UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
______________________
FORM 10-K
(Mark One)
 
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2005
2007
Or
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
 
Commission
File Number
Exact Name of Registrant
as specified in its charter
State or Other Jurisdiction of
Incorporation or Organization
IRS Employer
Identification Number
1-12609PG&E CORPORATIONCalifornia94-3234914
1-2348PACIFIC GAS AND ELECTRIC COMPANYCalifornia94-0742640

PG&E Corporation
One Market, Spear Tower
Suite 2400
San Francisco, California 94105
(Address of principal executive offices) (Zip Code)
(415) 267-7000
(Registrant's telephone number, including area code)
Pacific Gas and Electric Company
77 Beale Street,
P.O. Box 770000
San Francisco, California 94177
(Address of principal executive offices) (Zip Code)
(415) 973-7000
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Name of Each Exchange on Which Registered
PG&E Corporation: Common Stock, no par value
New York Stock Exchange and Pacific Exchange
Pacific Gas and Electric Company: First Preferred Stock,
cumulative, par value $25 per share:
American Stock Exchange and Pacific Exchange
Redeemable: 5% Series A, 5%, 4.80%, 4.50%, 4.36%
 
Nonredeemable: 6%, 5.50%, 5%
 
Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act:
PG&E Corporation
Yes x No o
Pacific Gas and Electric Company
Yes x No ¨
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act:
PG&E Corporation
Yes ¨ No x
Pacific Gas and Electric Company
Yes o No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. 
PG&E Corporation
Yes x No o
Pacific Gas and Electric Company
Yes x No ¨




Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K:
PG&E Corporation
x
Pacific Gas and Electric Company
x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer”smaller reporting company. (as defined in Rule 12b-2 of the Exchange Act.Act). (Check one).:

PG&E Corporation
Large accelerated filer x
Accelerated filer ¨
Non-accelerated filer ¨
Pacific Gas and Electric Company
Large accelerated filer x
Large accelerated filer  ¨
Accelerated filer ¨
Accelerated filer ¨
Non-accelerated filer ¨
Non-accelerated filer x
Smaller reporting company ¨
Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
PG&E Corporation
Yes ¨ No x
Pacific Gas and Electric Company
Yes o No x

Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 30, 2005,2007, the last business day of the most recently completed second fiscal quarter:
PG&E Corporation Common Stock$13,97515,962 million
Pacific Gas and Electric Company Common StockWholly owned by PG&E Corporation
Common Stock outstanding as of February 10, 2006:
19, 2008:
 
PG&E Corporation:345,319,971355,749,692 (excluding shares held by a wholly owned subsidiary)
Pacific Gas and Electric Company:Wholly owned by PG&E Corporation

DOCUMENTS INCORPORATED BY REFERENCE
Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved:
Designated portions of the combined 20052007 Annual Report to ShareholdersPart I (Item 1, Item 1.A.), Part II (Items 5, 6, 7, 7A, 8 and 9A)
Designated portions of the Joint Proxy Statement relating to the 20062008Part III (Items 10, 11, 12, 13 and 14)
Annual Meetings of Shareholders 






TABLE OF CONTENTS

  
Page
Units of Measurementiii
PART I
Item 1.Business1
General 1
Corporate Structure and Business1
Corporate and Other Information1
Employees1
 iii
Item 1.Cautionary Language Regarding Forward Looking Statements
1
 1
1
1
1
1
PG&E Corporation's Regulatory Environment3
 Federal Energy Regulation3
 State Energy Regulation
4
3
 The Utility's Regulatory Environment4
 Federal Energy Regulation4
State Energy Regulation5
 Other Regulation56
 Competition7
 Competition in the Electricity Industry7
Competition in the Natural Gas Industry8
 Ratemaking Mechanisms910
 Overview910
 910
 General Rate Cases10
Attrition Rate Adjustments11
 Cost of Capital Proceedings11
 Baseline Allowance11
Public Purpose and Other Programs11
Energy Efficiency Programs11
Demand Response Programs12
Self-Generation Incentive Program and California Solar Initiative12
Low-Income Energy Efficiency Programs and California Alternate Rates for Energy12
 1213
 Rate Recovery of Costs of New Electricity Generation Resources13
Overview13
Costs Incurred Under New Power Purchase Agreements13
Costs of Utility-Owned Generation Resource Projects14
DWR Electricity and DWR Revenue Requirements14
Electricity Transmission14
Transmission Owner Rate Cases14
Natural Gas15
The Gas Accord15
Biennial Cost Allocation Proceeding16
Natural Gas Procurement16
Interstate and Canadian Natural Gas Transportation and Storage16
Electric Utility Operations17
Electricity Resources17
Owned Generation Facilities17
DWR Power Purchases18
Third-Party Power Purchase Agreements19
Future Long-Term Generation Resources19
Electricity Transmission19
Electricity Distribution Operations20
2007 Electricity Deliveries 21
Electricity Distribution Operating Statistics21
Natural Gas Utility Operations22
2007 Natural Gas Deliveries 23
Natural Gas Operating Statistics23
i

Natural Gas Supplies24
Gas Gathering Facilities25
Interstate and Canadian Natural Gas Transportation Services Agreements12
13
13
14
15
15
16
16
17
18
18
18
18
20
20
20
21
22
24
25
 Environmental Matters2526
 25
General26
 27
 Water Quality27
 Compressor Station Litigation28
Endangered Species29
 Hazardous Waste Compliance and Remediation3029
 Nuclear Fuel Disposal31
 Nuclear Decommissioning31
 
i
Electric and Magnetic Fields32
1A. Risk Factors32
Unresolved Staff Comments33
Item 2.32
33
 Diablo Canyon Power Plant33
 33
33
33
 Solano County District Attorney’s Office3634
4.3735
 3835
   
3938
3938
4039
4039
4039
4039
4039
9B.40
40
40
4139
   
PART III
and Corporate Governance4341
4342
4342
and Director Independence
44
43
4443
   
4543
 5049
 51
 52


ii



UNITS OF MEASUREMENT

1 Kilowatt (kW)=One thousand watts
1 Kilowatt-Hour (kWh)=One kilowatt continuously for one hour
1 Megawatt (MW)=One thousand kilowatts
1 Megawatt-Hour (MWh)=One megawatt continuously for one hour
1 Gigawatt (GW)=One million kilowatts
1 Gigawatt-Hour (GWh)=One gigawatt continuously for one hour
1 Kilovolt (kV)=One thousand volts
1 MVA=One megavolt ampere
1 Mcf=One thousand cubic feet
1 MMcf=One million cubic feet
1 Bcf=One billion cubic feet
1 MDth=One thousand decatherms






iii








PG&E Corporation, incorporated in California in 1995, is an energy-baseda holding company thatwhose primary purpose is to hold interests in energy-based businesses.  PG&E Corporation conducts its business principally through Pacific Gas and Electric Company or the Utility,(“Utility”) a public utility operating in northern and central California. The Utility engages primarily in the businesses of electricity and natural gas distribution, electricity generation, procurement and transmission, and natural gas procurement, transportation and storage. The Utility was incorporated in California in 1905. PG&E Corporation became the holding company of the Utility and its subsidiaries on January 1, 1997.

The Utility served approximately 55.1 million electricity distribution customers and approximately 4.24.3 million natural gas distribution customers at December 31, 2005.2007. The Utility had approximately $33.8$36.3 billion of assets at December 31, 2005,2007, and generated revenues of approximately $11.7$13.2 billion in 2005.2007. Its revenues are generated mainly through the sale and delivery of electricity and natural gas. The Utility is regulated primarily by the California Public Utilities Commission or the CPUC,(“CPUC”), and the Federal Energy Regulatory Commission or the FERC.(“FERC”).


The principal executive office of PG&E Corporation is located at One Market, Spear Tower, Suite 2400, San Francisco, California 94105, and its telephone number is (415) 267-7000. The principal executive office of the Utility is located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177, and its telephone number is (415) 973-7000. PG&E Corporation and the Utility file various reports with the Securities and Exchange Commission or the SEC.(“SEC”). These reports, including Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Sections 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, are available free of charge on both PG&E Corporation's website, www.pgecorp.comwww.pgecorp.com, and the Utility's website, www.pge.comwww.pge.com. The information contained on these websites is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this report.


At December 31, 2005,2007, PG&E Corporation and its subsidiaries had approximately 19,80020,050 regular employees, including approximately 19,50019,785 regular employees of the Utility.  Of the Utility's regular employees, approximately 12,80012,929 are covered by collective bargaining agreements with three labor unions: the International Brotherhood of Electrical Workers, Local 1245, AFL-CIO or IBEW;(“IBEW”); the Engineers and Scientists of California, IFPTE Local 20, AFL-CIO and CLC or ESC;(“ESC”); and the Service Employees International Union, Local 24/7 or SEIU.(“SEIU”).  The ESC and IBEW collective bargaining agreements expire on December 31, 2008.  The SEIU collective bargaining agreement expires on February 28, 2009.



This combined Annual Report on Form 10-K, including the information incorporated by reference from the joint Annual Report to Shareholders for the year ended December 31, 2007 (“2007 Annual Report”), contains forward-looking statements that are necessarily subject to various risks and uncertainties, the realization or resolution of which are outside of management's control.uncertainties. These statements are based on current estimates, expectations and projections about future events, and assumptions regarding these events and management's knowledge of facts atas of the date of this report. These forward-looking statements relate to, among other matters, estimated capital expenditures, estimated Utility rate base, estimated environmental remediation liabilities, estimated tax liabilities, the anticipated outcome of various regulatory and legal proceedings, future cash flows, and the level of future equity or debt issuances, and are also identified by words such as "assume," "expect," "intend," "plan," "project," "believe," "estimate," "predict," "anticipate," "aim, " "may," "might," "should," "would," "could," "goal," "potential"“assume,” “expect,” “intend,” “plan,” “project,” “believe,” “estimate,” “predict,” “anticipate,” “aim, “ “may,” “might,” “should,” “would,” “could,” “goal,” “potential” and similar expressions. PG&E Corporation’s and the Utility’s results of operations and financial condition depend primarily on whether the Utility is able to operate its business within authorized revenue requirements, timely recover its authorized costs, and earn its authorized rate of return. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, are discussed below in Item 1A. Risk Factors. These factors include, but are not limited to:

·the Utility’s ability to manage capital expenditures and operating costs within authorized levels and recover costs through rates in a timely manner;
·the outcome of regulatory proceedings, including pending and future ratemaking proceedings at the CPUC and the FERC;
1


Operating Environment

·How the Utility manages its responsibility to procure electric capacity and energy for its customers;
·Thethe adequacy and price of electricity and natural gas supplies, and the ability of the Utility to manage and respond to the volatility of the electricity and natural gas market for its customers;markets;
·Weather,the effect of weather, storms, earthquakes, fires, floods, disease, other natural disasters, explosions, accidents, mechanical breakdowns, acts of terrorism, and other events or hazards that affect demand for electricity or natural gas, result in power outages, reduce generating output, disrupt natural gas supply, cause damage toon the Utility's assets or generatingUtility’s facilities cause damage to theand operations, or assets ofits customers, and third parties on which the Utility relies, or subject the Utility to third party claims for damage or injury;relies;
·Unanticipatedthe potential impacts of climate change on the Utility’s electricity and natural gas businesses;
·changes in customer demand for electricity and natural gas resulting from unanticipated population growth or decline, general economic and financial market conditions, changes in technology, including the development of alternative energy sources, all of which may affect customer demand for natural gas or electricity;other reasons;
·Whetheroperating performance of the Utility is required to cease operations temporarily or permanently at itsUtility’s Diablo Canyon nuclear power plant becausegenerating facilities (“Diablo Canyon”), the occurrence of unplanned outages at Diablo Canyon, or the temporary or permanent cessation of operations at Diablo Canyon;
·whether the Utility is unablecan maintain the cost efficiencies it has recognized from its completed initiatives to increaseimprove its on-site spent nuclear fuel storage capacity, find another depositary for spent fuel, or timely completebusiness processes and customer service, improve its performance following the replacementOctober 2007 implementation of new work processes and systems, and identify and successfully implement additional cost-saving measures
·whether the steam generators, or becauseUtility incurs substantial unanticipated expense to improve the safety and reliability of mechanical breakdown, lack of nuclear fuel, environmental constraints, or for some other reasonits electric and natural gas distribution systems;
·whether the risk thatUtility achieves the CPUC’s energy efficiency targets and recognize any incentives the Utility may be required to purchase electricity from more expensive sources; andearn in a timely manner;
·Whetherthe impact of changes in federal or state laws, or their interpretation, on energy policy and the regulation of utilities and their holding companies;
·the impact of changing wholesale electric or gas market rules, including new rules of the California Independent System Operator (“CAISO”) to restructure the California wholesale electricity market;
·how the CPUC administers the conditions imposed on PG&E Corporation when it became the Utility’s holding company;
·the extent to which PG&E Corporation or the Utility is ableincurs costs and liabilities in connection with litigation that are not recoverable through rates, from insurance or from other third parties;
·the ability of PG&E Corporation and/or the Utility to recognize access capital markets and other sources of credit in a timely manner on favorable terms;
·the anticipated cost benefitsimpact of environmental laws and savings expected to result from its efforts to improve customer service through implementationregulations and the costs of specific initiatives to streamline business processescompliance and deploy new technology.remediation;
·the effect of municipalization, direct access, community choice aggregation, or other forms of bypass; and
the impact of changes in federal or state tax laws, policies, or regulations.

Legislative ActionsFor more information about the more significant risks that could affect the outcome of these forward-looking statements and Regulatory ProceedingsPG&E Corporation's and the Utility's future financial condition and results of operations, see “Risk Factors” that appears near the end of the section entitled “Management's Discussion and Analysis of Financial Condition and Results of Operations” (MD&A”) in the 2007 Annual Report that is incorporated by reference and filed as part of Exhibit 13 to this Annual Report on Form 10-K.  PG&E

·The outcome of the regulatory proceedings pending at the CPUC and the FERC and the impact of future ratemaking actions by the CPUC and the FERC;
·The impact of the recently enacted Energy Policy Act of 2005 which, among other provisions, repeals the Public Utility Holding Company Act of 1935 making electric utility industry consolidation more likely; expands the FERC’s authority to review proposed mergers; changes the FERC regulatory scheme applicable to qualifying co-generation facilities, or QFs; authorizes the formation of an Electric Reliability Organization to be overseen by the FERC to establish electric reliability standards; and modifies certain other aspects of energy regulation and federal tax policies applicable to the Utility;
·The extent to which the CPUC or the FERC delays or denies recovery of the Utility's costs, including electricity or gas purchase costs, from customers due to a regulatory determination that such costs were not reasonable or prudent, or for other reasons, resulting in write-offs of regulatory assets;
·How the CPUC administers the capital structure, stand-alone dividend, and first priority conditions of the CPUC's past decisions permitting the establishment of holding companies for the California investor-owned electric utilities and the outcome of the CPUC's new rulemaking proceeding concerning the relationship between the California investor-owned energy utilities and their holding companies and non-regulated affiliates, which may include (1) establishing reporting requirements for the allocation of capital between utilities and their non-regulated affiliates by the parent holding companies, and (2) changing the CPUC's affiliate transaction rules;
·Whether the Utility is determined to be in compliance with all applicable rules, tariffs and orders relating to electricity and natural gas utility operations, including tariffs related to the Utility’s billing and collection practices, and the extent to which a finding of non-compliance could result in customer refunds, penalties or other non-recoverable expenses, such as has been recommended with respect to the CPUC’s investigation into the Utility’s billing and collection practices; and
·Whether the Utility is required to incur material costs or capital expenditures or curtail or cease operations at affected facilities, including the Utility’s natural gas compressor stations, to comply with existing and future environmental laws, regulations and policies.

2

Pending Litigation


·The outcome of pending litigation; and
·The timing and resolution of the pending appeal of the bankruptcy court order confirming the Utility's plan of reorganization under Chapter 11 of the U.S. Bankruptcy Code.

Municipalization and Bypass

·Continuing efforts by local public utilities to take over the Utility's distribution assets through exercise of their condemnation power or by duplication of the Utility's distribution assets or service, and other forms of municipalization that may result in stranded investment capital, decreased customer growth, loss of customer load and additional barriers to cost recovery; and
·The extent to which the Utility's distribution customers are permitted to switch between purchasing electricity from the Utility and from alternate energy service providers as direct access customers, and the extent to which cities, counties and others in the Utility's service territory begin directly serving the electricity needs of the Utility's customers, potentially resulting in stranded generating asset costs and non-recoverable procurement costs.

