(PG&E-1)

PACIFIC GAS AND ELECTRIC COMPANYCHAPTER 1

SUMMARY OF PG&E’S REQUEST

A. IntroductionIn this application, Pacific Gas and Electric Company (PG&E or the

Company) is requesting that the California Public Utilities Commission (CPUC or

Commission) authorize electric and gas distribution base revenue amounts for

2007 of $2.958 billion and $1.041 billion, respectively. PG&E is also requesting

that the Commission authorize a generation base revenue amount for 2007 of

$1.043 billion. In addition, PG&E requests that the Commission authorize

PG&E to file attrition adjustment advice letters for 2008 and 2009.

The electric distribution revenue requirement is based on the costs PG&E

forecasts it will incur in 2007 to: (1) own, operate, and maintain: (a) its

distribution plant; (b) a portion of its transmission plant providing service directly

to specific customers and connecting to specific generation resources; and (c) a

portion of its common and general plant; (2) perform the transactions necessary

to procure electricity for its bundled-service electric customers; and (3) provide

services to its electric customers.

The gas distribution revenue requirement is based on the costs PG&E

forecasts it will incur in 2007 to: (1) own, operate, and maintain its distribution

plant and a portion of its common and general plant; (2) perform the

transactions necessary to acquire gas supplies for core gas customers; and

(3) provide services to its gas customers.

The generation revenue requirement is based on the costs PG&E forecasts

it will incur in 2007 to: (1) own, operate and maintain its electric generating

plant; (2) to amortize the WAPA regulatory asset; and (3) to reflect the work

performed for irrigation districts on a reimbursable basis.

These proposed distribution base revenue amounts represent an increase

for the electric and gas departments of $485 million and $94 million,

respectively, over the amounts presently authorized by the Commission as

reflected in PG&E’s 2003 General Rate Case (GRC) and subsequent attrition

filings, and the cost of capital decision for 2004 and 2005 costs of capital

decision. The proposed generation base revenue amount represents an

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increase of $75 million over the amount authorized by the Commission in the

2003 GRC decision and subsequent attrition filings, and the cost of capital

decision for 2004 and 2005.[1] Compared to total billed revenues presently

authorized, these revenue increases represent a 5.6 percent increase in

revenues billed to electric customers and a 2.7 percent increase in revenues

billed to gas customers.

B. Comparison With Previous Commission Decisions

1. Electric and Gas DistributionTable 2-1 provides a comparison of the distribution results of operations

that PG&E forecasts for 2007 with the estimated adopted distribution results

of operations for 2005 (i.e., adopted by the Commission in PG&E’s

2003 GRC as modified by the attrition increases and cost of capital

decisions for 2004 and 2005). For gas and electric operations and

maintenance and customer services expense combined, PG&E’s forecast

for 2007 is 12.9 percent higher than the amount adopted by the

Commission for 2005. The amounts shown on Table 2-1 for 2005 are

labeled “estimated adopted” because the attrition mechanism for 2004 and

2005 applies the increase to total adopted revenue and not to individual line

items in the results of operations.

The capital-related costs (return, taxes and depreciation) are forecast to

be 8.0 percent higher than those adopted by the Commission for 2005. The

primary driver of these capital-related costs is the increase in the cost of

plant in service to serve PG&E’s customers, including the cost of replacing

aging infrastructures. The physical volume and cost of plant in service

grows every year to serve new customers and increased load, and the costs

of each year’s additions grow as well due to inflation. At the same time, old

depreciated plant (with no book value remaining) is replaced with new

equipment. The costs of this replacement equipment are much higher than

the original costs of the retired plant because of the accumulated inflation

since the original construction. Since plant is a cumulative amount and

additions at today’s costs are added to a balance that includes the original

costs of facilities added 50 or more years ago, the increase in

1 [?] See Decisions 04-05-055 and 04-12-047 and Advice Letters 2499-G/2446-E and 2580-G/2566-E.

