for potential changes in the number of employees since 1998. Furthermore, PG&E failed to provide any evidence corroborating its estimates.

We also question PG&E's contention that because it cannot have shared services among subsidiaries without consolidating subsidiaries, and because PG&E benefits from the efficiencies associated with those shared services, PG&E should share in the cost of the consolidation. We have already held that the utility does not benefit from the existence of the Holding Company. This fact has become even more evident in light of the unwillingness of the Holding Company to provide any financial support to the utility during the energy crisis.

We have held that it is appropriate for the utility to pay for those services provided by the Holding Company that are both needed, and that are provided efficiently, without duplication of effort. The "consolidation" services provided by certain departments fail the first test, i.e., they are not independently needed by the utility.

PG&E also argued that ORA's analysis unfairly confuses titles with functions. We agree with the general premise of PG&E's argument, that is, the fact that two individuals carry the same title or work in departments with the same name does not mean that those individuals perform the same tasks or functions, but note that the burden remains on PG&E to demonstrate that a title is indeed all they share.

Notwithstanding the concerns raised by ORA and TURN's initial testimony, we are willing to approve the A&G element as part of the broader Distribution Settlement. It is clear that the parties have each made substantial concessions relative to their individual positions in order to achieve the Settlement. One of the factors we use in evaluating the reasonableness of a settlement is whether the interests of the parties supporting the settlement are fairly reflective of the interests of the parties that would be affected by the settlement. In this case, the Distribution Settlement commands the support of all parties taking positions on PG&E's TY 2003 revenue requirement request, including those parties challenging PG&E's A&G forecast. Moreover, the Settling Parties represent residential and small commercial customers of PG&E; the parties that are likely to be the most sensitive to any revenue or rate increases. When parties with very different viewpoints agree on a solution to a problem, it is an indication that it is a reasonable proposal.

Because the A&G settlement represents a sizable reduction to PG&E's request, that is part of a broader settlement, representing various trade-offs by all the parties, we find it reasonable in light of the record.

7.5 Unbundling of A&G Expenses

In Section 3.1.4 of the Agreement, the Settling Parties agree that it is more efficient to litigate common costs like A&G expenses only once, in the GRC, and then to use the results in other CPUC proceedings, rather than re-litigating these common A&G expenses multiple times. The Settling Parties request that A&G expenses allocated to Unbundled Cost Categories (UCCs) adopted in this 2003 GRC be used in determining the A&G expenses in related proceedings in 2003 and future years until the 2007 test year GRC, if those proceedings would otherwise require litigation of A&G expenses. The Settling Parties maintain that this approach would ensure consistent recovery of the A&G expenses approved in this GRC.²² The affected UCCs and related proceedings are:  Gas Transmission (Gas Accord II and Gas Accord III); Humboldt (Nuclear Decommissioning Cost Triennial Proceeding); Gas Public Purpose Programs (PPP) and Electric PPP (various gas and electric PPP filings.)

In addition, the Settling Parties agree that, to the extent that Commission decisions in 2004 through 2006 on PPP include less A&G expense than the amounts allocated to PPP UCCs in this Agreement, any shortfall would be recovered through GRC distribution attrition revenues. The Settling Parties agree that the revenue requirements included in this Agreement are sufficient to address the issue of a possible shortfall in electric PPP revenues in 2003.²³

We accept the Settling Parties' approach as reasonable; however, we remind the Parties that we cannot bind future Commissions to this approach. Pub. Util. Code § 1708 provides that, with proper notice and opportunity to be heard, a future Commission may rescind, alter, or amend previous decisions to the extent deemed necessary to provide for just and reasonable rates.

7.6 Nuclear Decommissioning Trust Administrative Fees

PG&E's Application included $2.97 million of nuclear decommissioning trust fund administrative fees charged to A&G Account 930, Miscellaneous and General Expense. TURN initially argued that this expense should be directly assigned to a "nuclear decommissioning" UCC rather than the "generation UCC where PG&E and ORA have assigned it." (Exhibit 405, p. 15.) PG&E explained on rebuttal that TURN's recommendation would effectively eliminate PG&E's opportunity to recover these costs through 2005 by shifting them to an already completed proceeding, A.02-03-020, which did not include them.

In response to PG&E's rebuttal, TURN proposed and PG&E agreed to a "Joint Recommendation of PG&E and TURN--Account 930 Nuclear Decommissioning Trust Fund A&G Expenses." (Exhibit 426.) The joint recommendation provides that the $2.97 million ($2000) in this cost category will remain classified to generation UCCs in this GRC. In its next triennial nuclear decommissioning proceeding, PG&E will include this cost as a nuclear decommissioning cost in its application, and will include in its application in that case a provision to reduce the generation revenue requirement by an equal and offsetting amount.

PG&E and TURN agree to jointly propose a class allocation of these nuclear decommissioning trust fund expenses in Phase 2 of this GRC that is consistent with the allocation of nuclear decommissioning costs.

The Distribution Settlement adopts the joint recommendation that resolves the issue raised by TURN. The Joint Recommendation is a reasonable compromise of the positions presented by the Settling Parties, and is fully supported by the evidence in the record.

7.7 Distribution Operations and
Maintenance Expense

Distribution Operations and Maintenance (O&M) expenses cover the cost of operating and maintaining PG&E's electric and gas distribution systems. PG&E requested distribution O&M expenses of $399.873 million electric and $119.940 million gas. ORA recommended O&M expenses of $382.806 million for electric distribution and $116.949 million for gas distribution. (Exhibit 100, pp. 2-4; 2-15.)