PG&E Corporation and the Utility do not undertake an obligation to update forward-looking statements, whether in response to new information, future events or otherwise.



The Utility's electricity distribution network extends throughout all or a part of 47 of California's 58 counties, comprising most of northern and central California. The Utility's network consists of 128,128 circuit miles of distribution lines (of which approximately 20% are underground and approximately 80% are overhead). There are 89 transmission substations and 48 transmission-switching stations. A transmission substation is a fenced facility where voltage is transformed from one transmission voltage level to another. There are 611 distribution substations and 118 low-voltage distribution substations. There are 290 combined transmission and distribution substations. Combined transmission and distribution substations have both transmission and distribution transformers.PG&E Corporation's Regulatory Environment

The Utility's distribution network interconnectsFederal Energy Regulation

As a public utility holding company, PG&E Corporation is subject to the Utility's electricity transmission system at 671 points. This interconnection betweenrequirements of the Utility's distribution networkEnergy Policy Act of 2005 (“EPAct”), which became effective on February 8, 2006.  Among its key provisions, the EPAct repealed the Public Utility Holding Company Act of 1935 and enacted the Public Utility Holding Company Act of 2005 (“PUHCA 2005”). Under PUHCA 2005, public utility holding companies fall principally under the regulatory oversight of the FERC, an independent agency within the U.S. Department of Energy (“DOE”).  PG&E Corporation and its subsidiaries are exempt from all requirements of PUHCA 2005 other than the obligation to provide access to their books and records to the FERC and the transmission system typically occurs at distribution substations where transformersCPUC for ratemaking purposes.  These books and switching equipment reducerecords provisions are largely duplicative of other provisions under the high-voltage transmission levels at which the electricity transmission system transmits electricity, ranging from 500 kV to 60 kV, to lower voltages, ranging from 44 kV to 2.4 kV, suitable for distribution to the Utility's customers. The distribution substations serve as the central hubsFederal Power Act of the Utility's electricity distribution network1935 and consist of transformers, voltage regulation equipment, protective devices and structural equipment. Emanating from each substation are primary and secondary distribution lines connected to local transformers and switching equipment that link distribution lines and provide delivery to end-users. In some cases, the Utility sells electricity from its distribution lines or other facilities to entities, such as municipal and other utilities, that then resell the electricity.

3



The following table shows the percentage of the Utility's total 2005 electricity deliveries represented by each of its major customer classes.State Energy Regulation

Total 2005 Electricity Delivered: 81,626 GWhPG&E Corporation is not a public utility under California law.  The CPUC has authorized the formation of public utility holding companies subject to various conditions related to finance, human resources, records and bookkeeping, and the transfer of customer information. The financial conditions provide that:

Agricultural and Other Customers·  6%
Industrial Customers18%
Residential Customers36%
Commercial Customers40%
the Utility cannot guarantee any obligations of PG&E Corporation without prior written consent from the CPUC;


The following table shows certain of the Utility's operating statistics from 2001 to 2005 for electricity sold or delivered, including the classification of sales and revenues by type of service.
  
2005
 
2004
 
2003
 
2002
 
2001
Customers (average for the year):          
Residential 4,353,458 4,366,897 4,286,085 4,171,365 4,165,073
Commercial 509,786 509,501 493,638 483,946 484,430
Industrial 1,271 1,339 1,372 1,249 1,368
Agricultural 78,876 80,276 81,378 78,738 81,375
Public street and highway lighting 28,021 27,176 26,650 24,119 23,913
Other electric utilities 4 3 4 5 5
Total (1) 4,971,362 4,985,192 4,889,127 4,759,422 4,756,164
Deliveries (in GWh):(2)          
Residential 29,752 29,453 29,024 27,435 26,840
Commercial 32,375 32,268 31,889 31,328 30,780
Industrial 14,932 14,796 14,653 14,729 16,001
Agricultural 3,742 4,300 3,909 4,000 4,093
Public street and highway lighting 792 2,091 605 674 418
Other electric utilities 33 28 76 64 241
Subtotal 81,626 82,936 80,156 78,230 78,373
California Department of Water Resources (DWR) (20,476) (19,938) (23,554) (21,031) (28,640)
Total non-DWR electricity 61,150 62,998 56,602 57,199 49,733
Revenues (in millions):          
Residential $3,856 $3,718 $3,671 $3,646 $3,396
Commercial 4,114 4,179 4,440 4,588 4,105
Industrial 1,232 1,204 1,410 1,449 1,554
Agricultural 446 491 522 520 525
Public street and highway lighting 66 71 69 73 60
Other electric utilities 4 22 24 10 39
Subtotal 9,718 9,685 10,136 10,286 9,679
DWR (1,699) (1,933) (2,243) (2,056) (2,173)
Direct access credits   (277) (285) (461)
Miscellaneous(3) 235 (248) (52) 193 244
Regulatory balancing accounts (327) 363 18 40 37
Total electricity operating revenues $7,927 $7,867 $7,582 $8,178 $7,326
Other Data:          
Average annual residential usage (kWh) 6,834 6,744 6,772 6,577 6,444
Average billed revenues (cents per kWh):          
Residential 12.96 12.62 12.65 13.29 12.65
Commercial 12.71 12.95 13.92 14.65 13.34
Industrial 8.25 8.14 9.62 9.84 9.71
Agricultural 11.92 11.41 13.35 13.00 12.83
Net plant investment per customer $2,966 $2,790 $2,689 $2,105 $2,018


4



(1)Starting in 2005, the Utility’s methodology used to count customers changed from the number of billings to the number of active service agreements.

(2)These amounts include electricity provided to direct access customers who procure their own supplies of electricity.

(3)Miscellaneous revenues in 2003 include a $125 million reduction due to refunds to electricity customers from generation-related revenues in excess of generation-related costs.


The following table shows the percentage of the Utility's total sources of electricity for 2005 represented by each major electricity resource:

·  
the Utility's dividend policy must be established by the Utility's Board of Directors as though the Utility were a stand-alone utility company;
Owned generation (nuclear, fossil fuel-fired·  
the capital requirements of the Utility, as determined to be necessary and hydroelectric facilities)
40%
DWR27%
Qualifying Facilities/Renewables22%
Irrigation Districts5%
Other Power Purchases6%prudent to meet the Utility's obligation to serve or to operate the Utility in a prudent and efficient manner, must be given first priority by PG&E Corporation's Board of Directors (known as the “first priority” condition); and

·  
the Utility must maintain on average its CPUC-authorized utility capital structure, although it can request a waiver of this condition if an adverse financial event reduces the Utility's common equity component by 1% or more.
The Utility is required to dispatch all of(As discussed below under “Item 3—Legal Proceedings,” the electricity resources within its portfolio, including electricity provided under DWR contracts, in the most cost-effective way. To the extent the Utility's electricity resources are not sufficient to meet the demand of the Utility's customers, the Utility purchases the electricity from the wholesale electricity market. At other times, least-cost dispatch requires the Utility to schedule more electricity than is necessary to meet its retail loadCalifornia Attorney General and to sell this additional electricity on the wholesale electricity market. The Utility typically schedules excess electricity when the expected electricity sales proceeds exceed the variable costs to operate a generation facility or buy electricity on an optional contract.


At December 31, 2005, the Utility owned and operated the following generation facilities, all located in California, listed by energy source:


Generation Type 
 
County Location
 
Number of
Units
 
Net Operating
Capacity (MW)
Nuclear:      
Diablo Canyon San Luis Obispo 2 2,174
Hydroelectric:      
Conventional 
16 counties in northern
and central California
 107 2,684
Helms pumped storage Fresno 3 1,212
Hydroelectric subtotal   110 3,896
Fossil fuel:      
Humboldt Bay(1) Humboldt 2 105
Hunters Point(2) San Francisco 2 215
Mobile turbines Humboldt 2 30
Fossil fuel subtotal   6 350
Total   118 6,420
(1)The Humboldt Bay facilities consist of a retired nuclear generation unit and two operating fossil fuel-fired plants.

(2)In July 1998, the Utility reached an agreement with the City and County of San Francisco regardinghave alleged that PG&E Corporation and its directors, as well as the Utility's Hunters Point fossil fuel-fired plant, which has been designated as a "must run" facility bydirectors of the Utility, violated the CPUC’s holding company conditions during the California Independent System Operator, to support system reliability. The agreement expresses the Utility's intention to retire the plant when it is no longer needed. The Utility expects to retire the plant in 2006 after the completion of a new 230-kV transmission line from Redwood City to Brisbane, known as the Jefferson-Martin 230-kV Line, that will provide additional transmission system reliability in San Francisco and northern San Mateo County. Construction of this project is expected to be completed in April 2006.

5


Diablo Canyon Power Plant. The Utility's Diablo Canyon power plant consists of two nuclear power reactor units, each capable of generating up to approximately 1,087 MW of electricity. Unit 1 began commercial operation in May 19852000-2001 energy crisis. PG&E Corporation and the operating license for this unit expires in September 2021. Unit 2 began commercial operation in March 1986Utility believe that they have complied with applicable statutes, CPUC decisions, rules and the operating license for this unit expires in April 2025. For the 10-year period ended December 31, 2005, the Utility's Diablo Canyon power plant achieved an average overall capacity factor of approximately 89.1%.orders.)

The following table outlinesCPUC also has adopted complex and detailed rules governing transactions between California's electricity and gas utilities and their affiliates.  The rules address the Diablo Canyon power plant's refueling schedule for the next five years. The Diablo Canyon power plant refueling outages are typically scheduled every 16 to 21 months. The average length of a refueling outage over the last five years has been approximately 47 days. It is anticipated, however, that additional work will be required during future scheduled outages leading up to the replacementuse of the steam generatorsutilities’ names and logos by their affiliates, the separation of utilities and their affiliates, provision of utility information to affiliates, and energy procurement-related transactions between the utilities and their affiliates.  The rules also prohibit each utility from engaging in Unit 2 in 2008 and in Unit 1 in 2009. The capital expenditures necessary to complete these projects are discussed further in the section of PG&E Corporation’s and the Utility’s combined 2005 Annual Report to Shareholders, or 2005 Annual Report, entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” or MD&A. This additional work will lengthen the forecasted outage durations to the time periods shown below. The table below shows outages of up to 45 days to accommodate non-routine tasks, such as expanded steam generator inspection and repair and low-pressure turbine rotor replacement. Outages of up to 80 days are scheduled for steam generator replacements. The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors.

 
2006
 
2007
 
2008
 
2009
 
2010
          
Unit 1
         
   Refueling- April - January October
   Duration (days)- 35 - 80 35
   Startup- June - April November
Unit 2
         
   RefuelingApril - February October -
   Duration (days)45 - 80 35 -
   StartupJune - April November -

In addition, as discussed below under “Environmental Matters —Nuclear Fuel Disposal,” the Utility is constructing an on-site dry cask storage facility to store the spent nuclear fuel that is expected to be completed by 2008. To provide another storage alternative in the event construction of the dry cask storage facility is delayed, in November 2005, the Nuclear Regulatory Commission, or the NRC, authorized the Utility to install a temporary storage rack in each unit's existing spent fuel storage poolcertain practices that would increase the on-site storage capability to permit the Utility to operate Unit 1 until 2010 and Unit 2 until 2011. The Utility anticipatesdiscriminate against energy service providers that it would complete the installation of the temporary storage racks bycompete with that utility's affiliates.  In December 2006. If the Utility is unable to complete the dry cask storage facility, or if construction is delayed beyond 2010, and if the Utility is otherwise unable to increase its on-site storage capacity, it is possible that the operation of Diablo Canyon may have to be curtailed or halted as early as 2010 with respect to Unit 1 and 2011 with respect to Unit 2 and until such time as additional spent fuel can be safely stored.

The Utility has several types of nuclear insurance for its Diablo Canyon power plant and the retired nuclear generating unit at Humboldt Bay, or Humboldt Bay Unit 3. The Utility has insurance coverage for property damages and business interruption losses as a member of Nuclear Electric Insurance Limited, or NEIL. NEIL is a mutual insurer owned by utilities with nuclear facilities. NEIL provides property damage and business interruption coverage of up to $3.24 billion per incident for Diablo Canyon. In addition, NEIL provides $131 million of property damage insurance for Humboldt Bay Unit 3. Under this insurance, if any nuclear generating facility insured by NEIL suffers a catastrophic loss causing a prolonged outage, the Utility may be required to pay an additional premium of up to $43.6 million per one-year policy term.

NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. If one or more acts of domestic terrorism cause property damage covered under any of the nuclear insurance policies issued by NEIL to any NEIL member within a 12-month period, the maximum recovery under all those nuclear insurance policies may not exceed $3.24 billion plus the additional amounts recovered by NEIL for these losses from reinsurance. There is no policy coverage limitation for an act caused by foreign terrorism because NEIL would be entitled to receive substantial reimbursement by the federal government under the Terrorism Risk Insurance Extension Act of 2005. The Terrorism Risk Insurance Extension Act of 2005 expires on December 31, 2007.

Under the Price-Anderson Act, public liability claims from a nuclear incident are limited to $10.8 billion. As required by the Price-Anderson Act, the Utility purchased the maximum available public liability insurance of $300 million for the Diablo

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Canyon power plant. The balance of the $10.8 billion of liability protection is covered by a loss-sharing program (secondary financial protection) among utilities owning nuclear reactors. Under the Price-Anderson Act, owner participation in this loss-sharing program is required for all owners of nuclear reactors that are licensed to operate, are designed for the production of electrical energy, and have a rated capacity of 100 MW or higher. If a nuclear incident results in costs in excess of $300 million, then the Utility may be responsible for up to $100.6 million per reactor, with payments in each year limited to a maximum of $15 million per incident until the Utility has fully paid its share of the liability. Since the Diablo Canyon power plant has two nuclear reactors each with a rated capacity of over 100 MW, the Utility may be assessed up to $201.2 million per incident, with payments in each year limited to a maximum of $30 million per incident. The Energy Policy Act of 2005 extended the Price-Anderson Act through December 31, 2025. Both the maximum assessment per reactor and the maximum yearly assessment will be adjusted for inflation beginning August 31, 2008.

In addition, the Utility has $53.3 million of liability insurance for Humboldt Bay Unit 3 and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents covering liabilities in excess of the $53.3 million of liability insurance.

Hydroelectric Generation Facilities. The Utility's hydroelectric system consists of 110 generating units at 68 powerhouses, including a pumped storage facility, with a total generating capacity of 3,896 MW. The system includes 99 reservoirs, 76 diversions, 174 dams, 184 miles of canals, 44 miles of flumes, 135 miles of tunnels, 19 miles of pipe and 5 miles of natural waterways. The system also includes water rights as specified in 87 permits or licenses and 160 statements of water diversion and use. With the exception of three non-jurisdictional powerhouses, all of the Utility's powerhouses are licensed by the FERC. Pursuant to the Federal Power Act, the term of a hydroelectric project license issued by the FERC is between 30 and 50 years. In the last four years, the Utility has received six renewed hydroelectric project licenses from the FERC totaling 699 MW. Licenses associated with approximately 917 MW now in relicensing have expired; these projects are being operated on automatically renewed annual licenses pending issuance of renewed licenses. Within the next three years 2006, through 2008, licenses associated with another 12 MW will expire. Licenses associated with approximately 2,960 MW will expire between 2009 and 2043.


During the 2000-2001 energy crisis the California investor-owned electric utilities lost their creditworthiness and were unable to purchase electricity in the wholesale market for their customers. As a result, in January 2001, the State of California authorized the DWR to purchase electricity to meet the portion of the demand of the utilities' customers, plus applicable reserve margins, not satisfied from their own generation facilities and existing electricity contracts. California Assembly Bill, or AB, 1X, which was passed in February 2001, authorized the DWR to enter into contracts for the purchase of electricity and to issue revenue bonds to finance electricity purchases. The Utility and the other California investor-owned electric utilities act as the billing and collection agent for the DWR's sales of electricity to retail customers.