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capital-related costs since 2005 is reasonable. In addition, tax deductible

accelerated depreciation from pre-1981 flow-through property is declining,

increasing the tax component of capital-related costs.

The increase in administrative and general (A&G) expenses reflects not

only the usual cost drivers, but reflect increased escalation in medical

benefits costs as well.

As directed by the Commission, PG&E is taking a more active role in

the planning and procurement of generation resources. As PG&E’s

generation function has been returned to cost of service ratemaking, PG&E

has included the Electric Supply Administration costs in its generation

revenue requirement. Previously, these costs were recovered in distribution

rates.

In this application, PG&E is requesting that the Commission approve

revisions to PG&E’s depreciation rates to reflect more accurately the

average service life of the plant that provides distribution service to PG&E’s

customers, and the net salvage at the time that plant is removed from

service. PG&E retained a valuation consultant who performed an analysis

of PG&E’s depreciation rates. (See Exhibit (PG&E-2), Chapters 9 and 10.)

For electric distribution, the change in depreciation rates increases the

revenue requirement by $165 million; for gas distribution, the change in

depreciation rates results in a $15 million increase in revenue requirement.

2. GenerationTable 2-1 provides a comparison of the electric generation results of

operations that PG&E forecasts for 2007 with the electric generation results

of operation adopted by the Commission for 2005 by the Commission

(i.e., including the 2004 and 2005 attrition increases and changes in cost of

capital). The amounts shown on Table 2-1 for 2005 are labeled “estimated

adopted” because the attrition mechanism for 2004 and 2005 applies the

increase to total adopted revenue and not to individual line items in the

results of operations.

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2005Estimated 2007

Line Adopted * Proposed Difference LineElectric Distribution **

1 Operation and Maintenance 428 501 73 12 Customer Services 229 259 30 23 Administrative and General 235 310 76 34 Payroll Taxes, Franchise & Uncollectibles 55 71 16 45 Return, Taxes & Depreciation 1,605 1,749 145 56 Subtotal 2,552 2,890 339 68 Change in Depreciation Rates - 165 165 89 Total 2,552 3,055 504 9

10 Less: FERC Allocation (11) (17) (6) 1011 Total CPUC Jurisdiction 2,541 3,038 497 1112 Less: Other Operating Revenue (67) (80) (13) 1213 Billed Revenue 2,474 2,958 485 13

Gas Distribution14 Operation and Maintenance 134 142 8 1415 Customer Services 180 194 14 1516 Administrative and General 137 176 39 1617 Payroll Taxes, Franchise & Uncollectibles 30 35 6 1718 Return, Taxes & Depreciation 483 505 22 1819 Subtotal 963 1,051 88 1920 Change in Depreciation Rates - 15 15 2021 Total 963 1,066 103 21

Less: Other Operating Revenue (16) (25) (9) Billed Revenue 947 1,041 94

Electric Generation **22 Operation and Maintenance 371 457 87 2223 Customer Services - - - 2324 Administrative and General 116 172 56 2425 Payroll Taxes, Franchise & Uncollectibles 27 33 6 2526 Return, Taxes & Depreciation 462 392 (70) 2627 Subtotal 976 1,055 78 2728 Change in Depreciation Rates - (2) (2) 2829 Total 976 1,053 77 2930 Less: Other Operating Revenue (8) (10) (1) 3031 Billed Revenue 968 1,043 75 31

Total32 CPUC Rate Case Revenue 4,480 5,158 677 3233 Less: Other Operating Revenue (92) (114) (23) 3334 Total Billed Revenue 4,389 5,043 654 34

* Amounts are from PG&E's 2003 GRC Decision 04-05-055 adjusted for 2004 and 2005 attritionand 2004 and 2005 cost of capital changes. Amounts shown are estimates because attritionchanges are made to the total adopted revenues and are not specified for each specificcost of service line item.

** Amounts are adjusted to move Electric Supply Administration from electric distribution toelectric generation to match PG&E 2007 GRC proposal.