ORA recommended adjustments to PG&E's requested electric distribution O&M expenses in the following MWCs: Operate Distribution System (MWC BA), Line Patrols and Inspections (MWC BF), Preventive Maintenance (MWC BG), Work Required of Others (MWC EW), Test and Treat and Pole Restoration (MWC GA), and Vegetation Management (MWC HN). (Exhibit 100, pp. C-1 to C-3.) ORA requested adjustments to PG&E requested expenses for gas distribution O&M in the following MWCs: Catholic Protection (MWC DG), Install Meters and Devices (MWC EY), Preventative Maintenance (MWC FH), and Perform Maintenance to Correct Failure (MWC FI). (Exhibit 100, C-4-C-5.) ORA stated that its adjustments were focused on MWCs for which PG&E had requested "dramatic" increases in incremental spending without providing sufficient support for its requests. ORA also recommended adjustments in areas where PG&E "proposed additional funding for maintenance activities that were previously funded." (Exhibit 303, p.6-8.)

TURN recommended further reductions compared to the expense level recommended by ORA of approximately $8.85 million ($2000 FERC). TURN proposed expense reductions in the following areas: CAISO-Ordered Stage 3 Events (MWC BA), Corrective Maintenance (MWC BH), and Customer Connections (MWC EV). ORA and TURN disagreed with some of PG&E's underlying estimation methodologies based on anticipated units of work and forecast unit costs, and differed with PG&E on how to use historical data to forecast future expenses.

The Distribution Settlement adopts 2003 distribution O&M expenses of $391.5 million electric and $118.5 million gas ($2000 FERC). The Distribution Settlement also adopts a Vegetation Management expense (included in the above electric total) of $124.7 million. This amount includes funding for the Vegetation Management Quality Assurance Program, but eliminates the requirement adopted in D.00-02-046 that shareholders share in the cost of this program. The one-way balancing account for Vegetation Management and the associated Quality Assurance Plan would continue in effect, as would the tree removal program. The $124.7 million ($2000 FERC) for the Vegetation Management account represents a compromise between PG&E's position of $126.857 million and ORA's position of $118.122 million.

The Settling Parties' agreement on O&M expenses falls between the litigation positions of each of the Settling Parties. The settlement represents a reasonable compromise, at a high level, between the positions held by the Settling Parties on specific detailed issues. The Settling Parties state that their high-level agreement is not intended to imply any specific resolution of issues at a detailed level, with the exception of the one way balancing account for Vegetation Management, nor it is intended to create any future precedent.

7.8 Customer Accounts and
Services Expense

PG&E's Customer Accounts and Services activities include the processes, technology, and people that together form the vital communication link between PG&E and its 4.7 million electric and 3.8 million gas customers. PG&E TY 2003 forecast for distribution Customer Accounts expenses was $206.025 million electric and $159.492 million gas, compared to ORA's estimate of $194.982 million electric and $151.129 million gas. ($2000 FERC.)

PG&E's forecast for distribution Customer Services expenses was $3.662 million electric and $3.618 million gas, whereas ORA estimated $1.912 million electric and $3.515 million gas.

TURN and Aglet also conducted detailed analysis of PG&E's proposed Customer Accounts and Services expenses by MWC. TURN recommended reductions in PG&E's Customer Accounts and Services expenses of approximately $16.1 million.²⁴ A portion of these reductions overlaps with the recommendations of ORA and Aglet. Aglet recommended reductions in PG&E's Customer Accounts and Services expenses of approximately $4.2 million;²⁵ a portion of these reductions overlap with the recommendations of ORA and TURN. TURN proposed expense reductions in the following areas: Customer Retention (MWC FK), Utility Operations (UO) Internet Projects (MWC AB), and Customer Information Systems (MWC BJ). Aglet proposed expense reductions in the following areas: Meter Reading (MWC AR), Customer Retention (MWC FK), and Economic Development (MWC FK).

The most significant areas of controversy affecting the forecast of 2003 expense included: the forecast ongoing expense required to operate PG&E's Customer Information System; whether PG&E should recover in rates the costs of customer retention programs; whether PG&E should recover in rates the costs of programs to attract customers to PG&E's service area in conjunction with state and regional development efforts; whether PG&E's per customer cost to serve Commercial, Industrial and Agricultural customers is higher than Southern California Edison Company's; and the amount of overtime PG&E will need, principally in the customer services area, for 2003 and beyond.

The Settlement adopts Customer Accounts distribution expenses of $199.9 million electric and $154.7 million gas and Customer Services distribution expenses of $1.363 million electric and $3.483 million gas. The Customer Services forecast reflects a zero expense amount in Account 912 for customer retention and economic development.

The Settling Parties' agreement on Customer Accounts and Services expenses represents a compromise from the parties' litigation positions and is fully supported by the record developed in this proceeding.

7.9 Line Extension Administration

PG&E requested $10.163 million for Major Work Category (MWC) EV (Customer Connection Expenses) ($5.590 million allocated to the Electric Distribution and $4.573 million allocated to Gas Distribution). TURN proposed that PG&E recover $4.332 million, arguing that the "majority of costs contained in this expense account are for tasks associated with connecting new customers to PG&E's system and, therefore, should be subject to the line extension allowances (and considered as a portion of PG&E's forecast for MWC 16)." (Exhibit 401, p. 4.)

The Distribution Settlement provides that PG&E will, beginning in 2004, charge processing expenses to new customer connection applicants in a manner to be determined by PG&E. In addition, non-residential customer revenue estimate expenses incurred in 2004 and subsequent years will be charged to new customer connection applicants in a manner to be determined by PG&E. Finally, new customer connection process improvement expense incurred in 2004 and in subsequent years will be included in the overheads charged to all new application projects.

This resolution is consistent with the record and represents a reasonable compromise of the litigation positions of TURN and PG&E.

7.10 Uncollectibles

PG&E uses an "uncollectibles factor" to forecast the expense associated with uncollectible utility revenues. This forecast is included in FERC Account 904. The uncollectibles factor the Commission last adopted for PG&E is 0.267 %. In this case, PG&E proposed a lower factor of: 0.250 %. PG&E calculated its proposed factor using the five-year average from 1997-2001, 0.209 %, and adding an adjustment of 0.041 % to take into account the "poor state of the economy as evidenced by the increase in the number of bankruptcy filings that have occurred in recent years." (Exhibit 6, p. 4-7 to 4-8.)