The DWR is currently legally and financially responsible for these contracts. The DWR has stated publicly in the past that it intended to transfer full legal title to, and responsibility for, the DWR power purchase contracts to the California investor-owned electric utilities as soon as possible. However, the DWR power purchase contracts cannot be transferred to the Utility without the consent of the CPUC. The settlement agreement approved by the CPUC on December 18, 2003, and entered intorevised its rules to, among the CPUC, the Utility and PG&E Corporation on December 19, 2003, to resolve the Utility's proceeding under Chapter 11 of the U.S. Bankruptcy Code, or the Settlement Agreement, provides that the CPUC will not require the Utility to accept an assignment of, or to assume legal or financial responsibility for, the DWR power purchase contracts unless each of the following conditions has been met:other changes:

·  After assumption,
emphasize that the Utility's issuer rating by Moody's Investors Service,holding company may not aid or Moody's, will be no less than A2 andabet a utility's violation of the Utility's long-term issuer credit rating by Standard & Poor's,rules or S&P, will be no less than A;act as a conduit to provide confidential utility information to an affiliate;

·  The
require prior CPUC first makes a finding thatapproval before the DWR power purchase contracts to be assumed are just and reasonable; andutility can contract with an affiliate for resource procurement (e.g., electricity or gas), except in blind transactions where the identity of the other party is not known until the transaction is consummated;

·  The CPUC has acted
require certain key officers to ensureprovide annual certifications of compliance with the affiliate rules;
·  
prohibit certain key officers from serving in the same position at both the utility and the holding company, or, in the alternative, prohibit the sharing of lobbying, regulatory relations and certain legal services (except for legal services necessary to the provision of permitted shared services);
·  
require the utility to obtain a “nonconsolidation opinion” indicating that it would not be consolidated into a bankruptcy of its holding company; and
·  make the CPUC's Energy Division responsible for hiring independent auditors to conduct biennial audits to verify that the Utility will receive full and timely recoveryutility is in its retail electricity rates of all costs associatedcompliance with the DWR power purchase contracts to be assumed without further review.affiliate rules.

The Settlement Agreement does not limit the CPUC's discretionCPUC has established specific penalties and enforcement procedures for affiliate rules violations. Utilities are required to review the prudenceself-report affiliate rules violations.


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The Utility's Regulatory Environment 

Various aspects of the Utility's administrationbusiness are subject to a complex set of energy, environmental and dispatchother laws, regulations and regulatory proceedings at the federal, state and local levels.  In addition to enacting PUHCA 2005 to replace the Public Utility Holding Company Act of 1935, as discussed above, the EPAct significantly amended various federal energy laws applicable to electric and natural gas markets, including the Federal Power Act of 1935, the Natural Gas Act of 1938 and the Public Utility Regulatory Policies Act of 1978  (“PURPA”).

This section and the “Ratemaking Mechanisms” section below summarize some of the assumed DWR power purchase contracts consistent with applicable law.

7


Third-Party Power Purchase Agreementsmore significant laws, regulations and regulatory mechanisms affecting the Utility. These summaries are not an exhaustive description of all the laws, regulations and regulatory proceedings that affect the Utility. The energy laws, regulations and regulatory proceedings may change or be implemented or applied in a way that the Utility does not currently anticipate. For discussion of specific pending regulatory proceedings that are expected to affect the Utility.  For more information, see “Regulatory Matters” in the MD&A in the 2007 Annual Report.

Qualifying FacilityFederal Energy Regulation

The FERC

The FERC regulates the transmission and wholesale sales of electricity in interstate commerce and the transmission and sale of natural gas for resale in interstate commerce. The FERC also regulates interconnections of transmission systems with other electric systems and generation facilities; tariffs and conditions of service of regional transmission organizations, including the CAISO; and the terms and rates of wholesale electricity sales. The EPAct granted the FERC significant new responsibilities to oversee the reliability of the nation’s electricity transmission grid, to prevent market manipulation, and to supplement state transmission siting efforts in certain electric transmission corridors that are determined to be of national interest. The EPAct also expanded the FERC’s authority to impose penalties for violation of certain federal statutes, including the Federal Power Purchase AgreementsAct of 1935 and the Natural Gas Act of 1938, and for violations of FERC-approved regulations. The FERC can impose penalties of up to $1,000,000 per day per violation.  The FERC has jurisdiction over the Utility's electricity transmission revenue requirements and rates, the licensing of substantially all of the Utility's hydroelectric generation facilities, and the interstate sale and transportation of natural gas.

Electric Reliability Standards; Development of Transmission Grid.  As part of its directive to oversee the development of mandatory electric reliability standards to protect the national electric transmission system, the FERC certified the North American Electric Reliability Corp., known as the NERC, as the nation’s Electric Reliability Organization under the EPAct.  The NERC is responsible for developing and enforcing electric reliability standards, subject to FERC approval. The FERC also has approved a delegation agreement under which the NERC has delegated enforcement authority for the geographic area known as the Western Interconnection to the Western Electricity Coordinating Council. Failure of the Utility to comply with FERC-approved electric reliability standards may subject the Utility to penalties. In addition, the CAISO is responsible for providing open access electricity transmission service on a non-discriminatory basis, planning transmission system additions, and ensuring the maintenance of adequate reserves of generation capacity.  

The FERC also has issued rules on electric transmission pricing reforms designed to promote needed investment in energy infrastructure, to reduce transmission congestion, and to require transmission organizations with organized electricity markets to make long-term firm transmission rights available to load-serving entities, so these entities can enter into long-term transmission service arrangements without being exposed to unhedged congestion cost risk.

Prevention of Market Manipulation.  The EPAct also gave the FERC broader authority to police and penalizes the exercise of market power or behavior intended to manipulate prices paid in FERC-jurisdictional transactions.  In January 2006, the FERC adopted rules to prohibit market manipulation, modeling its new rules on SEC Rule 10b-5, which prohibits fraud and manipulation in the purchase or sale of securities.  Under the FERC's new regulations, it is unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas, electric energy, or transportation/transmission services subject to the jurisdiction of the FERC:  (1) to use or employ any device, scheme or artifice to defraud, (2) to make any untrue statement of a material fact or to omit to state a material fact necessary in order to make the statements made, in the light of the circumstances under which they were made, not misleading, or (3) to engage in any act, practice or course of business that operates or would operate as a fraud or deceit upon any person.

The Utility isQF Regulation.   Under PURPA, electric utilities were required by CPUC decisions to purchase energy and capacity from independent power producers that are qualifying cogeneration facilities under the Public Utility Regulatory Policies Act of 1978, or PURPA.known as QFs. To implement the purchase requirements of PURPA, the CPUC required California investor-owned electric utilities to enter into long-term power purchase agreements with qualifying facilities, or QFs and approved the applicable terms, conditions, prices and eligibility requirements.  These agreements requireThe EPAct significantly amended the Utility to pay for energy and capacity. Energy payments are based on the QF's actual electrical output and CPUC-approved energy prices, while capacity payments are based on the QF's total available capacity and contractual capacity commitment. Capacity payments may be adjusted if the QF fails to meet or exceeds performance requirements specified in the applicable power purchase agreement.

As of December 31, 2005, the Utility had agreements with 280 QFs for approximately 4,200 MW that are in operation. Agreements for approximately 3,900 MW expire at various dates between 2006 and 2028. QF power purchase agreements for approximately 300 MW have no specific expiration dates and will terminate only when the owner of the QF exercises its termination option. The Utility also has power purchase agreements with approximately 60 inoperative QFs. The total of approximately 4,200 MW consists of approximately 2,600 MW from cogeneration projects, 600 MW from wind projects and 1,000 MW from projects with other fuel sources, including biomass, waste-to-energy, geothermal, solar and hydroelectric.

On January 22, 2004, the CPUC ordered the California investor-owned electric utilities to allow owners of QFs with certain power purchase agreements expiring before the end of 2005 to extend these contracts for five years with modified pricing terms. As of December 31, 2005, 21 QFs had entered into such five-year contract extensions, 13 QFs entered in extensions in 2004 and 8 QFs entered into extensions in 2005. QF power purchase agreements accounted for approximately 22% of the Utility’s 2005 electricity sources, approximately 23% of the Utility's 2004 electricity sources and approximately 20% of the Utility's 2003 electricity sources. No single QF accounted for more than 5% of the Utility's 2005, 2004 or 2003 electricity sources.

There are proceedings pending at the CPUC that may impact both the amount of payments to QFs and the number of QFs holding power purchase agreements with the Utility. The CPUC will address whether certain payments for short-term power deliveries required by the power purchase agreements comply with the pricing requirements of the PURPA.  The CPUC is also considering whether to require the California investor-owned electric utilities to enter into new power purchase agreements with existing QFs with expiring power purchase agreements and with newly-constructed QFs. For a further discussion of QF matters, see the section of Note 17: Commitments and Contingencies— Power Purchase Agreements—Qualifying Facility Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2005 Annual Report.

On January 19, 2006, the FERC proposed regulations to implementAs amended, Section 210(m) of PURPA which was enacted as part of the Energy Policy Act of 2005. Section 210(m) authorizes the FERC to waive the obligation of an electric utility under Section 210
4


of PURPA both (1) to purchase the electricity offered to it by a QF (under a new contract or obligation), if certain conditions are met, and (2)the FERC finds that the QF has nondiscriminatory access to sellone of three defined categories of
competitive wholesale electricity to a QF if certain conditions are met.markets.  The statute would permitpermits such waivers as to a particular QF or on a “service territory-wide basis.”  While the FERC's proposed regulations would grant blanket waivers from the obligationThe Utility plans to purchase for certain areas under the control ofassess whether it will file a regional transmission organization,request with the FERC has concluded that the ISO market does not qualify for such status due to the lack of a functioning day-ahead market, i.e., a market in which electricity deliveries are scheduled a day before delivery.  The ISO intendsterminate its obligations under PURPA to implement a day-ahead market in late 2007. The proposed regulations would authorize utilities to make a showing on a case-by-case basis that short and long-term markets are sufficiently competitive to warrant waiver of the PURPA mandatory purchase obligation. The Utility intends to apply for a service territory-wide waiver of itsenter into new QF purchase obligations under this case-by-case approach. after the implementation of the new day ahead market structure provided for in the CAISO’s Market Redesign and Technology Update (“MRTU”) initiative.


The Nuclear Regulatory Commission (“NRC”), oversees the licensing, construction, operation and decommissioning of nuclear facilities, including the two nuclear generating units at Diablo Canyon and the Utility’s retired nuclear generating unit at Humboldt Bay (“Humboldt Bay Unit 3”).  NRC regulations require extensive monitoring and review of the safety, radiological, environmental and security aspects of these facilities. In the event of non-compliance, the NRC has the authority to impose fines or to force a shutdown of a nuclear plant, or both. NRC safety and security requirements have, in the past, necessitated substantial capital expenditures at Diablo Canyon, and additional significant capital expenditures could be required in the future.

The NRC operating license for Diablo Canyon Unit 1 expires in November 2024 and the NRC operating license for Diablo Canyon Unit 2 expires in August 2025.  Under the terms of these licenses, there must be sufficient storage capacity for the radioactive spent fuel produced by the Diablo Canyon plant.  For a discussion of the Utility’s spent fuel storage project, see “Environmental Matters – Nuclear Fuel Disposal,” below.


Irrigation Districts and Water AgenciesCalifornia Legislature

The Utility has contracts withUtility's operations have been significantly affected by various irrigation districts and water agencies to purchase hydroelectric power. Under these contracts, the Utility must make specified semi-annual minimum payments based on the irrigation districts' and water agencies' debt service requirements, regardless of whether or not any hydroelectric power is supplied, and variable payments for operation and maintenance costs incurredstatutes passed by the suppliers. These contracts expire on various dates from 2005 to 2031. The Utility's irrigation district and water agency contracts accounted for approximately 5% of the Utility’s 2005 electricity sources, approximately 5% of the Utility's 2004 electricity sources and approximately 5% of the Utility's 2003 electricity sources.California legislature, including:

·  
Assembly Bill 1890.  Assembly Bill 1890, enacted in 1996, mandated the restructuring of the California electricity industry, commencing in 1998 with the implementation of a market framework for electricity generation in which generators and other energy providers were permitted to charge market-based rates for wholesale electricity and the investor-owned utilities’ customers were given the choice to become “direct access” customers by buying energy from an alternate service provider other than the regulated utilities.  Among other provisions, Assembly Bill 1890 provided for the establishment of the CAISO, as a nonprofit public benefit corporation, to operate and control the state-wide electricity transmission grid and ensure efficient use and reliable operation of the transmission grid.

·  
Assembly Bill 1X.   Assembly Bill 1X was enacted during the California 2000-2001 energy crisis when the California investor-owned electric utilities were no longer able to buy electricity.  Assembly Bill 1X authorized the California Department of Water Resources (“DWR”) beginning on February 1, 2001, to purchase electricity and sell that electricity directly to the investor-owned electric utilities' retail customers. Assembly Bill 1X required the California investor-owned electric utilities to deliver electricity purchased by the DWR under the contracts and to act as the DWR's billing and collection agent.  To ensure that the DWR recovers its costs to procure electricity, Assembly Bill 1X required the CPUC to suspend the right of retail end-user customers to become direct access customers until the DWR no longer procures electricity pursuant to Assembly Bill 1X.  The current DWR contracts terminate at various dates through 2015.  

·  
Assembly Bill 57.   Assembly Bill 57, enacted in September 2002 and amended by Senate Bill 1976, required the California investor-owned utilities to resume purchasing power on January 1, 2003, required the CPUC to allocate electricity to be provided under the DWR contracts among the customers of the California investor-owned electric utilities, requires the utilities to file short- and long-term electricity resource procurement plans with the CPUC for approval, and authorizes the utilities to recover their reasonable wholesale procurement costs incurred under a CPUC-approved procurement plan through the establishment of new electricity procurement balancing accounts to allow timely recovery by the utilities of differences between recorded revenues and costs incurred under the approved procurement plans.

·  
Senate Bill 1078.  Senate Bill 1078, enacted in September 2002 (as amended by Senate Bill 107, enacted in September 2006 and effective on January 1, 2007) established the Renewables Portfolio Standard Program, which requires each California retail seller of electricity, except municipal utilities, to increase its purchases of eligible renewable energy (such as biomass, small hydro, wind, solar and geothermal energy) by at least 1% of its retail sales per year, so that the amount of electricity purchased from eligible renewable resources equals at least 20% of its total retail sales by 2010.

·  
Assembly Bill 380.  Assembly Bill 380, enacted in September 2005, requires the CPUC, in consultation with the CAISO, to establish resource adequacy requirements for all load-serving entities, including the California investor-owned electric

85


Other Power Purchase Agreements
utilities but excluding local publicly owned electric utilities.  Assembly Bill 380 requires each load-serving entity to maintain physical generating capacity adequate to meet its load requirements, including peak demand and planning and operating reserves, deliverable to locations and at times as may be necessary to provide reliable electric service.

·  
Assembly Bill 32.  Assembly Bill 32, enacted in September 2006, requires the California Air Resources Board (“CARB”) to adopt regulations to limit statewide greenhouse gas emission, to 1990 levels by 2020, with certain limits beginning in 2012.  (See “Environmental Matters” below for more information.)

·  
Senate Bill 1368.   Senate Bill 1368, also enacted in September 2006, prohibits any load-serving entity, including investor-owned electric utilities, from entering into a long-term financial commitment for baseload generation (i.e., electricity generation from a power plant that is designed and intended to provide electricity at an annualized plant capacity factor of at least 60%) unless it complies with a greenhouse gas emission performance standard.  (See “Environmental Matters” below for more information.)

Electricity Purchases to Satisfy the Net Open PositionThe CPUC

In 2005,The CPUC has jurisdiction to set the Utility continued buyingrates, terms and conditions of service for the Utility's electricity to meet its net open position, which is the portion of the demand of a utility's customers, plus applicable reserve margins, not satisfied from that utility's owndistribution, electricity generation, facilitiesnatural gas distribution, and existing electricity contracts. During 2005, more than 9,000 GWh of energy was bought or soldnatural gas transportation and storage services in the wholesale market to manage the Utility’s 2005 net open position. Contracts entered into in 2005 had both terms of less than one year, and multi-year terms. In 2005, the Utility both submitted and requested bids in competitive solicitations to meet intermediate and long-term needs and anticipates procuring electricity under contracts with multi-year terms beginning in 2006 or later.