(Millions of Dollars)

Table 2-1PACIFIC GAS AND ELECTRIC COMPANY

SUMMARY OF INCREASE OVER 2003 GENERAL RATE CASE

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The costs associated with other functions (i.e., other portions of the

electric transmission system, gas storage and transmission, and the direct

costs of programs, such as, California Alternative Rates for Energy (CARE),

Customer Energy Efficiency (CEE), Demand-Side Management (DSM) and

other public purpose programs, and distributed generation incentives) are

not included in this application. Figure 2-1 illustrates the organizations in

PG&E whose functions are represented in the revenue requirement in this

GRC.

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FIGURE 2-1PACIFIC GAS AND ELECTRIC COMPANY

ORGANIZATION AS OF JULY 2005

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&E

-1)

Chairman of the Board

President and ChiefExecutive Officer

Senior Vice PresidentChief Financial Officer

and Treasurer

Senior Vice PresidentHuman Resources

Executive VicePresident and Chief

Operating Officer

Senior Vice PresidentPublic Policy and

Governmental Affairs

Senior Vice PresidentGeneration and Chief

Nuclear Officer

Vice President andGeneral Manager

DCPP

Senior Vice PresidentCustomer Service and

Revenue

Vice PresidentCustomer Satisfaction

Vice PresidentDCPP

Operations & StationDirector

Vice PresidentNuclear Services

Vice PresidentPower Contracts and

Electric ResourceDevelopment

Senior Vice PresidentTransmission and

Distribution

Vice PresidentAsset Management

Vice PresidentCalifornia GasTransmission

Vice PresidentElectric Transmission

Vice PresidentGeneral Services

Vice President

Vice PresidentGas and Electric

Supply

Vice Presidentand Chief Information

Officer

Vice Presidentand Controller

Vice PresidentEnvironmental Affairs

Vice PresidentRegulatory Relations

Vice PresidentCommunications

Vice PresidentGovernmental

Relations

Senior Vice Presidentand General Counsel

Vice President andCorporate Secretary

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C. Purpose of This ChapterThe material contained in this application establishes the basis for the

revenue requirement and shows that the requested level of revenues are

reasonably necessary to provide adequate service to PG&E’s customers in

2007. This application also provides the Commission an opportunity to review

PG&E’s operations and the costs PG&E will incur to provide generation,

distribution and related services to its customers, to validate that these

operations are reasonable and their costs reasonable and prudently incurred.

This chapter previews the structure of the exhibits in this application. The

chapter also introduces the Company’s program management structure and the

initiatives and rigorous budget review process the Company undertakes to

control costs while maintaining reliability and focusing on safety and customer

satisfaction.

D. Organization of the Remainder of This ChapterThe remainder of this chapter is organized as follows:

Preview of PG&E’s Exhibits in This Application;

PG&E’s Program Management Model;

Program and Budget Review Process;

Program Management Focus;

Revenue Requirements Computation;

Net Savings Due to Business Transformation;

Balancing Accounts and Other Revenue Adjustments;

Summary of PG&E’s Exhibits; and

Conclusion.

E. Preview of PG&E’s Exhibits in This ApplicationThe pre-filed exhibits in this application present information on PG&E’s

operations and costs organized by groups of related activities called major work

categories (MWC). As described in more detail below, PG&E manages its

distribution and generation operations using a program management approach

that organizes the Company and its responsibilities functionally (rather than

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(PG&E-1)geographically, as before) by major program areas. These programs in turn are

comprised of MWCs. The management accounting module of PG&E’s SAP[2] accounting system is organized along the same lines, (i.e., by MWC).

Exhibits (PG&E-3) through (PG&E-7), use the program and MWC structure

to describe the different distribution, generation, customer service, and related

support activities PG&E must perform to carry out its obligation to serve. The

chapters in these exhibits also present costs of these different MWC activities,

including PG&E’s forecasts of those costs for 2007. These chapters provide

fundamental support for PG&E’s distribution and generation revenue

requirement request by showing how that number is built from the “bottom-up”

(i.e., from the activities PG&E must undertake and what those activities cost).

