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(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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(PG&E-1)
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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