Renewable Energy Contracts

California law requires each California retail seller of electricity, except for municipal utilities, to increase its purchases of renewable energy (such as biomass, wind, solar and geothermal energy) by at least 1% of its retail sales per year, the annual procurement target, so that the amount of electricity purchased from renewable resources equals at least 20% of its total retail sales by the end of 2017. In January 2005, the California Senate introduced a bill proposing to require the goal to be met by the end of 2010 instead of 2017.California. The CPUC also has suggested thatjurisdiction over the 20% goal be met by 2010Utility's issuances of securities, dispositions of utility assets and a 33% goal be met by 2020. The Utility estimates that the accelerated goal would require the Utility to increase the amount of its annual renewablefacilities, energy purchases on behalf of the Utility's electricity and natural gas retail customers, rate of return, rates of depreciation, aspects of the siting and operation of natural gas transportation assets, oversight of nuclear decommissioning and aspects of the siting of the electricity transmission system. Ratemaking for retail sales from the Utility's generation facilities is under the jurisdiction of the CPUC. To the extent that this electricity is sold for resale into wholesale markets, however, it is under the ratemaking jurisdiction of the FERC. In addition, the CPUC has general jurisdiction over most of the Utility’s operations, and regularly reviews the Utility’s performance, using measures such as the frequency and duration of outages. The CPUC also conducts investigations into various matters, such as deregulation, competition and the environment, in order to approximately 800-900 GWh. During 2005,determine its future policies. The CPUC consists of five members appointed by the Governor of California and confirmed by the California State Senate for staggered six-year terms.

PG&E Corporation and the Utility entered into several new renewable power purchase contractsa settlement agreement with the CPUC on December 19, 2003, to resolve the Utility's proceeding filed under Chapter 11 of the U.S. Bankruptcy Code that will helphad been pending in the Utility meet its goals.

ForU.S. Bankruptcy Court for the Northern District of California (“Bankruptcy Court”) since April 2001, referred to as the Chapter 11 Settlement Agreement. The nine-year Chapter 11 Settlement Agreement established certain regulatory assets and addressed various ratemaking matters to restore the Utility’s financial health and enable it to emerge from Chapter 11.  The terms of the Chapter 11 Settlement Agreement were incorporated into the Utility’s plan of reorganization under Chapter 11, which became effective on April 12, 2004.  The Bankruptcy Court does retain jurisdiction to hear and determine disputes arising in connection with the interpretation, implementation or enforcement of the Chapter 11 Settlement Agreement, in addition to other matters. (For more information, regarding the Utility's power purchase contracts, see Note 17: Commitments and Contingencies— Power Purchase Agreements,15 of the Notes to the Consolidated Financial Statements included in the 20052007 Annual Report.)


Electricity TransmissionThe California Energy Resources Conservation and Development Commission, commonly called the California Energy Commission (“CEC”), is the state's primary energy policy and planning agency. The CEC is responsible for licensing of all thermal power plants over 50 MW, overseeing funding programs that support public interest energy research, advancing energy science and technology through research, development and demonstration, and providing market support to existing, new and emerging renewable technologies. In addition, the CEC is responsible for forecasting future energy needs used by the CPUC in determining the adequacy of the utilities' electricity procurement plans.

At December 31, 2005, the Utility owned 18,616 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV and transmission substations with a capacity of 49,158 MVA. Electricity is transmitted across these lines and substations and is then distributed to customers through 128,128 circuit miles of distribution lines and substations with a capacity of 25,254 MVA. In 2005, the Utility delivered 81,626 GWh to its customers, including 8,867 GWh delivered to direct access customers. The Utility is interconnected with electric power systems in the Western Electricity Coordinating Council which includes 14 western states, Alberta and British Columbia, Canada, and parts of Mexico.Other Regulation

InThe Utility obtains permits, authorizations and licenses in connection with the construction and operation of the Utility's generation facilities, electricity industry restructuring,transmission lines, natural gas transportation pipelines and gas compressor station facilities. Discharge permits, various Air Pollution Control District permits, U.S. Department of Agriculture-Forest Service permits, FERC hydroelectric generation facility and transmission line licenses, and NRC licenses are some of the California investor-ownedmore significant examples. Some licenses and permits may be revoked or modified by the granting agency if facts develop or events occur that differ significantly from the facts and projections assumed in granting the approval. Furthermore, discharge permits and other approvals and licenses are granted for a term less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency. (For more information see “Environmental MattersWater Quality” below.)

The Utility has over 520 franchise agreements with various cities and counties that permit the Utility to install, operate and

6


maintain the Utility's electric utilities relinquished control, but not ownership,and natural gas facilities in the public streets and roads.  In exchange for the right to use public streets and roads, the Utility pays annual fees to the cities and counties.  Franchise fees are computed pursuant to statute under either the Broughton Act or the Franchise Act of 1937.  In addition, charter cities can set fees of their transmissionown determination.  In most cases, the Utility’s franchise agreements are for an indeterminate term, with no expiration date.  The Utility has several franchise agreements that have a specified term, including agreements with two large charter cities.  The franchise agreements generally require that the Utility install and maintain the electric and gas facilities in compliance with regulations adopted by cities and counties in the exercise of their police powers relating to the California Independent System Operator, use of the public streets.  The Utility also periodically obtains permits, authorizations and licenses in connection with distribution of electricity and natural gas.  Under these permits, authorizations and licenses, the Utility has rights to occupy and/or the ISO, in 1998. The FERC has jurisdiction over these transmission facilities, and the revenue requirements and ratesuse public property for transmission service are set by the FERC. The ISO, which is regulated by the FERC, controls the operation of the transmission systemUtility's business and provides open access transmission service on a nondiscriminatory basis. The ISO also is responsible for assuring that the reliability of the transmission system is maintained.to conduct certain related operations.


On August 19, 2004, the CPUC also approved a project to install approximately 28 miles of 230-kV transmission line from Redwood City to Brisbane, known as the Jefferson-Martin 230-kV Line. The improvement is intended to provide additional transmission system reliability in San Francisco and northern San Mateo County. Construction of this project is expected to be completed in April 2006.


The Utility owns and operates an integrated natural gas transportation, storage and distribution system in California that extends throughout all or a part of 38 of California's 58 counties and includes most of northern and central California. In 2005, the Utility served approximately 4.2 million natural gas distribution customers. The total volume of natural gas throughput during 2005 was approximately 856 Bcf.

At December 31, 2005, the Utility's natural gas system consisted of 40,704 miles of distribution pipelines, 6,128 miles of backbone and local transmission pipelines and three storage facilities. The Utility's distribution network connects to the Utility's transmission and storage system at approximately 2,200 major interconnection points. The Utility’s backbone transmission system, composed of Lines 300, 400 and 401, is used to transport gas from the Utility’s interconnection with interstate

9


pipelines, other local distribution companies, and California gas fields to the Utility’s local transmission and distribution system. The Utility's Line 300, which interconnects with the U.S. southwest and California-Oregon pipeline systems owned by third parties (Transwestern Pipeline Co., El Paso Natural Gas Company, Questar Southern Trails Pipeline Company and Kern River Pipeline Company), has a receipt capacity at the California-Arizona border of approximately 1.1 Bcf per day. The Utility's Line 400/401 interconnects with the natural gas transportation pipeline of TransCanada's Gas Transmission Northwest Corporation at the California-Oregon border. This line has a receipt capacity at the border of approximately 2.0 Bcf per day. Through interconnections with other interstate pipelines, the Utility can receive natural gas from all the major natural gas basins in western North America, including basins in western Canada, the Rocky Mountains and the southwestern United States. The Utility also is supplied by natural gas fields in California.

The Utility also owns and operates three underground natural gas storage fields connected to the Utility's transmission and storage system. These storage fields have a combined annual cycle capacity of approximately 42 Bcf. In addition, two independent storage operators are interconnected to the Utility's northern California transportation system.

The CPUC divides the Utility's natural gas customers into two categories: core and noncore customers. This classification is based largely on a customer's annual natural gas usage. The core customer class is comprised mainly of residential and smaller commercial natural gas customers. The noncore customer class is comprised of industrial, larger commercial and electric generation natural gas customers. In 2005, core customers represented more than 99% of the Utility's total customers and 40% of its total natural gas deliveries, while noncore customers comprised less than 1% of the Utility's total customers and 60% of its total natural gas deliveries.

The Utility provides natural gas delivery services to all core and noncore customers connected to the Utility's system in its service territory. Core customers can purchase natural gas from alternate energy service providers or can elect to have the Utility provide both delivery service and natural gas supply. When the Utility provides both supply and delivery, the Utility refers to the service as natural gas bundled service. Currently, over 99% of core customers, representing over 96% of core market demand, receive natural gas bundled services from the Utility.

The Utility does not provide procurement service to noncore customers. Electricity generators, cogenerators, enhanced oil recovery and refiners, and other large noncore customers may not transfer to core service, and smaller noncore customers must sign up for a minimum five-year term if they elect to transfer to core service. These restrictions were put in place because large increases in the Utility's natural gas supply portfolio demand from significant transfers of noncore customers to core service would raise prices for all other core procurement customers and obligate the Utility to reinforce its pipeline system to provide core service reliability on a short-term basis to serve this new load.

The Utility offers backbone gas transmission, delivery (local transmission and distribution), and storage services as separate and distinct services to its noncore customers. These customers may elect to receive storage services from the Utility or other third-party storage providers. Noncore customers formerly were able to subscribe for natural gas bundled service as if they were core customers but are no longer allowed to do so. Access to the Utility's backbone gas transmission system is available for all natural gas marketers and shippers, as well as noncore customers.

The Utility has regulatory balancing accounts for core customers designed to ensure that the Utility's results of operations over the long term are not affected by weather variations, conservation or changes in their consumption levels. The Utility's results of operations can, however, be affected by noncore consumption levels because there are fewer regulatory balancing accounts related to noncore customers. Approximately 97% of the Utility's natural gas distribution base revenues are recovered from core customers and 3% are recovered from noncore customers.

The California Gas Report is prepared by the California electric and natural gas utilities to present an outlook for natural gas requirements and supplies for California over a long-term planning horizon. It is prepared in even-numbered years followed by a supplemental report in odd-numbered years. The 2004 California Gas Report forecasts average annual growth in the Utility's natural gas deliveries (for core customers and non-core transportation) of approximately 1.3% for the years 2004 through 2025. The natural gas requirements forecast is subject to many uncertainties and there are many factors that can influence the demand for natural gas, including weather conditions, level of economic activity, conservation, price, and the number and location of electricity generation facilities.



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The following table shows the percentage of the Utility's total 2005 natural gas deliveries represented by each of the Utility's major customer classes:

Total 2005 Natural Gas Deliveries: 856 Bcf

Residential Customers28%
Transport-only Customers (noncore)60%
Commercial Customers12%


The following table shows the Utility's operating statistics from 2001 through 2005 (excluding subsidiaries) for natural gas, including the classification of sales and revenues by type of service:

 
2005
 
2004
 
2003
 
2002
 
2001
Customers (average for the year):         
Residential3,929,117 3,812,914 3,744,011 3,738,524 3,705,141
Commercial216,749 215,547 208,857 206,953 205,681
Industrial962 2,178 1,988 1,819 1,764
Other gas utilities6 6 6 5 6
Total4,146,834 4,030,645 3,954,862 3,947,301 3,912,592
Gas supply (MMcf):         
Purchased from suppliers in:         
Canada204,884 205,180 196,278 210,716 209,630
California(18,951) (9,108) (7,421) 19,533 20,352
Other states103,237 103,801 102,941 67,878 76,589
Total purchased289,170 299,873 291,798 298,127 306,571
Net (to storage) from storage(3,659) (532) 1,359 (218) (27,027)
Total285,511 299,341 293,157 297,909 279,544
Utility use, losses, etc.(1)(14,312) (19,287) (14,307) (16,393) (8,988)
Net gas for sales271,199 280,054 278,850 281,516 270,556
Bundled gas sales (MMcf):         
Residential194,108 201,601 198,580 202,141 197,184
Commercial77,056 78,080 79,891 78,812 72,528
Industrial35 373 379 563 831
Other gas utilities    13
Total271,199 280,054 278,850 281,516 270,556
Transportation only (MMcf):572,869 597,706 525,353 508,090 646,079
Revenues (in millions):         
Bundled gas sales:         
Residential$2,336 $1,944 $1,836 $1,379 $2,308
Commercial885 712 697 499 783
Industrial  1 3 16
Other gas utilities  1 1 
Miscellaneous(22) (29) (31) 127 (93)
Regulatory balancing accounts340 316 68 11 (253)
Bundled gas revenues3,539 2,943 2,572 2,020 2,761
Transportation service only revenue238 270 284 316 375
Operating revenues$3,777 $3,213 $2,856 $2,336 $3,136
Selected Statistics:         
Average annual residential usage (Mcf)49 53 53 54 53
Average billed bundled gas sales revenues per Mcf:         
Residential$12.04 $9.64 $9.25 $6.82 $11.70
Commercial11.48 9.12 8.73 6.33 10.80
Industrial0.61 (0.56) 2.48 4.35 19.15
Average billed transportation only revenue per Mcf0.42 0.45 0.54 0.62 0.58
Net plant investment per customer$1,262 $1,266 $1,261 $1,006 $970
          
(1)Includes fuel for the Utility's fossil fuel-fired generation plants.

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The Utility purchases natural gas to serve the Utility's core customers directly from producers and marketers in both Canada and the United States. The contract lengths and natural gas sources of the Utility's portfolio of natural gas purchase contracts have fluctuated, generally based on market conditions. During 2005, the Utility purchased approximately 289,000 MMcf of natural gas (net of the sale of excess supply) from 57 suppliers. Consistent with existing CPUC policy directives, substantially all this natural gas was purchased under contracts with a term of one year or less. The Utility's largest individual supplier represented approximately 10.4% of the total natural gas volume the Utility purchased during 2005.

The following table shows the total volume and the average price of natural gas in dollars per Mcf of the Utility's natural gas purchases by region during each of the last five years. The average prices for Canadian and U.S. southwest gas shown below include the commodity natural gas prices, pipeline demand or reservation charges, transportation charges and other pipeline assessments. The volumes purchased are shown net of sales of excess supplies of gas. In 2005, the sale of excess supplies to parties located in California exceeded purchases from parties located in California.


  
2005
 
2004
 
2003
 
2002
 
2001
  
MMcf
 
Avg.
Price
 
MMcf
 
Avg.
Price
 
MMcf
 
Avg.
Price
 
MMcf
 
Avg.
Price
 
MMcf
 
Avg.
Price
Canada  204,884 $7.12  205,180 $5.37  196,278 $4.73  210,716 $2.42  209,630 $4.43
California(1)  (18,951)$7.70  (9,108)$4.89  (7,421)$3.39  19,533 $2.88  20,352 $11.55
Other states (substantially all U.S southwest)  103,237 $7.10  103,801 $5.44  102,941 $4.63  67,878 $3.04  76,589 $10.41
Total/weighted average  289,170 $7.07  299,873 $5.41  291,798 $4.73  298,127 $2.59  306,571 $6.40
(1)California purchases include supplies from various California producers and supplies transported into California by others.


The Utility's gas gathering system collects natural gas from third-party wells in California. During 2005, approximately 4% of the gas transported on the Utility's system came from various California producers, with the balance coming from supplies transported into California by others. The natural gas well production is processed by producers to remove various impurities from the natural gas stream and the Utility then odorizes the natural gas so that it may be detected in the event of a leak. The facilities include approximately 420 miles of gas gathering pipelines. The Utility receives gas well production at approximately 300 metering facilities. The Utility’s gas gathering system is geographically dispersed and is located in 13 California counties. Approximately 119 MMcf per day of natural gas produced in northern California was delivered into the Utility's gas gathering system during 2005.


In 2005, approximately 65% of the gas transported on the Utility's system came from western Canada. The Utility has a number of arrangements with interstate and Canadian third-party transportation service providers to serve core customers' service demands. The Utility has firm transportation agreements for delivery of natural gas from western Canada to the United States- Canadian border with TransCanada NOVA Gas Transmission, Ltd. and TransCanada PipeLines Ltd., B.C. System. These companies' pipeline systems connect at the border to the pipeline system owned by Gas Transmission Northwest Corporation which provides natural gas transportation services to interconnection points with the Utility's natural gas transportation system in the area of California near Malin, Oregon. The Utility has a firm transportation agreement with Gas Transmission Northwest Corporation for these services.

During 2005, approximately 31% of the gas transported on the Utility's system came from the western United States, excluding California. The Utility has firm transportation agreements with Transwestern Pipeline Co., or Transwestern, and El Paso Natural Gas Company, or El Paso, to transport this natural gas from supply points in this region to interconnection points with the Utility's natural gas transportation system in the area of California near Topock, Arizona.