The portion of the SAP accounting system used to track expenditures by

MWC does so without regard to which FERC account those dollars will be

booked. However, PG&E is required to report its financial results and express

its regulatory requests (including requests to this Commission) using a FERC

account format. Thus, where appropriate, the chapters in these exhibits

translate the SAP-expressed forecasts into equivalent FERC-account amounts

and show to which specific FERC accounts the forecasts are assigned (this

process is described more fully below).

For distribution operations, Exhibit (PG&E-2) expresses the summary result

of all of these assignments, restating PG&E’s underlying forecast by FERC

account (for expenses) and function (for plant additions). Exhibit (PG&E-2) also

provides the computation of the revenue requirement request based on those

forecasts.

For generation operations, Exhibit (PG&E-3), Chapters 3 through 12,

present the expense and plant data for generation, and the computation of the

generation revenue requirement.

F. PG&E’s Program Management ModelIn recent years, PG&E has developed a program management approach to

managing work activities and associated costs necessary to provide service to

its customers. In this organizational model, PG&E has grouped related work

activities into programs and assigned individuals as program managers. Thus,

2 [?] PG&E’s financial and management accounting system uses software developed by SAP AG, and is colloquially referred to at PG&E as the SAP system.

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(PG&E-1)one individual is responsible for organizing and managing a group of specific

work activities that are conducted throughout the entire PG&E service territory.

PG&E’s operations are no longer primarily structured on a geographical (or

“area”) basis. Although a geographical approach can move the operational

decision-making closer to the customer, the program management approach

provides consistency of work processes, prioritization, and cost monitoring that

are harder to maintain in a geographic model. In the program management

model, the program manager usually does not have supervisory responsibility

for the individuals performing the work in the field, but instead works with area

managers to plan for, schedule, and implement the necessary work. In the

customer services area and for many of the administrative functions, the

program managers are officers or line managers supervising the employees

performing the work.

PG&E’s programs are comprised of related or similar work activities

(i.e., the MWCs discussed above). MWCs whose costs are charged to expense

are designated with two letters; MWCs whose costs are recorded in plant

accounts are identified by two digits. For example, within the Field Services and

Dispatch Program, MWC DD represents activities necessary to perform field

service work, MWC DC represents activities necessary to dispatch service

requests to field personnel, and MWC 80 includes the capital expenditures

which support the program. Since the MWCs are grouped with similar kinds of

work, the costs incurred in any one program are ultimately recorded in several

FERC expense or plant accounts. In the Field Services and Dispatch example

above, the expenses incurred in MWCs DC and DD are recorded in FERC

Account 587 – Distribution Customer Installation Expense—Electric;

Account 879 – Distribution Customer Installation Expense—Gas, and

Account 903 – Customer Records and Collection Expense, and the capital

expenditures in MWC 80 are recorded in FERC Account 391 – Office Furniture

and Equipment.

G. Program and Budget Review ProcessThe programs are the focal point for the annual planning and budget

process. Each year, program managers and vice presidents present to the

Senior Vice President and Chief Financial Officer (CFO) the previous year’s

results of each program, and the proposals for the next year. For each

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(PG&E-1)program, the CFO reviews the volume of work accomplished, unit costs of the

work (where appropriate), total level of costs, available resources, and

performance measures. Performance measures include items such as the level

of uncollectible accounts and responses to the Quality of Service Evaluations

(QSE+) PG&E receives from customers.

As part of this program and budget review process, program managers also

present plans and budgets for the next year using cost and performance results

of the previous year, and cost and performance goals for the next year. These

goals may include the volume of work to be performed or the unit cost of

performing the work (e.g., the number of trees to be trimmed or the cost per

tree).

H. Program Management FocusPG&E’s SAP accounting system provides program managers with the

management accounting data needed to help manage their programs and

MWCs. Although the costs incurred in a MWC may be recorded in several

FERC accounts, the management accounting data tracks the costs of the work

being performed within the MWC without regard to which FERC accounts the

costs are ultimately charged. The SAP management accounting data allows

program managers to see the total cost of their activities, enabling better

tracking and control of costs, and providing measures by which to gain

efficiencies.