Aglet recommended a factor of 0.182 percent, an amount equal to the recorded, unweighted three-year average for 1999-2000. Aglet argued PG&E's adjustment of 0.041 % is unreasonable because PG&E had not demonstrated that an increased number of bankruptcy filings indicate that more people are unable to pay their bills.

In Section 3.4 of the Distribution Settlement, the Parties agree to an uncollectibles factor of 0.200 %. This agreement is reasonable and is fully supported by the record.

7.11 Depreciation

The purpose of depreciation expense is to distribute the recovery of the original cost of fixed capital assets less estimated net salvage over the useful life of the assets. Depreciation expense is a function of plant in service, the rate at which various classes of plant are expected to depreciate (service lives), and estimated net salvage. Public Utilities Code Section 795 empowers the Commission to "ascertain and by order fix the proper and adequate rates of depreciation of the several classes of property of each public utility."

PG&E requested that the Commission use the depreciation parameters developed in its depreciation study to determine the electric and gas depreciation rates. The depreciation study proposed new depreciation parameters (i.e., average service lives, curve type, and net salvage percents) based on a review of PG&E's historical records, company practices with respect to plant maintenance, and expected future events that may affect service life and net salvage. Based on the depreciation study, PG&E proposed changes to net salvage rate, average service life, and mortality curve.

The depreciation parameters proposed by PG&E translate into a TY 2003 forecast of $564.7 million for electric distribution-related depreciation expense, a 49.4 % increase over the $377.9 million level adopted in PG&E's last GRC. PG&E also forecast $179.4 million for gas distribution-related depreciation expense, a 15.1 % decrease in the $211.3 million adopted previously.

TURN and ORA also presented testimony on depreciation issues. ORA recommended that the Commission reject PG&E's proposed changes to electric distribution net salvage percentages.²⁶ Instead, ORA argued, the net salvage percentages for electric distribution should remain at their currently authorized levels. ORA's position reflected its concern regarding PG&E's accounting treatment of monies received from third parties, crediting reimbursed retirements to the cost of replacement, rather than including it with net salvage. (Exhibit 304, p.17-8.) ORA's position also reflected its concern that not only are the proposed net salvage percentages too high, but currently authorized net salvage percentages may also be too high. To explain the basis for its concern, ORA provided the following comparison of the net salvage received in rates to the net salvage actually spent over the ten-year period from 1993-2002:

Table 4

Net Salvage Dollars Received vs. Actually Spent²⁷

(Dollars in thousands)

	1993	1994	1995	1996	1997	1998
Net Salvage Received in Rates
Electric Distribution	$84,450	$89,808	$94,834	$66,308	$71,564	$77,121
Net Salvage Actually Spent
Electric Distribution	($2,046)	$9,517	$8,760	$1,578	$39,505	$22,250
(Continued)	1999	2000	2001	2002	Total
Net Salvage Received in Rates
Electric Distribution	$82,142	$86,169	$91,361	$96,771	$840,528
Net Salvage Actually Spent
Electric Distribution	$20,353	$21,439	$29,463	$43,652	$194,471

ORA agreed with PG&E's proposed changes to its net salvage percentages for the gas distribution function because they result in a decrease in depreciation expense.

TURN presented testimony addressing PG&E's proposed net salvage values, average service lives and survivor curves. With respect to net salvage values, TURN raised concerns regarding: (1) the use of PG&E's SAP accounting system as a basis for making net salvage proposals; (2) PG&E's accounting treatment of "reimbursed retirements" (3) the allocation of replacement costs between installation of new plant and removal of replaced plant; (4) the effect of economies of scale on historic and future costs of removal; (5) the effect of the additional costs incurred for emergency replacements on historic and future costs of removal; (6) the effect of the "investment mix" of historic retirements as compared to the current plant in service on the analyses of service life and net salvage; (7) the occurrence of instances of negative gross salvage in certain years; (8) consideration of future inflation when estimating future net salvage; and (9) the effect of overtime pay and outside contractor costs on the historic and future costs of removal. (Exhibit 439, pp. 14-41.)

TURN recommended adjustments to net salvage for 14 mass property accounts, arguing that PG&E's proposals regarding net salvage values were, in many instances, "much more negative than the industry and almost always more negative than the industry average." (Exhibit 439, p. 5.) TURN also recommended longer average service lives for 5 plant accounts, arguing that PG&E's depreciation study "often ignored the best fitting statistical results of its life analyses or gave weight to insufficiently supported expectations from in-house technical operational personnel to arrive at inappropriate average service lives." (Id.)

Relative to PG&E's request, ORA's and TURN's depreciation proposals would decrease PG&E's distribution depreciation expense by $102 million and $172 million, respectively. In Section 3.6 of the Distribution Settlement, the Settling Parties agree to the depreciation parameters resulting from ORA's position on electric, gas, and common plant depreciation.²⁸

7.12 Rate Base

PG&E's revenue requirement includes "return on rate base," an amount that compensates PG&E's shareholders for their investment in PG&E's plant and equipment. The calculation of PG&E's rate base has a number of steps, starting with determining the correct beginning plant balance to which capital additions will be added during the test year. The working cash calculation and the capital additions calculation, both components of the rate base calculation, are addressed in other sections of this decision. Ultimately, the rate base must be assigned to UCCs, with residual common plant allocated to all UCCs, including gas and electric distribution and generation UCCs.

PG&E developed its 2003 rate base forecast using 2001 recorded plant as the starting point then adding forecast capital additions for 2002 and 2003. ORA recommended use of 2002, rather than 2001, recorded plant as a starting point. PG&E agreed with ORA's recommendation on rebuttal. (Exhibit 24, p.6-3.)