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The following table shows certain information about the Utility's firm natural gas transportation agreements, including the contract quantities, contract durations and associated demand charges, net of sales of excess supplies, for capacity reservations. These agreements require the Utility to pay fixed demand charges for reserving firm capacity on the pipelines. The total demand charges may change periodically as a result of changes in regulated tariff rates approved by Canadian regulators in the case of TransCanada NOVA Gas Transmission, Ltd. and TransCanada PipeLines Ltd., B.C. System, and by the FERC in all other cases. The Utility recovers these demand charges through the Core Procurement Incentive Mechanism, or CPIM. The Utility may, upon prior notice and with the CPUC’s approval, extend each of these natural gas transportation agreements. On the FERC-regulated pipelines, the Utility has either a right of first refusal or evergreen rights allowing it to renew natural gas transportation agreements at the end of their terms. If another prospective shipper also wants the capacity, the Utility would be required to match the competing bid with respect to both price and term.


Pipeline
 
Expiration
Date
  
Quantity
MDth per day
 
Demand Charges
for the Year Ended
December 31, 2005
(In millions)
        
TransCanada NOVA Gas Transmission, Ltd. 12/31/2007
(a)
 616 28.0
TransCanada PipeLines Ltd., B.C. System 10/31/2007  607 13.0
Gas Transmission Northwest Corporation 10/31/2007  610 54.8
Transwestern Pipeline Co. 03/31/2007  150 20.5
El Paso Natural Gas Company (b) Various  202 19.2
(a)A small portion (23 MDth/d) of the Utility’s capacity is due to expire on October 31, 2007.
(b)As of December 31, 2005, the Utility has three active contracts with El Paso with expiration dates ranging from June 30, 2007 to June 30, 2010.


Historically, energy utilities operated as regulated monopolies within service territories wherein which they were essentially the sole suppliers of natural gas and electricity services. These utilities owned and operated all of the businesses and facilities necessary to generate, transport and distribute energy. Services were priced on a combined, or bundled, basis with rates charged by the energy companies designed to include all the costs of providing these services. Under traditional cost-of-service regulation, the utilities undertook a continuing obligation to serve their customers, in return for which the utilities were authorized to charge regulated rates sufficient to recover their costs of service, including timely recovery of their operating expenses and a reasonable return on their invested capital. The objective of this regulatory policy was to provide universal access to safe and reliable utility services. Regulation was designed in part to take the place of competition and ensure that these services were provided at fair prices.

In recent years, energy utilities have faced intensifying pressures to unbundle, or price separately, those services that are no longer considered natural monopolies. The most significant of these services are the commodity components—the supply of electricity and natural gas. The driving forces behind these competitive pressures have been customers who believe that they can obtain energy at lower unit prices and competitors who want access to those customers. Regulators and legislators responded to these forces by providing for more competition in the energy industry. Regulators and legislators, to varying degrees, have required utilities to unbundle rates in order to allow customers to compare unit prices of the utilities and other providers when selecting their energy service provider.


Federal.  At the federal level, many provisions of the EPAct support the development of competition in the wholesale electric market. The EPAct has directed the FERC to develop rules to encourage fair and efficient competitive markets by employing best practices in market rules and reducing barriers to trade between markets and among regions. The EPAct also gives the FERC authority to prevent accumulation and exercise of market power by assuring that proposed mergers and acquisitions of public utility companies and their holding companies are in the public interest and by addressing market power in jurisdictional wholesale markets through its new powers to establish and enforce rules prohibiting market manipulation.

Even before the passage of the EPAct, the FERC's policies have supported the development of a competitive electricity generation industry. FERC Order 888, issued in 1996, established standard terms and conditions for parties seeking access to regulated utilities' transmission grids.  Order 888 requires all public utilities that own, control or operate facilities used for transmitting electric energy in interstate commerce to have on file an open access non-discriminatory transmission tariff (“OATT”) that contains minimum terms and conditions of non-discriminatory service.  The FERC's subsequent Order 2000, issued in late 1999, established national standards for regional transmission organizations, or RTOs, and advanced the view that a regulated, unbundled transmission sector should facilitate competition in both wholesale electricity generation and retail electricity markets. The ISO alsoOn February 16, 2007, the FERC issued its own comprehensive energy market design proposal to effect changes toOrder 890, which is designed to: (1) strengthen the structure and operationform of the California electricity market. The first phaseOATT adopted in Order 888 to ensure that tariffs achieve their original purpose of remedying undue discrimination; (2) provide greater specificity in the form of the ISO’s new market design has been approved byOATT to reduce opportunities for undue discrimination and facilitate the FERCFERC’s enforcement; and was implemented by the ISO(3) increase transparency in the fourth quarter of 2004. On February 14, 2006, the ISO filed its proposed tariff language with the FERCrules applicable to implement the balance of its market design proposal. Assuming FERC approval, the balanceplanning and use of the ISO’s new market design could be implemented as early as November 2007.transmission system.

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In July 2003, in orderThe FERC also has issued rules on the interconnection of generators to require regulated transmission providers, such as the Utility or the CAISO, to use standard interconnection procedures and a standard agreement for generator interconnections.  These rules are intended to limit opportunities for transmission providers to favor their own generation, facilitate market entry for generation competitors by streamlining and standardizing interconnection procedures, and encourage needed investment in generatorgeneration and transmission infrastructure,transmission. Under the FERC issued final rules on the interconnection of generators larger than 20 MW withand associated tariffs, a transmission system. The new rules require regulated transmission providers, such as the Utility or the ISO, generally to use standard interconnection procedures and a standard agreement for generator interconnections. These rules required the Utility and the ISO to revise the current form of agreements and procedures used when constructing facilities to interconnect new generators. In July 2005, the FERC accepted tariff changes filed by the Utility and the ISO to implement the new rules. In doing so, the FERC confirmed that the ISO is authorized to implement California-specific modifications to the FERC's pro forma agreement and procedures for new interconnections under what is known as an "independent entity variation." The new rules, tariffs and related interconnection procedures establish time-frames for completing studies on behalf of new generator applicants, and codifyis required to pay for the FERC's preexisting policy regarding financing of transmission system upgrades needed in order to interconnect a newthe generator. Under this policy, theThe generator must finance such upgrade facilities in the first instance, but then iswill be reimbursed the funds, with interest, over a five-year period after the power plant achieves commercial operation. The cost of the network upgrades then is recovered by the Utilityregulated transmission provider in its overall transmission rates.


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In 1998, California implemented ABState.  At the state level, Assembly Bill 1890, whichenacted in 1996, mandated the restructuring of the California electricity industry andcommencing in 1998.  Assembly Bill 1890 established a market framework for electricity generation in which generators and other electricity providers were permitted to charge market-based prices for wholesale electricity.electricity through transactions conducted through the Power Exchange (“PX”).  As a result of the California 2000-2001 energy crisis, the PX filed a petition for bankruptcy protection and now operates solely to reconcile remaining refund amounts owed and to make compliance filings as required by the FERC in the California refund proceeding, which is still pending at the FERC.  (For information about the status of the California refund proceeding and the remaining disputed claims made by power suppliers in the Utility’s Chapter 11 proceeding, see Note 15 of the Notes to the Consolidated Financial Statements in the 2007 Annual Report.)  The CAISO, which was established pursuant to AB 1890 also gave customers the choiceto take control of continuing to buy electricity from the California investor-owned electric transmission facilities located in California, currently administers a real-time or “spot” wholesale market for the sale of electric energy. This market is used to allocate space on the transmission lines, maintain operating reserves, and match supply with demand in real time.  The CAISO’s MRTU initiative is intended to restructure the California electricity market and to enhance power grid reliability, including the implementation of a new day-ahead market.  The CAISO also will provide congestion revenue rights to allow market participants, including load-serving entities, to hedge the financial risk of CAISO-imposed congestion charges in the MRTU day-ahead market.  The MRTU tariffs will apply to all load-serving entities, including the investor-owned utilities, or, beginningserving California consumers.  The CAISO has delayed the start date of MRTU several times and has indicated that it will not set a new date for commencement of MRTU until market participants have had an opportunity to test the final MRTU functionality and have provided feedback to the CAISO.  Also, in April 1998, entering into contractsJanuary 2008, the CPUC staff issued its recommendation to purchaseestablish a statewide wholesale electricity from alternatecapacity market to replace the current resource adequacy program.  The CPUC is expected to issue a decision on this matter in May 2008.  Any changes the CPUC adopts would be subject to the FERC’s approval.

Assembly Bill 1890 also permitted retail end-use customers to choose their energy service providers (i.e.,provider by becoming a direct access customers). Thecustomer.  To ensure that the DWR recovers its costs to procure electricity for the customers of the investor-owned electric utilities, Assembly Bill 1X required the CPUC suspendedto suspend the right of retail end-user customers to become direct access customers until the DWR no longer procures electricity on behalf of the customers of the California investor-owned electric utilities. The CPUC suspended direct access on September 20, 2001.2001, but allowed existing direct access customers to continue being served by alternative energy service providers, rather than investor-owned electric utilities. The CPUC has assessed an additional charge on certain direct access customers to avoid a shift of costs from direct access customers to customers who receive bundled service.  The CPUC is scheduled to vote on February 28, 2008 on a proposed decision that concludes the CPUC does not have the authority to reinstate direct access because the DWR still supplies power under the contracts it executed during the energy crisis.  The proposed decision states that the CPUC will proactively investigate how the DWR can terminate its obligations under the power contracts, by assignment or otherwise, to hasten the reinstatement of direct access.

In addition, the Utility’s customers may, under certain circumstances, obtain power from a “community choice aggregator” instead of from the Utility.  California ABAssembly Bill 117, enacted in 2002, permits cities and counties to purchase and sell electricity for their local residents and businesses once they have registered as community choice aggregators.  Under ABAssembly Bill 117, the Utility would continue to provide distribution, metering and billing services to the community choice aggregators' customers and would be those customers' provider of electricity of last resort.  However, once registration has occurred, each community choice aggregator would procure electricity for all of its residents who do not affirmatively elect to continue to receive electricity from the Utility.  ToThe CPUC has adopted rules to implement community choice aggregation, including the imposition of a surcharge on retail end-users of the community choice aggregator to prevent a shifting of costs to customers of a utility who receive bundled services, AB 117 requires the CPUC to determine a cost-recovery mechanism so that retail end-users of the community choice aggregator will pay an appropriate share of the DWR's and the Utility's costs. ABservices. Assembly Bill 117 also authorized the Utility to recover from each community choice aggregator any costs of implementing the program that are reasonably attributable to the community choice aggregator, and to recover from customers any costs of implementing the program not reasonably attributable to a community choice aggregator.  In December 2005, the CPUC adopted rules that allow for the implementation ofNo cities or counties are currently operating as community choice aggregation.aggregators, but the San Joaquin Valley Power Authority has filed an implementation plan and stated that it intends to begin operating in 2008.


FERC Order 636, issued in 1992, required interstate natural gas pipeline companies to divide their services into separate gas commodity sales, transportation and storage services. Under Order 636, interstate natural gas pipeline companies must provide transportation service regardless of whether or not the customer (often a local gas distribution company) buys the natural gas commodity from these companies. The Utility’s natural gas pipelines are located within the State of California and are exempt from FERC rules and regulations applicable to interstate pipelines.

Thepipelines; the Utility’s pipeline operations are instead subject to the jurisdiction of the CPUC.  In 1998,The Utility’s gas transmission and storage system has operated under the Utility implementedCPUC-approved “Gas Accord” market structure since 1998.  This market structure largely mimics the regulatory framework required by FERC for interstate gas pipelines. The CPUC divides the Utility's natural gas customers into two categories: “core” customers, which are primarily small commercial and residential customers, and “non-core” customers, which are primarily industrial, large commercial and electric generation customers.  Under the Gas Accord settlement agreement,structure, non-core customers have access to capacity rights for firm service, as well as interruptible (or “as-available”) services.  All

8



services are offered on a CPUC-approvednondiscriminatory basis to any creditworthy customer.  The Gas Accord market structure has resulted in a robust wholesale gas commodity market at the Utility’s “citygate,” which refers to the interconnection between the big “backbone” gas transmission system and the smaller, downstream local transmission systems.

The Utility’s first Gas Accord, a settlement agreement reached among the Utility and many interested parties, under whichwas approved by the CPUC in 1997, took effect on March 1, 1998, and was renewed, with slight modifications, for various successive periods.  In September 2007, the CPUC approved the Gas Accord IV covering 2008 through 2010.  The Gas Accord separated the Utility’s natural gas transportationtransmission and storage rates from its distribution services and rates.  The Gas Accord also changed the nature of the Utility’s transmission and storage services the Utility provides were separatedby creating path-specific transmission services, firm and interruptible service offerings, standard and negotiated rate options, and a secondary market for ratemaking purposes fromtrading of firm capacity rights.  Additionally, the Utility's distribution services. The Gas Accord changedeliminated balancing account protection for some services, increasing the terms of service and rate structure for natural gas transportation, allowing the Utility's core customers greater flexibility to purchase natural gas from competing suppliers. The Utility's noncore customers purchase their natural gas from producers, marketers and brokers, and purchase their preferred mix of transportation, storage and distribution services from the Utility. Although they can select the gas suppliers of their choice, substantially all core customers buy natural gas, as well as transportation and distribution services, from the Utility as a bundled service. The Gas Accord market structure has been extended by the CPUC through 2007.Utility’s risk/reward potential.

The Utility competes with other natural gas pipeline companies for customers transporting natural gas into the southern California market on the basis of transportation rates, access to competitively priced supplies of natural gas, and the quality and reliability of transportation services. The most important competitive factor affecting the Utility's market share for transportation

14


of natural gas to the southern California market is the total delivered cost of western Canadian natural gas relative to the total delivered cost of natural gas from the southwestern United States. The total delivered cost of natural gas includes, in addition to the commodity cost, transportation costs on all pipelines that are used to deliver the natural gas, which, in the Utility's case, includes the cost of transportation of the natural gas from Canada to the California border and the amount that the Utility charges for transportation from the border to southern California. In general, when the total cost of western Canadian natural gas increases relative to other competing natural gas sources, the Utility's market share of transportation services into southern California decreases.  The Utility also competes for storage services with other third-party storage providers, primarily in northern California.

From time to time, existing pipeline companies propose to expand their pipeline systems for delivery of natural gas into northern and central California. As a result of the California energy crisis, several new natural gas pipeline proposals were initiated to serve proposed new generation facilities for northern and central California. Many of the electricity generation projects have been cancelled or delayed, making it difficult for sponsors of the various gas pipeline projects to acquire enough firm capacity commitments to go forward with construction.

The Utility,PG&E Corporation, through its subsidiary, PG&E Strategic Capital, Inc., along with Fort Chicago Energy Partners, L.P. and Northwest Pipeline Corporation, have agreed to jointly pursue the development of a new 250-mile230-mile interstate gas transmission pipeline that would increase natural gas supplies for the entire West Coast region of the United States. The proposed Pacific Connector Gas Pipeline, expected to be operational in 2010, together with the proposed Jordan Cove liquefied natural gas or LNG,(“LNG”) terminal in Coos Bay, Oregon, being developed by Fort Chicago Partners.Partners, L.P., would open growing West Coast natural gas markets to diverse worldwide natural gas supply sources, providing additional alternatives to traditional Canadian, Southwest and Rocky Mountain supplies and increasing supply options and reliability. The proposed Pacific Connector projectGas Pipeline would connect the proposed Jordan Cove LNG terminal to Northwest Pipeline Corporation’s pipeline system near Roseburg,in Oregon, and to the Utility's backbone gas transmission system near Malin, Oregon. Other potential interconnects include Tuscarora Gas Transmission Company’s pipeline system, which serves northern Nevada. The proposed Pacific Connector Gas Pipeline would be capable of delivering 1 bcf per day to the West Coast natural gas market, - both to customers in the Pacific Northwest through Northwest Pipeline Corporation's pipeline system, and to the Utility's system for delivery to customers in California. The group intendsCalifornia, and to seek market commitments forcustomers in northern Nevada through Tuscarora Gas Transmission Company’s pipeline system.  In September 2007, applications with the FERC were filed to request authorization to construct the proposed pipeline projectPacific Connector Gas Pipeline and to begin environmental assessments alongthe Jordan Cove LNG terminal.  It is expected that the FERC will issue a decision by the end of 2008.