The accounting information provided to program managers expresses costs

in a standard-cost format. This standard cost includes the direct costs of an

activity as well as several “charge-back” items, such as telecommunication

expenses, building facilities’ costs, fleet costs, and personal computer support

costs. The standard cost also includes such items as benefits and payroll tax

expenses associated with PG&E labor, which are required to be recorded in

specific, separate FERC accounts. The standard costs reported by SAP are

referred to as “SAP dollars” while the amounts recorded in FERC accounts are

referred to as “FERC dollars.” For costs that are recorded in expense accounts,

the conversion from SAP dollars to FERC dollars requires that the amounts

included in the standard cost for benefits and payroll taxes be removed. For

capital expenditures, benefits and payroll taxes are included in the capitalized

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(PG&E-1)costs of constructed assets, and no adjustment of the SAP dollar cost is

required.

In the program management chapters in Exhibits (PG&E-3) through

(PG&E-7), program managers present cost estimates in nominal (e.g., 2007)

SAP dollars, because that is how they manage their programs. At the end of

each chapter, PG&E presents program costs in SAP dollars and shows the

FERC translation (i.e., the amounts forecast by FERC account in base

year (i.e., 2004) dollars, including a separate statement of the estimates of

payroll taxes and benefits included in the SAP standard costs).

Table 2-2 (attached at the end of this chapter) consolidates the translation

and summation of operations and maintenance (O&M) expenses for all MWCs

presented in Exhibits (PG&E-4), (PG&E-5) and (PG&E-7) to FERC accounts for

the electric and gas distribution and customer accounts functions. Table 2-2

shows that the total of all the O&M expenses forecast by MWC equals the total

of O&M expenses forecast by FERC account.

Table 2-3 (attached at the end of this chapter) consolidates the translation

and summation of operations and maintenance (O&M) expenses for all MWCs

presented in Exhibit (PG&E-3) to FERC accounts for the electric generation

function. Table 2-3 shows that the total of all the O&M expenses forecast by

MWC equals the total of O&M expenses forecast by FERC account.

I. Revenue Requirements ComputationPG&E’s proposed 2007 electric and gas distribution revenue requirements

are presented in Exhibit (PG&E-2), Chapter 17. The generation revenue

requirement is presented in Exhibit (PG&E-3), Chapter 12. The revenue

requirements are based on the expense and capital forecasts, on a

FERC-account basis.

J. Net Savings Due to Business TransformationAs described in Chapter 1 of this exhibit, PG&E is in the midst of a

transformation of its business operations with the goal of improving customer

service. As described in Exhibit (PG&E-10), PG&E is working on initiatives in

four work streams. Chapter 6 of Exhibit (PG&E-10) summarizes the estimated

costs and savings associated with initiatives in each of the work streams on a

revenue requirement basis (expenses plus return, taxes and depreciation on

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(PG&E-1)plant additions). PG&E proposes to adjust its revenue requirements

year-by-year to reflect the net savings from Transformation. This adjustment

will take place in two stages: First, the conservative range of the net savings

will be deducted from the revenue requirement. This will result in reductions of

$41 million in 2008 and $97 million in 2009. For 2007, the Transformation effort

may cost more that it saves, due to the need to fund early stages in order to

realize future benefits. PG&E is not, for the purposes of this application,

seeking to recover such costs for 2007, nor is it assuming that savings may

materialize which will offset such costs. Second, as described in Exhibit

(PG&E-10), Chapter 6, to the extent that PG&E earns more than its authorized

rate of return, PG&E proposes an earnings sharing mechanism that will allow

customers to share in the benefits of these efforts. This combination will

provide PG&E with the incentive to move ahead aggressively with its

Transformation initiatives while providing rate reductions to customers.