PG&E and ORA also both advocated the use of O&M labor factors to unbundle residual common plant and reserve, but initially disagreed over which data to use in the calculation. During the hearings, ORA and PG&E agreed to use 2002 recorded adjusted O&M labor factors.

Section 3.7 of the Distribution Settlement adopts recorded 2002 plant as the starting point for calculating 2003 rate base and uses 2002 recorded adjusted O&M labor factors to allocate residual common plant and reserve.

This agreement is reasonable and is fully supported by the record.

7.13 Capital Additions

PG&E's rate base has several components, the largest being plant and depreciation reserve. After establishing the year-end 2002-plant balance, 2003 net weighted average capital additions must be added to determine a 2003 weighted average plant balance. Those capital additions associated with common, general, and intangible plant must then be allocated to all UCCs, including the electric and gas distribution and generation UCCs.

PG&E prepared its forecast of 2003 net weighted average capital additions as follows: First, PG&E prepared a forecast of 2003 capital expenditures by month. This process includes subtracting a forecast of certain customer contributions that offset PG&E's capital expenditures (including joint pole receipts). Second, PG&E converted capital expenditures to capital additions. For large projects, this conversion was based on expected dates of operation. For smaller, on-going expenditures, expenditures may be converted to additions as spent. Third, PG&E converted gross capital additions to net additions (net of retirements) based primarily on ratios developed through analysis of historic information. Finally, PG&E used the monthly forecast of net capital additions to calculate a weighted average for the year.

ORA analyzed PG&E's forecast step-by-step, making specific recommendations on many aspects of the forecasting process, then recommending its own forecast. During the course of rebuttal and hearings, PG&E and ORA came to agreement on many of the issues raised by ORA.

By the time the Comparison Exhibit was filed on August 8, 2003, the scope of disagreement had narrowed to only a few issues: (1) PG&E's and ORA's differing forecasts of electric and gas distribution and common capital expenditures; (2) PG&E's and ORA's different methods for transferring recorded 2002 Construction Work in Progress (CWIP) to electric and gas distribution and common plant in service in 2003; (3) PG&E's and ORA's different operative dates for various distribution and common projects; and (4) PG&E's and ORA's different methods of forecasting weighted average gas distribution plant.

Aglet also raised an issue regarding the forecast of joint pole receipts (representing the joint pole owner's share of capital projects). TURN joined Aglet in the recommendation that PG&E's forecast of joint pole receipts should be $21 million, an increase of $4.1 million over PG&E's initial forecast.

In the Distribution Settlement, the parties agreed that net weighted average capital additions for 2003 ($2003) will be $292 million for the electric distribution UCCs and $89.2 million for the gas distribution UCCs. The Settling Parties further agreed that the above net capital additions reflect a 2003 forecast for joint pole receipts (representing the joint pole owner's share of capital projects) of $21 million.

The net weighted average capital additions for 2003 adopted in the settlement assume the incorporation of higher capitalization rates for A&G and reflect an allocation of net weighted average additions for common, general and intangible plant of $17.4 million for the electric distribution UCCs, $10.9 million for the gas distribution UCCs, and $7.765 million for the electric generation UCCs.

PG&E forecast 2003 net weighted average capital additions for the electric distribution UCCs at $351.335 million, compared to ORA's forecast of $223.738 million. The Settling Parties compromised on this issue, resulting in net weighted capital additions of $292 million.

PG&E forecasts 2003 net weighted average capital additions for the gas distribution UCCs at $107.767 million, compared to ORA's forecast of $72.786 million. The Settling Parties compromised and agreed to $89.2 million for gas distribution. Embedded in these forecasts were allocations of common, general, and intangible plant to the electric distribution UCCs of $17.392 million for PG&E and ($0.386) million for ORA, and to the gas distribution UCCs of $10.889 million for PG&E and ($1.326) million for ORA.

PG&E and ORA reached agreement on the 2003 net weighted average capital additions for generation assets in the Generation Settlement. However, the Comparison Exhibit reflects the unresolved issues concerning the amount and allocation of common, general, and intangible plant to the generation UCC. PG&E's forecast allocation of 2003 net weighted average capital additions for common, general, and intangible plant to the generation UCCs was $7.765 million, compared to ORA's forecast of $6.042 million.²⁹

The Distribution Settlement adopts PG&E's forecast and allocation of common, general, and intangible plant and compromises between PG&E's and ORA's positions on electric and gas distribution plant. In addition, the perspective offered by Aglet and TURN on joint pole receipts was recognized in the development of the electric distribution plant forecast. Based on the record developed in this GRC, the Settling Parties were able to agree to a reasonable compromise that establishes 2003 net weighted average capital additions for the electric and gas distribution and generation UCCs, as well as the allocation of common, general, and intangible plant to the electric and gas distribution and generation UCCs.

7.14 Working Cash

The working cash forecast consists of two elements: (1) working funds needed for PG&E's daily operations; and (2) funds needed to cover operating expenses paid before PG&E receives customer revenues. These funds are included in PG&E's rate base and therefore affect the computation of the amount of operating income.

In their litigation positions, both ORA and TURN recommended a significant further reduction of approximately $99 million combined electric and gas distribution working cash based on PG&E's accrued vacation liability account. TURN also recommended that interest-bearing customer deposits should be an offset to rate base, resulting in a further reduction of $116 million.³⁰ In addition, TURN suggested two relatively small adjustments reducing accounts receivable ($3.406 million) and accounts and tax collections payable ($1.678 million).

In Section 3.9 of the Distribution Settlement, the Settling Parties agree to reduce working cash by $63 million electric and $37 million gas ($2003) relative to the amount in PG&E's Comparison Exhibit, representing a compromise from the litigation positions of each of the Settling Parties. In the Comparison Exhibit, PG&E forecast working cash of $74.626 million and $41.575 million ($2003) for electric and gas distribution, respectively. ORA forecasts working cash of $6.200 million and $2.864 million ($2003) for electric and gas distribution, respectively.