The development and construction of the Pacific Connector Gas Pipeline depends upon the construction of the proposed routeLNG terminal at Jordan Cove by Fort Chicago Partners, L.P.  PG&E Corporation cannot predict whether Fort Chicago Partners, L.P. will be successful in April 2006. The group plans to file an application to seekcompleting the FERC's approval fordevelopment and construction of its proposed LNG terminal.  In addition, the new pipeline by January 2007. Subject to regulatory approval,development and construction of the proposed LNG terminal and pipelinethe proposed Pacific Connector Gas Pipeline are subject to obtaining required permits, regulatory approvals, and commitments under long-term capacity contracts.  Assuming the required permits, authorizations, and long-term capacity commitments are timely received and that other conditions are timely satisfied, it is anticipated tothat the proposed LNG terminal and the proposed Pacific Connector Gas Pipeline would begin commercial operation in 2010.2011.


Federal Energy Regulation

The Public Utility Holding Company Act of 1935, or PUHCA, imposed structural and regulatory approval requirements on certain public utility holding companies that have limited their utility operations to a single integrated system. These requirements primarily related to sales and acquisitions of utility property and securities, issuance of securities by the top-level holding company, and various affiliate arrangements involving extensions of credit and the provision of goods, services or construction. PUHCA prevented these holding companies from owning other businesses that are not reasonably incidental or functionally related to the utility business. PUHCA also discouraged ownership of U.S. electric and gas utilities by domestic industrial and financial institutions and by foreign institutions generally. As a holding company with utility operations confined to one state,In December 2007, PG&E Corporation entered into a letter of intent with El Paso Corporation to acquire a 25.5% interest in El Paso Corporation’s proposed 680-mile, 42-inch natural gas transmission pipeline (the “Ruby Pipeline”) that would begin at the Opal Hub in Wyoming and its subsidiaries were exempt from most of PUHCA’s requirements.
In August 2005, a comprehensive federal energy bill namedterminate at the “Energy Policy Act of 2005” was enacted. Among its key provisions, the Energy Policy Act of 2005 repealed PUHCA, effective February 8, 2006, and enacted in its place the Public Utility Holding Company Act of 2005, or PUHCA 2005. Under PUHCA 2005, public utility holding companies fall principally under the regulatory oversight of the FERC, rather than the SEC (which previously administered PUHCA). On December 8, 2005, the FERC issued its final rule implementing PUHCA 2005 and, among other actions, adopted a requirement that, unless otherwise eligible for exemption, every utility holding company provide the FERC with access to its books and records that are relevant to the FERC’s ratemaking responsibilities.Malin, Oregon, interconnect, near California’s northern border.  The authorities granted to the FERC under PUHCA 2005 are supplementary to and somewhat duplicative of authorities it holds under other applicable law. On February 7, 2006, the FERC decided that it will rehear its December 8, 2005 order. In addition to providing for FERC access to utility holding company books and records and other matters, PUHCA 2005 also provides for access by state utility commissions to utility holding company books and records in certain circumstances..

The Energy Policy Act of 2005 modifies the FERC's authority and standard of review with respect to mergers and consolidations. The repeal of PUHCARuby Pipeline is expected to trigger a periodhave an initial capacity of consolidation among public utilities, as well as

15


acquisitions1.2 bcf per day and be expandable to 2 bcf per day.  The proposed Ruby Pipeline would connect Rocky Mountain natural gas producers with northern California, Nevada, and the Pacific Northwest to provide natural gas users with competitively priced natural gas.  PG&E Corporation’s acquisition of public utilities by other businesses. As a result,an interest in the repeal of PUHCA could increase competitive pressures on the energy utility industry, including competition from sources the Utility does not currently view as competitors.

State Energy Regulation

PG&E CorporationRuby Pipeline project is not a public utility under the laws of California and is not subject to regulation as such by the CPUC. CPUC approval authorizing the formation of holding companies has been granted subject to various conditions, set forth in CPUC decisions issued in 1996including the negotiation and 1999 relatedexecution of the partnership documents.  Subject to finance, human resources, recordsobtaining the required regulatory and bookkeeping, andother approvals, including the transferapprovals of customer information. In 2004, the California Courtboards of Appeal issued an opinion finding that the CPUC has limited jurisdiction over the holding companies to enforce these conditions. The financial conditions provide that:

·  The Utility is precluded from guaranteeing any obligationsdirectors of PG&E Corporation without prior written consent from the CPUC;

·  The Utility's dividend policy must continue to be established by the Utility's Board of Directors as though the Utility were a stand-alone utility company;

·  The capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility's obligation to serve or to operate the Utility in a prudent and efficient manner, must be given first priority by PG&E Corporation's Board of Directors (known as the “first priority” condition); and

·  The Utility must maintain on average its CPUC-authorized utility capital structure, although it shall have an opportunity to request a waiver of this condition if an adverse financial event reduces the Utility's equity ratio by 1% or more.

As discussed below under "Item 3—Legal Proceedings," the California Attorney General and the City and County of San Francisco have alleged that PG&E Corporation and its directors, as well as the directors of the Utility, violated the CPUC’s holding company conditions during the California energy crisis. PG&EEl Paso Corporation, and after obtaining necessary customer commitments, the Utility believe that they have complied with applicable statutes, CPUC decisions, rules and orders.Ruby Pipeline is anticipated to be in service in the first quarter of 2011.




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The CPUC also has adopted complex and detailed rules governing transactions between California's electricity and natural gas distribution companies and their non-regulated affiliates. The rules address the use of the regulated utilities’ name and logo by their non-regulated affiliates, the separation of regulated utilities and their non-regulated affiliates, information exchange among the affiliates, and power-procurement related transactions among regulated utilities and their non-regulated affiliates. The rules also prohibit each utility from engaging in certain practices that would discriminate against energy service providers that compete with that utility's non-regulated affiliates.Overview

The CPUC also has established specific penalties and enforcement procedures for affiliate rules violations. Utilities are required to self-report affiliate rules violations.

In October 2005, the CPUC issued an Order Instituting Rulemaking, or OIR, to allow the CPUC to re-examine the relationship between California energy utilities and their parent holding companies and affiliates. The CPUC noted that in light of the repeal of PUHCA, as discussed above, the parent holding companies of the California energy utilities may try to expand the unregulated activities of their affiliates, may try to merge with or acquire other companies or may be acquired by other companies, and that it was necessary for the CPUC to review its existing regulations and to consider whether additional, new rules or regulations are needed. The CPUC stated that it may propose rules to ensure that the California energy utilities retain sufficient capital and the ability to access capital in order to meet their customers' needs, and to address the potential conflicts between the utilities' ratepayers' interests and the parent holding companies' and affiliates' interests in order to ensure that these conflicts do not undermine the utilities' ability to meet their public service obligations at the lowest possible cost. The CPUC stated that it may propose additional rules or regulations regarding, but not necessarily limited to, (1) reporting requirements for the allocation of capital between utilities and their non-regulated affiliates by the parent holding companies, and (2) changes to the CPUC's affiliate transaction rules.  
The Utility's Regulatory Environment

Various aspects of the Utility's business are subject to a complex set of energy, environmental and other governmental laws, regulations and regulatory proceedings at the federal, state and local levels. This section and the "Ratemaking Mechanisms"

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section below summarize some of the more significant laws, regulations and regulatory mechanisms affecting the Utility. These sections are not an exhaustive description of all the laws, regulations and regulatory proceedings that affect the Utility. The energy laws, regulations and regulatory proceedings may change or be implemented or applied in a way that the Utility does not currently anticipate. For discussion of specific regulatory proceedings affecting the Utility, see the section of MD&A entitled “Regulatory Matters” in the 2005 Annual Report.


The FERC

The FERC is an independent agency within the U.S. Department of Energy, or the DOE, that regulates the transmission and wholesale sales of electricity in interstate commerce and the transmission and sale of natural gas for resale in interstate commerce. The FERC also regulates electricity transmission, interconnections, tariffs and conditions of service of the ISO, and the terms and rates of wholesale electricity sales. The ISO is responsible for providing open access transmission service on a non-discriminatory basis, meeting applicable reliability criteria, planning transmission system additions and assuring the maintenance of adequate reserves of generation capacity. In addition, the FERC has jurisdiction over the Utility's electricity transmission revenue requirements and rates, the licensing of substantially all of the Utility's hydroelectric generation facilities and the interstate sale and transportation of natural gas.

As discussed above, the Energy Policy Act of 2005 contains provisions addressing electric transmission and natural gas pipeline siting and investment, siting of LNG terminals, energy efficiency, and electric market manipulation. The Energy Policy Act of 2005 also changes the FERC regulatory scheme applicable to QFs, creates an Electric Reliability Organization to be overseen by the FERC to establish electric reliability standards, and modifies certain other aspects of energy regulation and federal tax policies applicable to the Utility. In addition, the Energy Policy Act of 2005 gives the FERC broader authority to police and penalize the exercise of market power or behavior intended to manipulate the prices paid in FERC-jurisdictional transactions. In January 2006, the FERC adopted rules to prohibit market manipulation, modeling its new rules on SEC Rule 10b-5 which prohibits fraud and manipulation with respect to the purchase or sale of securities. In response to the California energy crisis, the FERC issued a series of orders in the spring and summer of 2001 and July 2002 aimed at prospectively mitigating extreme wholesale energy prices like those that prevailed in 2000 and 2001. These orders established a cap on bids for real-time electricity and ancillary services of $250 per MWh (unless a generator could demonstrate that its costs justified a rate in excess of $250 per MWh) and established various automatic mitigation procedures. As of December 2003, all sellers with market-based rate authority became subject to, and incorporated in their market-based rate tariffs, behavioral conditions designed to prevent market manipulation. The FERC has proposed to repeal these behavioral conditions in favor of its more generalized prohibition on market manipulation that it adopted in January 2006 based on SEC Rule 10b-5, as discussed above.  On January 13, 2006, the FERC approved an increase in the energy price cap, from $250 to $400 per MWh, in response to the ISO’s request to reflect natural gas price increases. The FERC's January 13 order also initiated a proceeding to consider whether to extend the energy price cap increase throughout the Western Electricity Coordinating Council area, as well as whether to increase the price cap for ancillary services to the same level as the energy price cap.

Various entities, including the Utility and the state of California are seeking refunds from energy suppliers in the California ISO and California Power Exchange, or PX, markets for electricity overcharges on behalf of California electricity purchasers for the period May 2000 to June 2001 through FERC regulatory and judicial proceedings. The Utility has entered into settlements with various power suppliers resolving certain disputed claims and the Utility's refund claims against these power suppliers. For further discussion of these settlements, see the section of Note 17: Commitments and Contingencies—California Energy Crisis Proceedings, of the Notes to the Consolidated Financial Statements in the 2005 Annual Report.

The NRC

The NRC oversees the licensing, construction, operation and decommissioning of nuclear facilities, including the Utility's Diablo Canyon power plant and Humboldt Bay Unit 3. NRC regulations require extensive monitoring and review of the safety, radiological, environmental and security aspects of these facilities. In the event of non-compliance, the NRC has the authority to impose fines or to force a shutdown of a nuclear plant, or both. Safety requirements promulgated by the NRC have, in the past, necessitated substantial capital expenditures at the Utility's Diablo Canyon power plant and additional significant capital expenditures could be required in the future.

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The CPUC

The CPUC has jurisdiction to set the rates, terms and conditions of service for the Utility's electricity distribution, natural gas distribution and natural gas transportation and storage services in California. The CPUC also has jurisdiction over the Utility's issuances of securities, dispositions of utility assets and facilities, energy purchases on behalf of the Utility's electricity and natural gas retail customers, rate of return, rates of depreciation, aspects of the siting and operation of natural gas transportation assets, oversight of nuclear decommissioning and aspects of the siting of the electricity transmission system. Ratemaking for retail sales from the Utility's generation facilities is under the jurisdiction of the CPUC. To the extent this electricity is sold for resale into wholesale markets, however, it is under the ratemaking jurisdiction of the FERC. In addition, the CPUC has general jurisdiction over most of the Utility’s operations, and regularly reviews utility performance, using measures such as the frequency and duration of outages. The CPUC also conducts investigations into various matters, such as deregulation, competition and the environment, in order to determine its future policies. The CPUC consists of five members appointed by the Governor of California and confirmed by the California State Senate for staggered six-year terms.

The California Energy Resources Conservation and Development Commission

The California Energy Resources Conservation and Development Commission, commonly called the California Energy Commission, or CEC, is the state's primary energy policy and planning agency. The CEC is responsible for licensing of all thermal power plants over 50 MW; overseeing funding programs that support public interest energy research; advancing energy science and technology through research, development and demonstration; and providing market support to existing, new and emerging renewable technologies. In addition, the CEC is responsible for forecasting future energy needs that will be used by the CPUC in determining the adequacy of the utilities' electricity procurement plans.


The Utility obtains a number of permits, authorizations and licenses in connection with the construction and operation of the Utility's generation facilities, electricity transmission lines, natural gas transportation pipelines and gas compressor station facilities. Discharge permits, various Air Pollution Control District permits, U.S. Department of Agriculture-Forest Service permits, FERC hydroelectric generation facility and transmission line licenses, and NRC licenses are some of the more significant examples. Some licenses and permits may be revoked or modified by the granting agency if facts develop or events occur that differ significantly from the facts and projections assumed in granting the approval. Furthermore, discharge permits and other approvals and licenses are granted for a term less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency. The Utility currently has seven hydroelectric projects and one transmission line project undergoing FERC relicensing. The Utility will begin relicensing proceedings on two additional hydroelectric projects within the next two years.

The Utility has over 520 franchise agreements with various cities and counties that permit the Utility to install, operate and maintain the Utility's electric, natural gas, oil and water facilities in the public streets and roads. In exchange for the right to use public streets and roads, the Utility pays annual fees to the cities and counties under the franchises. Franchise fees are computed pursuant to statute under either the Broughton Act or the Franchise Act of 1937. However, there are 38 charter cities that can set a fee of their own determination. The Utility also periodically obtains permits, authorizations and licenses in connection with distribution of electricity and natural gas. Under these permits, authorizations and licenses, the Utility has rights to occupy and/or use public property for the operation of the Utility's business and to conduct certain related operations.



Cost-of-Service Ratemaking

The Utility’s rates for electricity and natural gas utility services are based on its costs of service.providing service (called cost-of-service ratemaking).  Before setting rates, can be set, the CPUC and the FERC must determine the annual amount of “revenue requirements”revenue (called revenue requirements) that the Utility is authorized to collect from its customers to recover the Utility’s operating and capital costs.customers.  The CPUC determines the Utility’s revenue requirements associated with electricity and gas distribution operations, electricity generation, and natural gas transportation and storage.  The FERC determines the Utility’s revenue requirements associated with its electricity transmission operations are established by the FERC. Revenue

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requirements are primarily determined based on the Utility’s forecast of future costs, including electricity and natural gas procurement costs. The components of revenue requirements for electricity and natural gas utility service include depreciation, operating, administrative and general expenses, taxes and return on investment, as applicable, for each area of these services, including distribution, transmission, transportation, generation, procurement and public purpose programs. Revenue requirements are then allocated among customer classes and specific rates designed to produce the required revenue are established. In the Utility's rate cases, interveners have the opportunity to comment on the Utility's application. The issues raised by these comments are then resolved by the appropriate regulatory agency. If the Utility and the interveners can settle these issues, these settlements are submitted to the regulatory agency for approval. Changes in any individual revenue requirement will affect customers' electricity and gas rates and the Utility's revenues.operations.

Revenue requirements are designed to allow a utility an opportunity to recover its reasonable operating and capital costs of providing utility services includingas well as a return of, and a fair rate of return on, its investment in utility facilities (called rate base).  Revenue requirements are primarily determined based on the Utility’s forecast of future costs.  These costs include the Utility’s costs of electricity and natural gas purchased for its customers, operating expenses, administrative and general expenses, depreciation, taxes, and public purpose programs.

Regulatory balancing accounts are used to adjust the Utility’s revenue requirements.  Sales balancing accounts track differences between the Utility’s recorded revenues and its authorized revenue requirements, due primarily to sales fluctuations.  Cost balancing accounts track differences between the Utility’s incurred costs and its authorized revenue requirements, most importantly for energy commodity costs and volumes.  Balances in all CPUC-authorized accounts are subject to review, verification audit, and adjustment, if necessary, by the CPUC.