In addition, similar to other Business Transformation initiatives, PG&E

proposes that if the Commission approves the closure of front counters the

partial year 2007 cost savings be incorporated into the 2007 revenue

requirement adopted in this proceeding and that subsequent cost savings be

reflected in the revenue requirements adopted for 2008 and 2009.

K. Balancing Accounts and Other Revenue Adjustments

1. Vegetation Management Balancing AccountPursuant to the Commission’s decision in PG&E’s 1999 GRC, PG&E

established the Vegetation Management Balancing Account (VMBA) to

track the differences between the vegetation management expense adopted

by the Commission and the recorded expense. The VMBA is a one-way

account—any amount of the adopted expense not spent is returned to

customers but PG&E cannot recover expenses above the adopted amount.

At the time the VMBA was adopted, there was concern that PG&E’s

estimates of the number of trees to be trimmed or removed and the costs of

that work were over stated. The VMBA has protected customers by

assuring that customers pay only for the vegetation work performed.

As discussed in Exhibit (PG&E-4), Chapter 9, Law enforcement

personnel at the California Department of Forestry and Fire Prevention

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(PG&E-1)(CDF) have recently indicated a desire to have PG&E substantially increase

its inspection, assessment and removal of potentially hazardous trees, even

though they praise PG&E’s existing program. If CDF maintains this position

on a going forward basis, the number of trees that PG&E is required to

perform a detailed inspection on and the associated inspection costs would

increase dramatically. However, due to the uncertainty over this potential

change in the scope of required utility vegetation management programs

and the attendant costs, PG&E is not at present forecasting additional

expenses for this potential additional work, but instead requests that the

VMBA be modified to a two-way balancing account to protect both PG&E’s

customers and shareholders from the financial impacts of any forecast error

or change in regulatory approach by the CDF or other agency with similar

jurisdiction. A revised VMBA preliminary statement is attached as Appendix

A to this chapter.

2. Other Balancing AccountsPG&E does not usually request recovery of balancing account balances

in GRC proceedings. However, as required by Commission decisions

described below, PG&E requests authorization to transfer the balances in

the Electric and Gas Credit Facilities Fees Tracking Accounts (ECFFTA and

GCFFTA) and the Community Choice Aggregation Implementation Cost

Balancing Account (CCAICBA) to the appropriate electric and/or gas

revenue balancing accounts for recovery from customers.

By Resolution E-3682 (April 1, 2004), the Commission approved the

ECFFTA and GCFFTA and required that the amounts in the accounts be

reviewed in the next GRC proceeding. PG&E requests that the balance in

these accounts be transferred to the electric Distribution Revenue

Adjustment Mechanism (DRAM), the Utility Generation Balancing Account

(UGBA) and the gas Core Fixed Cost Account (CFCA) and the Noncore

Customer Class Charge Account (NCA) for recovery from customers. As

discussed in Exhibit (PG&E-6), Chapter 12, PG&E forecasts the 2006

year-end amount to be transferred to be $6.3 million.

In Decision 04-12-046, the Commission ordered PG&E to establish a

balancing account for Community Choice Aggregation (CCA)

implementation costs incurred prior to cost recovery changes authorized in

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(PG&E-1)PG&E’s GRC. The Commission ordered that these costs be recovered in

the GRC, and also ordered PG&E to propose CCA implementation cost

revenue requirements in the GRC and changes to CCA tariffs for

transactions costs (D.04-12-046 Ordering Paragraphs 1 and 4, and p. 22).

On February 14, 2005, PG&E filed Advice Letter 2630-E to establish the

Community Choice Aggregation Implementation Cost Balancing Account

(CCAICBA) and is waiting for approval of this advice letter. When the

CCAICBA is approved, PG&E will record all initial period costs for CCA

program implementation. PG&E requests that the balance of the CCAICBA

be transferred to the DRAM for recovery from customers.