7.15 Taxes

Although a broad range of tax issues was addressed in PG&E's testimony, and in the testimony of ORA and TURN, only a small number of issues remained unresolved by the completion of rebuttal and filing of the Comparison Exhibit. The Distribution Settlement (Section 3.10) adopts the following agreements:

1. Settling Parties agree to use PG&E's method for calculating vehicle clearing depreciation for purposes of determining income taxes,

2. Settling Parties agree to recognize the current year deduction for capitalized A&G overheads for the calculation of test year income taxes; and

3. Settling Parties agree that the effect of the 50 % bonus depreciation, a change in the tax code, will not be recognized for the calculation of 2003 income taxes.

In addition to the tax issues addressed by the Distribution Settlement, there were a number of uncontested tax issues presented in PG&E's testimony, as well as a number of tax issues that were initially contested but were resolved by the time the Comparison Exhibit was filed. These issues are not specifically addressed in the Distribution Settlement, but they are included in the underlying assumptions used to calculate the revenue requirements associated with the Settlement.³¹

Only two tax issues remained contested by ORA: PG&E's income tax adjustments for certain past capitalized A&G overhead costs, and whether an increase in "Bonus Depreciation" as a result of legislation enacted earlier this year (2003) should be reflected in the test year revenue requirement computation.

Before 2000, PG&E's practice was to capitalize certain A&G costs in the same amount for both tax and book purposes. Beginning in 2000, PG&E took advantage of a Treasury Regulation that permits a taxpayer, under certain circumstances, to take an immediate tax deduction rather than capitalizing the A&G costs.³² ORA took the position that PG&E's tax forecast "does not reflect any deduction for the A&G overheads that can be deducted under the de minimis rule," and therefore PG&E's tax expense is overstated.

In 2003, PG&E's tax return will reflect deductions pertaining to: (1) retroactive application of the de minimis rule to the period 1989 to 1999; and (2) and current application of the de minimis rule to certain, current A&G overhead costs. PG&E agreed with ORA that this annual "going forward" deduction for current A&G overhead costs should be reflected in the revenue requirement calculation.³³ PG&E's position in the Comparison Exhibit reflects the immediate deduction of these A&G costs for tax purposes. The Distribution Settlement provides that the deduction pertaining to the retroactive period should not be reflected in the revenue requirement calculation for 2003.

The Distribution Settlement represents a reasonable compromise of the positions held by the parties and is fully supported by the record developed in this proceeding. The retroactive application of the de minimis rule is the result of an Internal Revenue Service (IRS)-approved change in accounting methodology that PG&E instituted in 2000. The IRS permitted PG&E to implement this change not only for the future, but also to realize a deduction for the years 1989 through 1999. By law, PG&E was required to take this deduction over a four-year period beginning in 2000 through 2003. The final deduction installment of $11.32 million will occur during 2003; thereafter there will be no further "additional deductions" related to the 1989-1999 period. The $11.32 million relates to a period before the test year and is not representative of future conditions and therefore, by agreement of the Settling Parties, will not be included in the test year revenue requirement calculation.

The bonus depreciation issue was raised during ORA's cross-examination of PG&E's tax witness, and concerns a new provision of the tax code that became effective in May 2003. (TR 1439:18-27.) Therefore, the Settling Parties' agreement not to incorporate this change in the tax code in the 2003 revenue requirement calculation is consistent with the intent of the ACR issued February 13, 2003, to prohibit the use of 2003 recorded data.

7.16 O & M Labor Factors

The 1999 GRC Decision adopted the use of O&M labor factors to unbundle residual common costs that cannot be directly assigned based on cost causation. In this 2003 GRC, PG&E and ORA agreed that the same approach should be used, but did not agree on the specific O&M labor factors.

Initially, PG&E proposed using 2003 forecast O&M labor factors in unbundling. ORA disagreed with PG&E's proposal, suggesting that the Commission adopt O&M labor factors used in PG&E's electric transmission rate application made before the FERC on January 13, 2003 (PG&E's Transmission Owner (TO) 6 filing, ER03-409-000). (Exhibit 306, p. 1-25 to 1-26.)

In rebuttal testimony, PG&E proposed using 2002 recorded adjusted O&M labor factors. (Exhibit 22, p.4-2.) ORA agreed with PG&E's proposal during the hearings. (TR 3150: 3-8.)

Section 4.2 of the Distribution Settlement provides that 2002 recorded adjusted data shall be used to calculate the O&M labor factors used to unbundle common costs to UCCs in the revenue requirement calculation.

7.17 Other Operating Revenues

Other Operating Revenues (OORs) are revenues from transactions not directly associated with the transportation or sale of gas and electricity. OORs are estimated separately and subtracted from the revenue requirement in the rate design process because OORs reduce the amounts that must be collected from customers in rates.

PG&E forecast electric and gas distribution-related OORs of $65.004 million and $15.992 million, respectively,

In Section 4.3 of the Agreement, the Settling Parties agree that CPUC-jurisdictional distribution OORs shall be $67.3 million electric and $16.3 million gas ($2003).

Initially, ORA and TURN both questioned PG&E's OOR forecast. ORA forecasted OOR of $68.879 million electric and $16.642 million gas. ORA's recommended adjustments to PG&E's forecast were based on its position with regard to insufficient funds (NSF) fees.

ORA also took issue with PG&E's OOR forecast for three accounts: 454 (Rent From Electric Property), 488 (Gas Miscellaneous Service Revenues), and 493 (Rent From Gas Properties). The revenues recorded within these accounts fluctuate from year to year, as do all of the OOR accounts. Given these fluctuations, PG&E has historically based its OOR estimates on the last recorded year. Based on the history of fluctuation in the accounts, ORA forecasted that the revenues should be increased by 11% in the case of Accounts 454 and 493, and 2% for Account 488.