To develop retail rates, the revenue requirements are allocated among customer classes (mainly residential, commercial, industrial and agricultural) and to various service components (mainly customer, demand, and energy).  Specific rate components are designed to produce the required revenue.  Rate changes become effective prospectively on or after the date of CPUC or FERC decisions.  Most rate changes approved by the CPUC throughout the year are consolidated to take effect on the first day of the following year.

Through cost-of-service ratemaking, rates are developed to produce the revenue requirements, including the authorized return on rate base.  To the extent that the Utility is unable to recover its costs through rates because the Utility’s actual costs are determined to be unreasonable or are higher than forecast, theThe Utility may be unable to earn its authorized rate of return.return because the CPUC or the FERC excludes the Utility’s actual costs from the revenue requirements or because the Utility’s actual costs are higher than those reflected in the revenue requirements.

While the CPUC generally uses cost-of-service ratemaking to develop revenue requirements and rates, it selectively uses incentive ratemaking, which bases rates on objective or fixed standards instead of on the cost of providing service.  The primary example is the Utility’s customer energy efficiency shareholder incentive mechanism.  In September 2007, the CPUC established incentive ratemaking mechanisms applicable to the California investor-owned utilities’ implementation of their energy efficiency programs funded for the 2006-2008 and 2009-2011 program cycles.  (For more information, see “Public Purpose and Other Programs” below.) Another example is the Core Procurement Incentive Mechanism (“CPIM”) under which the Utility's natural gas purchase costs are compared to an aggregate market-based benchmark, and the Utility’s shareholders share in the costs or savings outside a tolerance band around the benchmark.  (See “Natural Gas Procurement” below.)



The Utility's primary revenue requirement proceedingGeneral Rate Case (“GRC”) is the general rate case, or GRC, filed with the CPUC. In the GRC,primary proceeding in which the CPUC authorizesdetermines the amount of revenue requirements that the Utility is authorized to collect from customers an amount known as base revenues to recover basethe Utility’s basic business and operational costs related to the Utility'sits electricity and natural gas distribution and electricity generation operations.  The CPUC generally conducts a GRC typicallyevery three years.  The CPUC sets annual revenue requirement levels for a three-year rate period. The CPUC authorizes these revenue requirements in GRC proceedingsperiod based on a forecast of costs for the first, or test, year.  After authorizing the revenue requirements, the CPUC allocates revenue requirements among customer classes (mainly residential, commercial, industrial and agricultural) and establishes specific rate levels. Typical interveners in the Utility's GRC include the OfficeCPUC’s Division of Ratepayer Advocate, or ORA,Advocates , and The Utility Reform Network or TURN.(“TURN”).  On December 2, 2005,March 15, 2007, the UtilityCPUC approved a multi-party settlement agreement to resolve the Utility’s 2007 GRC.  The decision sets the Utility’s electricity and natural gas distribution and electricity generation revenue requirements for a four-year period, from 2007 through 2010, rather than for a typical three-year period.  Under the decision, the Utility’s next GRC will be effective January 1, 2011.  On November 1, 2007, the CPUC denied an application for rehearing of the decision that had been filed its 2007 GRC application withby TURN and Aglet Consumer Alliance.  Neither TURN nor Aglet filed a petition for appellate review of the CPUC.denial.  For more information, see “Regulatory Matters—2007 General Rate Case”“Results of Operations – Electric Revenues” in the MD&A in the 20052007 Annual Report.


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Attrition Rate Adjustments

The CPUC may authorize the Utility to receive annual increases for the years between GRCs in the base revenues authorized for the test year of a GRC in order to avoid a reduction in earnings in those years due to, among other things, inflation and increases in invested capital. These adjustments are known as attrition rate adjustments. Attrition rate adjustments provide increases in the revenue requirements that the Utility is authorized to collect in rates for electricity and natural gas distribution and electricity generation operations.  The CPUC’s decision in the Utility’s 2007 GRC includes a provision for attrition adjustments to be made in 2008, 2009 and 2010.  For more information, see “Results of Operations – Electric Revenues” in the MD&A in the 2007 Annual Report.

Cost of Capital Proceedings

The CPUC generally conducts an annual cost of capital proceeding to determine the Utility's authorized capital structure and the authorized rate of return that the Utility may earn on its electricity and natural gas distribution and electricity generation assets. The cost of capital proceeding establishes the percentage components thatrelative weightings of common equity, preferred equity and debt will represent in the Utility's total authorized capital structure for a specific year. The CPUC then establishes the authorized return on common equity, preferred equity and debteach component that the Utility will have the opportunity to collect in its authorized rates.  On December 15, 2005, the CPUC issued a cost of capital decision approving aThe Utility’s CPUC-authorized capital structure for the Utility consisting2008 consists of 46% long-term debt, 2% preferred stock and 52% common equity. The CPUC set theUtility’s CPUC-authorized rate of return that the Utility may earn on its electricity and natural gas distribution and electricity generation rate base for 2006 at 6.02%2008 is 6.05% for long-term debt, 5.87%5.68% for preferred stock and 11.35% for common equity, resulting in an overall rate of return on rate base of 8.79%.  The CPUC is considering various mechanisms that could replace the annual cost of capital proceedings.  The CPUC is scheduled to issue a final decision on this issue by April 24, 2008.

Although the FERC has authority to set the Utility’s rate of return for its electricity transmission operations, the rate of return is often unspecified if the Utility's transmission rates are determined through a negotiated rate settlement. The Utility’s rates of return for its backbone and local gas transmission and storage operations through 2007 has been previously set in the Gas Accord at 11.22% for the return on equity and 8.77% for the overall rate of return.


Baseline Allowance

The CPUC sets and periodically revises a baseline allowance for the Utility's residential gas and electricity customers. A customer's baseline allowance is the amount of its monthly usage that is covered under the lowest possible natural gas or electric rate. Natural gas or electricity usage in excess of the baseline allowance is covered by higher rates that increase with usage.

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The Utility administers, and/or funds, several state-mandated public purpose programs. Public Purpose and Other Programs

California law requires the CPUC to authorize certain levels of funding for electric and gas public purpose programs related to energy efficiency, low-income energy efficiency, research and development, and renewable energy resources.  For 2005,In addition, California law requires the CPUC to authorize funding for the California Solar Initiative discussed below, and other self-generation programs. In addition to public purpose programs, the CPUC has authorized additional funding for demand response programs.  For 2007 expenditures, the CPUC authorized the Utility to collect revenue requirements of approximately $250$639 million from electricity customers to fund these electricity public purpose and other programs and to collect revenue requirements of approximately $40$82 million from gas customers to fund these natural gas public purpose programs.
In addition to the amounts required to be authorized by California law, the CPUC has authorized the Utility to collect approximately $50 million from retail electricity customers to recover the cost of additional energy efficiency programs put in place in accordance with the “loading order” stated in the CPUC’s Energy Action Plan for meeting the state’s energy resource needs. The “loading order” requires optimization of energy efficiency measures first, followed by demand response initiatives, and the use of renewable energy, before conventional generation is sought to be developed.

The Utility also provides a discount rate called the California Alternate Rates for Energy, or CARE, for low-income customers. This rate subsidy of approximately $220 million per year (including avoided surcharges) is paid for by the Utility's other customers.
The CPUC is responsible for authorizing the programs, funding levels and cost recovery mechanisms for the Utility's operation of both energy efficiency and low-income energy efficiency programs. The CEC administers both the electric and natural gas public interest research and development programprograms and the renewable energy program on a statewide basis. In 2005,2007, the Utility transferred $102$114 million to the CEC for these programs.  In 2007, surcharges collected from the Utility’s gas customers funded $7.7 million in gas public interest research and development programs administered by the CEC.

Public purpose programs include:
·  
Energy Efficiency Programs.  The CPUC has authorized the Utility’s 2006 through 2008 energy efficiency portfolio plans and program and authorized the Utility to recover approximately $867 million to fund these programs, including funding for evaluation, measurement and verification activities.  This increased energy efficiency funding level is part of a larger effort by the State of California to reduce consumption of fossil fuels. The increased funding level is designed to enable both residential and business customers to take more advantage of the diverse mix of energy efficiency programs.  In May 2008, the Utility expects to file a new Application with the CPUC seeking approval of energy efficiency programs and funding for the next cycle of energy efficiency, 2009-2011.

In September 2007, the CPUC adopted an incentive ratemaking mechanism applicable to the California investor-owned utilities’ implementation of their energy efficiency programs funded for the 2006-2008 and 2009-2011 program cycles.  To earn incentives, the utilities must (1) achieve at least 85% of the CPUC’s overall savings goal over the three-year program

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cycle and (2) achieve at least 80% of the individual kWh, kW, and therm savings metric goals over the three-year program cycle.  If the utilities achieve between 85% and 99% of the CPUC’s overall savings goal, 9% of the verified net benefits (i.e., energy resource savings minus total energy efficiency program costs) will accrue to shareholders and 91% of the verified net benefits will accrue to customers.  If the utilities achieve 100% or more of the CPUC’s savings goal, the shared rate increases so that 12% of the total verified net benefits will accrue to shareholders and 88% will accrue to customers up to a stated maximum.  If the utilities achieve less than 65% of any one of the individual savings metric goals, then the utilities must reimburse customers based on the greater of (1) 5 cents per kWh, 45 cents per therm, and $25 per kW for each kWh, therm, or kW unit below the 65% threshold or (2) a dollar-for-dollar payback of negative net benefits, also known as a cost-effectiveness guarantee.  The maximum amount that the Utility could earn, and the maximum amount that the Utility could be required to reimburse customers, over the 2006-2008 program cycle is $180 million.

The utilities must submit two programs.interim claims during the three-year program cycle, subject to verification of the actual amount of net benefits in a final true-up claim.  The CPUC will determine for each interim claim whether a utility is entitled to incentives or is required to reimburse customers based on the level of achievement of the CPUC’s savings goals on a cumulative-to-date basis.  The interim amounts will be calculated using updated estimates and assumptions about the energy savings per energy efficiency measure (“load impact”) over the three-year program period and will be reduced based on an assumption that certain customers would have undertaken the energy efficiency activity in the absence of the utilities’ energy efficiency program (the “net-to-gross” ratio”). The decision, as modified in January 2008, requires that 35% of the incentives or reimbursement obligations calculated for each interim claim be “held back” until completion of measurement studies verifying the actual energy savings for the entire three-year program cycle.  The final true-up may result in an adjustment to the prior year’s interim claims, but as long as the final measured energy savings are at least 65% of the CPUC savings goals, the utilities will not be required to pay back any incentives earned on an interim basis.
·  
Demand Response Programs. Demand response programs provide financial incentives and other benefits to participating customers to curtail on-peak energy use.  The CPUC has authorized approximately $109 million for 2006 through 2008 demand response programs for the Utility.  In addition, the CPUC approved several contracts with third-party demand response providers in 2007.  The payments made under the contracts are recovered through a balancing account.
In addition, on February 14, 2008, the CPUC approved the Utility’s multi-year air conditioning direct load control program and authorized funding of $179 million through June 1, 2011 to implement this program.  Customers who enroll in this program will allow the Utility to remotely control the temperature settings of their central air conditioners to temporarily decrease their energy usage during local or system emergencies.  The decision will allow the Utility to enroll approximately 397,000 air conditioning load control devices to achieve approximately 305 MW of load reduction capacity by June 2011.
·  
Self-Generation Incentive Program and California Solar Initiative.   The Utility administers the self-generation incentive program (“SGIP”) authorized by the CPUC to provide incentives to electricity customers who install certain types of clean or renewable distributed generation resources that meet all or a portion of their onsite energy usage.  The CPUC has approved a budget of $83 million for the SGIP program in 2008, of which $36 million has been allocated to the Utility.  The CPUC also established the California Solar Initiative (“CSI”) to bring 1,940 MW of solar power on-line by 2017 through the California investor-owned utilities, and authorized the utilities to collect an additional $2.2 billion over the 2007 through 2016 period from their customers to fund customer incentives for the installation of retail solar energy projects to serve onsite load to meet this goal.  Of the total amount authorized, the Utility has been allocated $946 million to fund customer incentives, research, development and demonstration activities (with an emphasis on the demonstration of solar and solar-related technologies), and administration expenses.  The California Legislature modified the CSI program to include participation of the California municipal utilities. The current overall goal of the CSI is to install 3,000 MW (through both investor-owned electric utilities and electric municipal utilities) through 2017.
·  
Low-Income Energy Efficiency Programs and California Alternate Rates for Energy.  The CPUC has approved funding of $78 million in each of 2007 and 2008 to support energy efficiency programs for low-income and fixed-income customers.  The Utility also provides a discount rate called the California Alternate Rates for Energy (“CARE”) for low-income customers. This rate subsidy is paid for by the Utility's other customers.  For 2007, the amount of this subsidy was approximately $468.6 million (including avoided customer surcharges).  In May 2008, the Utility expects to file an application with the CPUC seeking approval of low-income energy efficiency programs and funding for the next cycle of low-income energy efficiency, 2009-2011.


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  ·  
The ClimateSmart™ Program.In 2006, the CPUC approved the ClimateSmart™ program to allow customers to choose to neutralize greenhouse gas emissions associated with their energy use.  Customers who choose to enroll in the ClimateSmart™ program will pay a small premium on their monthly utility bill, based on their energy usage, to fund environmental projects aimed at removing carbon dioxide and other greenhouse gases from the air.  The Utility estimates that this program, which began at the end of June 2007, will generate approximately $15 million by December 31, 2009 to fund projects that are expected to reduce greenhouse gas emissions by at least 1.5 million tons.

On September 22, 2005,Overview

Each California investor-owned electric utility is responsible for procuring electricity to meet customer demand, plus applicable reserve margins, not satisfied from that utility's own generation facilities and existing electricity contracts (including DWR allocated contracts). Every other year, each utility must submit a long-term procurement plan covering a ten-year period to the CPUC for approval.  In December 2007, the CPUC approved the utilities’ long-term procurement plan, covering the 2007-2016 period, subject to certain required modifications.  California legislation, Assembly Bill 57, allows the utilities to recover the costs incurred in compliance with their CPUC-approved procurement plans without further reasonableness review.  Each utility may, if appropriate, conduct a competitive request for offers (“RFO”) within the parameters permitted in its approved plan to meet the utility’s projected need for electricity resources.  Contracts that are entered into after the competitive bidding process are submitted to the CPUC for approval, along with a request for the CPUC to authorize revenue requirements to recover the associated costs.  The utilities conduct separate competitive solicitations to meet their renewable energy resource requirements. The utilities submit the renewable energy contracts after the conclusion of these solicitations to the CPUC for approval and authorization of the associated revenue requirements.

The Utility recovers its electricity procurement costs and the fuel costs for the Utility’s own generation facilities (but excluding the costs of electricity allocated to the Utility under DWR contracts) through the Energy Resource Recovery Account (“ERRA”), a balancing account authorized 2006 through 2008 energy efficiency portfolioby the CPUC in accordance with Assembly Bill 57.  The ERRA tracks the difference between the authorized revenue requirement and actual costs incurred under the Utility's authorized procurement plans and program funding levels, notcontracts.  To determine the authorized revenue requirement recorded in the ERRA, each year the CPUC reviews the Utility’s forecasted costs under power purchase agreements and fuel costs.  Although California legislation requiring the CPUC to adjust a utility’s retail electricity rates when the forecast aggregate over-collections or under-collections in the ERRA exceed 5% of a utility's prior year electricity procurement revenues (excluding amounts collected for the DWR contracts) expired on January 1, 2006, the CPUC has extended this mandatory rate adjustment mechanism for the length of a utility’s resource commitment or 10 years, whichever is longer.  The CPUC also performs compliance reviews of the procurement activities recorded in the ERRA to ensure that the Utility’s procurement activities are in compliance with its approved procurement plans. The Chapter 11 Settlement Agreement also provides that the Utility will recover its reasonable costs of providing utility service, including fundingpower procurement costs.