PG&E is currently awaiting a final decision in Phase 2 of the CCA

proceeding, which will determine the level of costs and cost responsibility for

CCA implementation and transactions costs. Phase 2 will set the

transactions costs to be recovered through CCA tariffs. As there is not yet a

final decision in Phase 2 of the CCA proceeding, PG&E does not yet have a

proposed revenue requirement for future CCA implementation costs, nor

does it propose any changes to the CCA tariffs, which have not yet been

set. Until a GRC CCA revenue requirement is adopted, PG&E will continue

to record CCA implementation costs in the CCAICBA for recovery from

customers.

L. Summary of PG&E’s ExhibitsFigure 2-2 provides a summary of the contents of Exhibits (PG&E-2)

through (PG&E-11). The compensation cost estimates in these exhibits include

base pay and short-term incentives (Performance Improvement Plan or PIP)

only. No long term stock based incentives or retention plan payments are

included in this proposed revenue requirement. In addition, PG&E requests that

the Commission reconsider inclusion in the adopted revenue requirement of

50 percent of the maximum payout amount of the Performance Incentive Plan

(PIP) as part of the appropriate level of compensation.

M. ConclusionThe material contained in the exhibits and accompanying workpapers in this

application support PG&E’s request that the Commission authorize distribution

base revenue amounts of $2.958 billion for the Electric Department and

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(PG&E-1)$1.041 billion for the Gas Department, and $1.043 billion for generation, to

provide revenues necessary to cover PG&E’s costs to provide safe and reliable

service to its customers and an opportunity to earn a fair return on its

investment in utility plant and equipment. PG&E further requests that the

Commission authorize PG&E to implement post test year revenue increases for

2008 and 2009 by Advice Letter.

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(PG&E-1)FIGURE 2-2

PACIFIC GAS AND ELECTRIC COMPANY2007 GENERAL RATE CASE

ORGANIZATIONAL STRUCTURE OF EXHIBITS

(PG&E-1)Summary of

PG&E's 2007 GRC

Includes policy testimony on PG&E’s presentation Provides an executive summary of the case and requested revenue

requirement Explains structure of the case and remaining exhibits

(PG&E-2)Distribution Results

of Operations

Presents the electric and gas distribution results of operations Translates the SAP view of costs presented in Exhibits 4, 5, 6 and 7 to the

FERC account view required by the Rate Case Plan Presents the other technical cost chapters (e.g., taxes, rate base)

(PG&E-3)Generation Results

of Operations

Presents PG&E’s policy on managing its generation resources Presents the generation results of operations Translates the SAP view of generation costs presented to the FERC

account view required by the Rate Case Plan Presents the other technical cost chapters (e.g., taxes, rate base)

(PG&E-4)Distribution

Operations Costs

Describes PG&E's policy on managing its distribution operations functions Describes the activities and costs incurred in operating, maintaining and

constructing distribution assets Presents costs from an SAP view, as they are managed internally

(PG&E-5)Customer Services

Costs

Describes PG&E's policy on managing its distribution customer service functions

Describes the activities and costs incurred in providing customer services to distribution customers

Presents costs from an SAP view, as they are managed internally

(PG&E-6)Administrative andGeneral Expenses

Describes PG&E's A&G costs, including Corporate Services department costs, costs of service provided by PG&E Corporation, pensions and benefits, insurance, claims and other A&G costs

(PG&E-7)General Services

and Other Support Costs

Describes common support costs, such as fleet, materials, and building costs

Describes PG&E's policy on managing its information technology assets and processes, to provide distribution services to customers

(PG&E-8)General Report

Presents information supporting the cost exhibits (e.g., escalation rates) Presents other miscellaneous information required by the Rate Case Plan Presents a master list of acronyms used throughout the case

(PG&E-9)Attrition

Presents PG&E's proposed mechanism for cost recovery during the attrition years following test year 2007

Presents the forecast of rate base growth for the attrition years

(PG&E-10)Business

Transformation

Describes PG&E's Business Transformation project management organization

Presents Business Transformation initiatives by work stream Presents PG&E’s estimates for net benefits to be realized by Business

Transformation initiatives

(PG&E-11)Statements

of Qualifications Presents indices to the case (e.g., by chapter, by witness) Presents the statements of qualifications for each witness

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