In errata, TURN withdrew its recommendation to increase OORs by $2.1 million to account for higher joint pole revenues; TURN now supports Aglet's recommendation on the issue of joint pole receipts.

The Distribution Settlement reflects a compromise of the positions of the parties. It recalculates the OOR forecast based on the agreement of the parties on the NSF fee, and represents a compromise of PG&E's and ORA's positions on forecasts of rent from properties and miscellaneous service revenues, items that fluctuate considerably from year to year. This compromise result is fully supported by the record created on this issue.

7.18 New Customer Connections
and E-Net Costs

PG&E requested that the Commission adopt two-way balancing accounts for: (1) capital expenditures related to new customer connections in MWC 16 (Electric Distribution Customer Connects) and MWC 29 (Gas Distribution Customer Connects), and (2) the costs related to PG&E's processing of customers' requests to connect self-generation equipment to PG&E's distribution system (also known as E-Net applications) included in MWC EW on the basis that these items are difficult to forecast and fluctuations expenditures represent risk to PG&E. ORA recommended against adoption of these balancing accounts because ORA finds the variance between PG&E's and ORA's forecasts to be minimal, the Commission has a track record of adopting expense estimates knowing that actual spending will likely differ, and because balancing account treatment represents a move to micromanaging PG&E's business.

The Distribution Settlement adopts ORA's position regarding balancing accounts for new customer connection and E-Net costs.

7.19 Insufficient Funds Fee

PG&E currently charges a $6.00 fee to those customers whose checks are returned because they have insufficient funds to cover the checks. This charge is known as an NSF (Non-Sufficient Fund) fee. PG&E's $6.00 NSF fee for returned checks was set in 1995. In this 2003 GRC, PG&E proposed to increase its NSF fee to $10.00 based on an analysis demonstrating that PG&E's NSF processing costs are $10.54. (Exhibit 3, p.9-3, Table 9-1.)

ORA and TURN both offered testimony on this issue. Neither party challenged PG&E's cost analysis, but each party used a different rationale to recommend NSF fees. ORA proposed increasing the NSF fee by only $2.00 to "mitigate the impact on customers who pay the NSF fee." ORA stated that its proposal for an $8.00 NSF fee was not based on PG&E's actual costs of dealing with bounced checks. (TR 3422:16.) Rather, ORA's proposal was motivated by concern for low-income customers who bounce checks.

TURN proposed a variable fee derived from a $6.50 base charge plus one % of the amount of the returned check. PG&E presented an analysis showing that TURN's proposal could result in charging check bouncers more than PG&E's actual costs. PG&E also expressed concern that a variable NSF fee might confuse customers, and that a variable fee would require substantial programming changes to the CIS and result in additional administrative costs.

The Settling Parties agree in Section 4.5 that PG&E should increase the NSF fee for returned checks from the current $6.00 to $8.00. The agreement to increase PG&E's NSF fee to $8.00 represents a reasonable compromise that acknowledges PG&E's cost study demonstrating that PG&E's costs of handling bounced checks are higher than the current $6.00 fee, while also acknowledging the concern that the new fee not present an undue hardship for low-income customers.

7.20 Public Utilities Code Section 739.10

The ACR directed PG&E to submit testimony concerning how it intends to comply with Public Utilities Code Section 739.10 (added by Stats. 2001, 1st Ex. Session, Ch.8, Sec. 10). Section 739.10 provides that "[t]he Commission shall ensure that errors in estimates of demand elasticity or sales do not result in material over or undercollections of the electrical corporations."

NRDC agreed with PG&E that to comply with Section 739.10, the Commission should establish a means by which to "track actual revenues compared to PG&E's Commission-approved revenue requirements, and make periodic true-ups to adjust for over- and undercollections." (Exhibit 750, p. 1.) Although NRDC would prefer one revenue adjustment mechanism rather than the two proposed by PG&E, as part of the Distribution Settlement, NRDC is willing to accept PG&E's proposal to utilize DRAM and UGBA to comply with Section 739.10.

Section 4.6 of the Distribution Settlement provides that PG&E will comply with Section 739.10 by implementing the Distribution Revenue Adjustment Mechanism (DRAM) and Utility Generation Balancing Account (UGBA)³⁴ as revenue adjustment mechanisms effective January 1, 2004, to ensure that PG&E recovers its authorized electric distribution and electric generation revenue requirements regardless of the level of sales.

7.21 Recovery of Expenses Associated
With the 20/20 Program

The ACR provided that the issue of recovery of costs associated with the delay in implementing PG&E's new Customer Information System (CIS) required to implement the 2002 "20/20" program is within the scope of the GRC and directed parties to address both the reasonableness of the costs and whether ratepayers or the DWR are to pay these costs.

Section 4.7 of the Settlement Agreement reads:

"The Settling Parties agree to allow recovery of the revenue requirement associated with $7.3 million in 2002 expenses incurred to implement the 20-20 program. PG&E will initially recover this revenue requirement from ratepayers by a debit entry to the Distribution Revenue Adjustment Mechanism (DRAM). The Settling Parties agree that DWR is ultimately responsible for these costs. PG&E will bill DWR the same amount debited to DRAM, and credit funds received from DWR to DRAM."

DWR submitted a memorandum on October 1, 2003, requesting that the Commission reject the portion of the Distribution Settlement concerning recovery of costs related to implementation of the 2002 customer rebate program known as the California 20/20 Rebate Program. DWR states that the Distribution Settlement is not consistent with the terms and conditions for reimbursement of 20/20 implementation costs established by DWR and accepted by the Commission in Resolution E-3770.

DWR explains that although it agreed to reimburse the utilities for "implementation and administration fees to the utilities to cover their reasonable costs of establishing and maintaining the procedures, systems, and mechanisms that are necessary to implement the 2002 California 20/20 Rebate Program," there is nothing in the record that establishes that these costs meet the requirements for reimbursement. DWR claims that PG&E has previously presented the costs it seeks to recover to DWR and requested payment and that DWR has already found these costs unreasonable and refused PG&E's request for reimbursement. DWR maintains that the practical effect of requiring DWR to reimburse PG&E for the costs associated with the implementation of PG&E's new CIS system would be to shift portions of the costs onto SCE's and SDG&E's ratepayers, since any reimbursement would be funded through DWR's Revenue Requirement determinations.

The Settling Parties respond that the record clearly establishes that the costs at issue should be addressed in this proceeding, citing the February 13, 2003, ACR. The Settling Parties argue that Exhibit 82 of its testimony provides clear and convincing evidence regarding how the 20/20 program caused significant delays in implementing PG&E's CIS. The Settling Parties maintain that the Commission should approve the Settlement, with the understanding that any further proceedings regarding the question of DWR's responsibility to reimburse PG&E for the $7.3 million will affect the provision of Section 4.7 of the Settlement, calling for crediting of amounts recovered from DWR.³⁵

7.21.1 Discussion

The ACR directed parties to review PG&E's testimony served with A.02-09-005 and A.02-11-017 and address both reasonableness and cost responsibility in their testimony in this proceeding. As directed, the Settling Parties have considered the costs in question as part of PG&E's TY 2003 forecast. As stated above, Section 4.7 of the Settlement provides that the cost associated with the delay in implementing the new CIS is $7.3 million. The Settling Parties further agreed that DWR should be responsible for these costs. However, the Settlement provides for the possibility that DWR may not reimburse PG&E by allowing PG&E to make a debit entry in the DRAM for $7.3 million, to be followed by a credit to the DRAM if and when PG&E receives reimbursement from DWR. In the event that DWR does not reimburse PG&E, PG&E ratepayers would bear the $7.3 million in cost associated with the delay in implementing the CIS.

The Settling Parties have agreed that the cost associated with the delay in implementing the new CIS is $7.3 million. The practical effect of the Settlement is that PG&E's ratepayers will bear the responsibility for this $7.3 million, either directly or indirectly. The terms and conditions under which DWR will reimburse the utilities for the utilities' reasonable costs for implementing and administering the 20/20 program were established in Commission Resolution E-3770 as follows:

"The Department will pay implementation and administration fees to the utilities to cover their reasonable costs of establishing and maintaining the procedures, systems, and mechanisms that are necessary to implement the California 20/20 Rebate Program. Utilities shall invoice the Department for payment of the implementation and administration fees. Invoices shall include reasonable documentation of the costs incurred. Utilities will exercise best efforts to track and keep costs within the amounts billed to the Department last year for the 2001 20/20 program. The Department must approve the invoiced amounts. The Department cannot unreasonably withhold approval." (Res. E-3770, dated June 6, 2002 Appendix 2, p. 2.)

We find that approval of the Settlement is reasonable because it resolves the following critical questions in a fair manner: (1) the appropriate cost associated with the delay, and (2) the ratemaking mechanism PG&E will use to recovery the costs from ratepayers. Whether or not the $7.3 million in question meets DWR's requirements for reimbursement is a question that only DWR has the authority to determine.

7.22 Customer Information System (CIS) Capital

PG&E presented evidence in this GRC forecasting expense and capital costs for a number of Information Technology (IT) projects, including the Enterprise Application Integration (EAI) Project,/ the Utility Operations Customer Care Project including maintenance of the mainframe computer, the CorDaptix CIS, CIS operations and maintenance, and Other IT Costs. The EAI and Other IT Costs requested above were neither addressed nor contested by any party in this proceeding.

The CIS is an information technology system that supports PG&E's customer billing, payment tracking, and bill settlement.³⁶ In this GRC, PG&E requested $176 million in capital expenditures for its CIS project, and $49 million³⁷ in associated O&M expenses.

ORA did not contest PG&E's capital expenditure request for the CIS project but did recommend an approximate $6 million adjustment to normalize the CIS O&M expenses.

TURN recommended that the Commission disallow $85.8 million (later revised to $73.5 million in errata) in capital expenditures. TURN also recommended that O&M expenses on the CIS system be held to 20% of the capital cost. Accordingly, they recommended a disallowance of $13 million in O&M for the CIS system.

The Distribution Settlement resolves the CIS O&M issues by adjusting PG&E's initial expense forecasts to account for ORA's recommendation regarding the timing of the expenses. According to the Settlement Agreement, this revised O&M expense estimate fully resolves ORA's and TURN's issues regarding CIS expenses.

To resolve TURN's recommended capital disallowance, the Settling Parties agreed that PG&E would include in its Results of Operations a $7 million credit against the revenue requirement through 2006. PG&E will retain the capital in its ratebase and continue depreciation using the applicable deprecation schedule for CIS.

7.22.1 Discussion

D.00-02-046 presents a full discussion of CIS funding to that time as follows:

"PG&E installed its CIS in 1964, and has made significant modifications to it in the intervening years. PG&E refers to this system, as currently being modified, as its Legacy CIS (LCIS)." "in the last decade, PG&E has made several attempts, since abandoned, to accomplish major upgrades to its CIS. In its 1990 GRC, PG&E received funding for its 1989-1993 CIS Rewrite project, a phased rewrite of the CIS. In 1993, after spending millions of dollars, PG&E abandoned this project. In 1994 and 1995, PG&E undertook development of a non-core CIS (nCIS) to meet the needs of PG&E's 200 largest customers using a client server technology. PG&E terminated the nCIS project in 1995, after completing the system analysis and design programming phases and beginning system testing. More recently, after issuing a Request for Proposal in August 1995, PG&E contracted with IBM to purchase and modify an off-the-shelf system in March 1996. PG&E spent 44.2 million on the IBM Integrity project in 1996 ad 1997, $34.2 million in 1996 alone. The IBM Integrity project was then terminated in 1997. Since 1997, PG&E has begun conversion of its CIS to a new technology called Genesis. The LCIS is currently operating in parallel with Genesis. PG&E anticipates completing the Genesis project in 2001, at which time the LCIS will be retired." (Mimeo., p. 388-389.)

In its TY 1999 GRC, PG&E reduced its CIS request for a base CIS from $146.7 million to $84.6 million to remove industry restructuring costs. The Commission concluded that the cost for a base CIS would range from a low of $30 to $50 million to a high of $88 to $14 million. The Commission concluded that the PG&E's requested $84.6 million fell within that range, but reduced PG&E's request by $10.8 million to reflect that certain costs associated with the IBM Integrity project that were not used and useful, resulting in an authorization of $73.8 million for a base CIS.

In this case, TURN argues that of the $176.3 million at issue, ratepayers have already funded $73.8 million in the 1999 GRC. Based on the record developed in this case, and TURN's showing that ratepayers have already funded a substantial portion of the total $176.3 million in the 1999 GRC, we would have been inclined to consider TURN's recommended disallowance for capital expenditures. However, we find the Distribution Settlement's compromise of a $7 million revenue requirement credit reasonable because it yields a dollar amount close to TURN's recommendation. If TURN's $73.5 million disallowance had been made to capital expenditures, it would have reduced the 2003 revenue requirement by approximately $7.6 million.

We agree with the Settling Parties that this outcome is reasonable, and fully supported by the record in this GRC, particularly as part of the broader Settlement. As set forth in Section 4.8 of the Settlement, PG&E shall include in its results of operations a $7 million credit against the revenue requirement (which will be allocated among PG&E's functions using the allocation method for the CIS system). The $7 million adjustment will extend through 2006 under the attrition method in the Settlement. PG&E will retain the capital in its rate base and continue depreciation using the applicable depreciation schedule for CIS. In the 2007 GRC, PG&E will include the remaining undepreciated balance of this capital in rate base.

7.23 Idle Facilities

Aglet and MID raised issues regarding PG&E's treatment of idle facilities. Aglet's issue concerned the accounting transactions associated with the life cycle of assets. This issue is resolved in Section 4.9 of the Agreement, which provides that PG&E will include in its next GRC a showing on the plant and depreciation accounting transactions associated with the life cycle of distribution assets and the requirements of the Uniform System of Accounts and other applicable accounting standards. This showing shall include, at a minimum, a description of PG&E's current practices and the basis for those practices.

MID raised a concern about the lack of standards for removal of idle facilities. This issue is resolved in Section 4.10 and Appendix A of the Agreement, which provides that within the joint MID and PG&E service area described in Public Utilities Code Section 9610 (b)(1), PG&E will remove those idle facilities located on private property that PG&E determines do not have any foreseeable use. Appendix A to the Distribution Settlement sets forth the terms under which that determination will be made.

7.24 Integrated Resource Planning

In response to the February 13, 2003 ACR, PG&E filed testimony regarding costs related to Integrated Resource Planning (IRP). PG&E requested that the Commission authorize an additional $11 million in O&M and A&G expense and capital expenditures to support IRP. PG&E also requested an additional $22.1 million of O&M expense to perform the activities associated with procuring electricity, arguing that these activities have been expanded in scope and complexity by recent, and still evolving, Commission decisions on electric procurement issues.

ORA recommended that the Commission reject PG&E's request for an additional $11 million for expenses and capital expenditures for IRP activities as well as PG&E's $22.1 million forecast associated with Electric Transaction Administration. In addition, Aglet and NRDC presented testimony discussing the overarching policy issues associated with integrated resource planning.

Section 4.11 of the Distribution Settlement recognizes that the ACR directed PG&E to identify costs of staffing associated with an assumption that PG&E will "remain a vertically integrated utility responsible for procuring and providing resources to its customers...."and states that "The Settling Parties understand that the Commission is considering integrated resource and procurement issues in R.01-10-024 and that the Commission will further define PG&E's role in this area which may affect costs. The Settling Parties reserve their rights to address such issues in other proceedings, as the role of utilities in this area is further developed by the Commission."

The Settling Parties note that no specific amounts are set forth in the Agreement for these IRP or expanded Electric Transaction Administration activities and that PG&E understands that it will meet its current responsibilities within the funds set forth in the Settlement.

7.25 Service Guarantees Under the Quality Assurance Program and Customer Service Issues

In D.00-02-046, the Commission directed PG&E to establish a Quality Assurance Program (QAP). In this proceeding, ORA recommended a number of changes to PG&E's existing QAP. ORA also recommended changes to PG&E's "Safety Net Program" during the Storm Response/Reliability phase of this GRC.

In addition, ORA recommended that PG&E: (1) follow up on recommendations contained in a "Network Study" prepared at PG&E's request concerning possible efficiency improvements PG&E might make in its local office and pay station operations; (2) process payments made at its drop boxes by 2 00 p.m. on the same day that payments are deposited; (3) survey customers who patronize PG&E's local offices and the pay stations PG&E maintains under contract to determine customer satisfaction; (4) explore enhancing retention efforts for customer service representatives; (5) investigate whether to implement technology improvements and/or process changes to enhance communications between call center and field employees; (6) investigate whether PG&E's translation service is meeting the needs of the various Asian/Pacific Islander communities; and (7) improve its website functionality and file an annual report with the Commission and ORA for three years, which describes and evaluates efforts to improve the website.

TURN suggested that PG&E explore alternatives for securing lower fees for customers who choose to pay their PG&E bills via debit or credit cards when its contract with its current vendor expires. (Exhibit 403, p. 26.)

The Settling Parties have resolved these issues in Appendix B to the Agreement, which sets forth all of the Customer Service-related agreements. These agreements, taken together, improve the Quality Assurance Program and address all of the other customer-related issues and proposals noted above. In addition, this Appendix resolves issues with regard to PG&E's "Safety Net Program" that were raised in the Storm and Reliability Phase of this GRC and previously submitted in briefs.³⁸