The authorized revenue requirements for evaluation, measurementcapital costs and verification activities,non-fuel operating and maintenance costs for Utility-owned generation are addressed in the Utility’s GRC. The revenue requirement to recover the initial capital costs for CPUC-approved utility owned generation projects will be recovered through a balancing account, the Utility Generation Balancing Account (“UGBA”), which will track the difference between the CPUC-approved forecast of initial capital costs, adjusted from time to time as permitted by the CPUC, and actual costs. The initial revenue requirement for the Utility-owned projects generally would begin to accrue in the UGBA as of the new facility’s commercial operation date or EM&V, forthe date a completed facility is transferred to the Utility, and the other investor-owned California utilities. The CPUC approved funding of approximately $850 million for the Utility's energy efficiency programs over the 2006 through 2008 period, 20% of which is towould be awarded to third-parties through a competitive bid process. On November 18, 2005, the CPUC authorized funding for EM&V activities of approximately $75 million for the Utility over the 2006 through 2008 period. The increased energy efficiency funding level is part of a larger effort by the state of California to reduce consumption of fossil fuels. The increased funding level will enable both residential and business customers to take more advantageincluded in rates on January 1 of the diverse mix of energy efficiency programs.following year.


California Solar InitiativeDuring 2006-2007, the CPUC approved several power purchase agreements with third parties in accordance with the Utility’s CPUC-approved long-term procurement plan and to meet renewable energy and resource adequacy requirements.  The CPUC also authorized the Utility to recover fixed and variable costs associated with these contracts through the ERRA.

On January 12,For new non-renewable generation purchased from third parties under power purchase agreements, the Utility may elect to recover any above-market costs through either: (1) the imposition of a non-bypassable charge imposed on bundled and departing customers only or (2) the allocation of the “net capacity costs” (i.e., contract price less energy revenues) to all “benefiting customers” in the utilities’ service territory, including existing direct access customers and community choice aggregation customers.  (For information about the status of direct access and community choice aggregation, see the section above entitled “Competition Competition in the Electricity Industry.”)  The non-bypassable charge can be imposed from the date of signing a power purchase agreement and last for 10 years from the date the new generation unit comes on line or for the term of the contract, whichever is less.  Utilities are allowed to justify a cost recovery period longer than 10 years on a case-by-case basis.

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If a utility elects to use the net capacity cost allocation method, the net capacity costs would be allocated for the term of the contract or 10 years, whichever is less, starting on the date the new generation unit comes on line.  Under this allocation mechanism, the energy rights to the contract are auctioned off to maximize the energy revenues and minimize the net capacity costs that would be subject to allocation.  If no bids are accepted for the energy rights, the Utility would retain the rights to the energy and would value it at market prices for the purposes of determining the net capacity costs to be allocated until the next periodic auction.


During 2006, the CPUC authorized increased fundingapproved three agreements related to provide customer incentives and set additional policies to develop solar resourcesUtility-owned generation projects in California over the next 11 years, 2006 through 2017. This program, called the California Solar Initiative, or CSI, was designedaccordance with the objectiveUtility’s CPUC approved long-term procurement plan.  The CPUC also authorized the amount of bringing 3,000 MW of solar power on-line by 2017. The CPUC’srevenue requirements that the Utility is authorized to recover related to each project to recover capital costs and non-fuel operations and maintenance costs.  For more information, see “Capital Expenditures – New Generation Facilities” in the MD&A in the 2007 Annual Report

In its December 2007 decision consolidates existing and anticipated solar incentiveson the utilities’ long-term procurement plans, for the California investor-owned utilities, including a $300 million increase in 2006 funding for the Self Generation Incentive Program that was authorized in December 2005. In total,future utility-owned generation projects the CPUC authorizedeliminated the California investor-ownedlimitations it had adopted in 2004 that required the utilities to collect an additional $2.8 billion overshare half of any construction cost savings with ratepayers while absorbing any cost overruns.  Instead, the 2006 through 2017 period from their customersdecision allows the utilities to fund customer incentivesmake flexible proposals for utility-owned generation ratemaking on a case-by-case basis.  For more information about the installation of retail solar energy projects to serve onsite load. The intent of the CSIisto help California move toward a cleaner energy future and bring the costs of solar electricity down for California consumers so that solar products will be cost-effective without incentives. Of the total amount authorized, theUtility’s approved long-term procurement plan covering 2007-2016, see “Electric Utility has been allocated $1.2 billion to fund customer incentives. When combined with previously authorized funding, the total funds to be provided to achieve the CSI’s objectives are $3.25 billion, of which $1.4 billion is allocated to the Utility. The CSI also allocates up to 5% of the annual budget for research, development and demonstration activities, with emphasis on the demonstration of solar and solar-related technologies.Operations — Electricity Resources-Future Long-Term Generation Resources” below.


As a consequence ofDuring the California 2000-2001 energy crisis, and the resulting inability of the California investor-owned utilitiesDWR entered into long-term contracts to purchase electricity in the wholesale market, on January 17, 2001, the Governor of California signed an order declaring an emergency and authorizing the DWR to purchasefrom third parties.  The electricity to maintain the continuity of supply to retail customers. This was followed by AB 1X, which authorized the DWR to purchase electricity and sell that electricity directly to the California investor-owned utilities' retail end-user customers and to issue revenue bonds to finance electricity purchases. AB 1X also

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required the Utility to deliver the electricity purchased by the DWR over the Utility's distribution systems and to act as a billing and collection agent for the DWR, without taking title to DWR-purchased electricity or reselling it to the Utility's customers.

AB 1X allows the DWR to recover its costs of electricity and associated transmission and related services, principal and interest on bonds issued to finance the purchase of electricity, administrative costs and certain other amounts associated with purchasing electricity through a revenue requirement. AB 1X also authorizes the CPUC to set rates to cover the DWR's revenue requirements, but prohibits the CPUC from increasing electricity rates for residential customers who use less electricity than 130% of their existing baseline quantities.

Under AB 1X, the DWR was prohibited after December 31, 2002 from entering into new electricity purchaseprovided under these contracts and from purchasing electricity on the spot market. California Senate Bill, or SB,1976, which became law in September 2002, required the CPUC to allocate electricity from existing DWR contracts among the customers of the California investor-owned electric utilities, including the Utility's customers. The DWR continues to be legally and financially responsible for the contracts that havehas been allocated to the electric customers of the three California investor-owned electric utilities.

The DWR pays for its costs of purchasing electricity from a revenue requirement collected from electricitythese customers ofthrough a rate component called the three California investor-owned electric utilities through what is known asDWR "power charge."  The rates that these customers pay also include a power charge. The Utility's customers also must pay what is known as a bond charge"bond charge" to pay a share of the DWR's revenue requirements to recover costs associated with the DWR's $11.3 billion bond offering completed in November 2002.  The proceeds of this bond offering were used to repay the State of California and lenders to the DWR for electricity purchases made before the implementation of the DWR's revenue requirement and to provide the DWR with funds to make its electricity purchases.  Because theThe Utility acts as a billing and collection agent for the DWR for these amounts; however, amounts collected for the DWR and any adjustments are not included in the Utility's revenues.
Electricity Transmission 


On January 1, 2003, the California investor-owned electric utilities resumed responsibility for procuring electricity to meet their net open positions. They also became responsible for scheduling and dispatching the electricity subject to the DWR allocated contracts on a least-cost basis and for many administrative functions associated with those contracts. The utilities also were required by SB 1976 to submit short-term and long-term procurement plans to the CPUC for approval.

Effective January 1, 2003, under California law, the Utility established a balancing account, the Energy Resource Recovery Account, or ERRA, designed to track and allow recovery of the difference between the recorded electricity procurement revenues and actual costs incurred under the Utility's authorized procurement plans, excluding the costs associated with the DWR allocated contracts and certain other items.

On December 16, 2004, the CPUC issued a final decision which approved, with certain modifications, each California investor-owned electric utility's long-term electricity procurement plan, or LTPP, in order to authorize each utility to plan for and procure the resources necessary to provide reliable service to their customers for the 10-year period 2005 through 2014. The decision recognizes that each utility will have capacity needs over the 10-year period, especially in 2011 when most of the DWR contracts expire. The decision includes the following key points:

·The decision finds that the Utility's strategy of adding approximately 1,200 MW of capacity and new peaking generation in 2008 and approximately 1,000 MW of new peaking and dispatchable generation in 2010 through requests for offers, or RFOs, is reasonable and compatible with the Utility's resource needs under its medium load preferred case scenario, does not crowd out policy-preferred resources, and is a reasonable level of commitment given load uncertainty.
·To meet the utilities' resource requirements, the utilities are required to solicit bids from providers of all potential sources of new generation (e.g. conventional or renewable resources to be provided under turnkey developments, buyouts, or power purchase agreements, or PPAs) through a single, open, transparent and competitive RFO process, although an utility can tailor a RFO to meet specific resource needs. In particular, bids for long-term generation resources (whether PPAs or utility-owned) would be evaluated side-by-side. In evaluating bids, the IOUs are required to:

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·To meet the utilities' resource requirements, the utilities are required to solicit bids from providers of all potential sources of new generation (e.g. conventional or renewable resources to be provided under turnkey developments, buyouts, or power purchase agreements, or PPAs) through a single, open, transparent and competitive RFO process, although an utility can tailor a RFO to meet specific resource needs. In particular, bids for long-term generation resources (whether PPAs or utility-owned) would be evaluated side-by-side. In evaluating bids, the IOUs are required to:
Øprocure the maximum amount of renewable generation resources, and be prepared to defend any selection of fossil-fuel generation resources over renewable resources,
Øemploy the Least-Cost Best-Fit methodology when evaluating bids for PPAs and utility-owned generation resources, taking into account the qualitative and quantitative attributes (such as performance risk, credit risk, price diversity, term and operational flexibility) associated with each bid, and
Øemploy a "greenhouse gas adder" to evaluate fossil-fuel generation bids as a method to recognize the risk of future greenhouse gas emissions costs to develop a more accurate price comparison between fossil-fuel, renewable and demand-side bids (the greenhouse gas adder would be used for analytical purposes only and would not be paid to a generator).
·The CPUC has agreed that it will consider the debt equivalence impact of procurement contracts on credit ratings in future cost of capital proceedings. The Utility is required to employ S&P’s method for assessing the debt equivalence of power purchase agreements when evaluating bids in an all-source solicitation, except that the debt equivalence factor should be 20% instead of 30%.
·The utilities are prohibited from recovering initial capital costs in excess of their final bid price for utility-owned generation resources. If final project costs are less than the final bid price, the savings would be shared with customers and any cost overruns would be absorbed by the utilities. Costs of future plant additions and annual operating and maintenance costs and similar costs incurred by a utility would be eligible for cost-of service ratemaking treatment.
·Affiliates of the utilities are permitted to participate in the bidding process for long-term generation resources, subject to certain guidelines and safeguards, including a requirement that the utility use an independent third-party evaluator in resource solicitations where there are bids that involve affiliates or utility-built or utility-turnkey development projects. The independent evaluator will not be able to make binding decisions on behalf of the utility.
·The utilities are permitted to recover their net stranded costs of all new fossil-fuel generation resources from all customers, including departing customers, for a period of 10 years or the life of the PPA, whichever is less, provided that the CPUC will allow the utilities an opportunity to justify a longer recovery period on a case-by-case basis. Stranded costs arising from renewable generation procurement activities can be collected from all customers, including departing load, over the life of the contract. The utilities are required to take appropriate steps to minimize potential stranded costs by selling excess energy and capacity needs into the marketplace and crediting the revenues from these sales against the utilities' costs.
·The CPUC extended the mandatory rate adjustment mechanism provided under SB 1976 (which otherwise expired on January 1, 2006) to the length of a resource commitment or 10 years, whichever is longer. Under this rate adjustment mechanism, the CPUC has agreed to adjust retail electricity rates or order refunds, as appropriate, when the aggregate over-collections or under-collections exceed 5% of the utility's prior-year electricity procurement revenues, excluding amounts collected for the DWR allocated contracts.
·With respect to the utilities' contracting authority, the decision permits the utilities to enter into short-term, mid-term and long-term contracts with starting delivery dates through 2014, provided the utilities submit necessary compliance filings and provided that contracts with terms five years or longer are submitted to the CPUC for pre-approval. The decision adopts a rolling 10-year procurement period, noting that the LTPPs cover a 10-year period and will be updated and reviewed every 2 years.
For a discussion of the Utility’s request for offers to solicit bids to develop or acquire long-term generation resources in accordance with the Utility’s plan, see the section of MD&A entitled “Regulatory Matters—Electricity Generation Resources—Long-Term Generation Resource Commitments.”


The Utility's electricity transmission revenuesrevenue requirements and its wholesale and retail transmission rates are subject to authorization by the FERC. The Utility has two main sources of transmission revenues: charges under the Utility's transmission owner tariff and charges under specific contracts with wholesale transmission customers that the Utility entered into before 1998, when the ISO commenced operations.CAISO began its operations in March 1998. These wholesale customers are referred to as existing transmission contract customers and are charged individualized rates based on the terms of their contracts. Other customers pay transmission rates that are established by the

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FERC in the Utility's transmission owner tariff rate cases andcases. These FERC-approved rates are included by the CPUC in the Utility's retail electricityelectric rates, and collected from retail electricity customers receiving bundled service underconsistent with the federal filed rate doctrine.doctrine, and are collected from retail electric customers receiving bundled service.


UnderThe primary FERC rate-making proceeding to determine the FERC's regulatory regime,amount of revenue requirements the Utility is ableauthorized to file a new baserecover for its electric transmission costs and to earn its return on equity is the transmission owner rate case under the Utility's transmission owner tariff whenever the Utility deems it necessary to increase its(“TO rate case”). A TO rate case is generally held every year and sets rates within certain guidelines set forth by the FERC. for a one-year period.  The Utility is typically able to charge new rates, subject to refund, before the outcome of the FERC ratemaking review process.  For more information about the Utility’s TO rate cases, see “Results of Operations — Electric Operating Revenues” in the MD&A in the 2007 Annual Report.

The Utility's transmission owner tariff includes two rate components:

·  Base transmission rates, which are intended to recover the Utility's operating and maintenance expenses, depreciation and amortization expenses, interest expense, tax expense and return on equity; and

·  Rates to recover the pass-through of ISO charges for reliability service costs and an ISO charge associated with cost differences in utility-specific transmission charges and an ISO grid-wide charge, both of which are discussed below.

components.  The primary component consists of base transmission rates intended to recover the Utility's operating and maintenance expenses, depreciation and amortization expenses, interest expense, tax expense and return on equity.  The Utility derives the majority of the Utility's transmission revenue from base transmission rates.

Transmission Control AgreementThe other component consists of rates intended to reflect credits and charges from the CAISO.  The CAISO credits the Utility for transmission revenues received by the CAISO.  These revenues include:

The Utility has entered into a Transmission Control Agreement,
·  
the proceeds received from the CAISO for wholesale wheeling service (i.e., the transfer of electricity that is being sold in the

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·  
wholesale market) that the CAISO provides to third parties using the Utility’s transmission facilities, and
·  revenues that the CAISO collects from transmission users to relieve congestion on the Utility’s transmission line (either in the form of financial hedges, such as firm transmission rights relating to future deliveries of electricity, or in the form of a usage charge to manage congestion relating to real-time delivery of electricity).

These revenues are adjusted by the shortfall or TCA, withsurplus resulting from any cost differences between the ISO and other participating transmission owners (including Southern California Edison, or SCE, San Diego Gas & Electric Company, and several California municipal utilities) under whichamount the transmission owners have assigned operational control of their electricity transmission systems to the ISO. The Utility is requiredentitled to givereceive from certain wholesale customers under specific contracts and the ISO two years’ noticeamount the Utility is entitled to receive or be charged for scheduling services under the CAISO’s rules and receive approval from the FERC if it wishes to withdraw from the TCA.

Reliability Must Run Agreementsprotocols.

The ISOCAISO also has entered into reliability must run, or RMR, agreements with various power plant owners, includingcharges the Utility that require designated units in certain power plants, known as RMR units, to remain available to generate electricity upon the ISO's demand when needed for local transmission system reliability. As a participating transmission owner under the TCA, the Utility is responsible for the ISO's costs paid under RMR agreements to power plant owners within or adjacent to the Utility's service territory. The Utility’s share of the ISO’s reliability service costs in 2005 was approximately $217 million. Under the Utility’s transmission owner tariff, the Utility recovers these costs, without mark-up or service fees. The Utility also received approximately $59 million in 2005 under the RMR agreements that the Utility entered into with the ISO for the Utility’s units that have been designated as RMR units. The Utility tracks these costs and revenues in the reliability services balancing account. Periodically, the Utility’s electricity transmission rates are adjusted to refund over-collections to the Utility’s customers or to collect any under-collections from customers. For further discussion of other RMR-related issues, see the section of Note 17: Commitments and Contingencies— Reliability Must Run Agreements, of the Notes to the Consolidated Financial Statements in the 2005 Annual Report.

Transmission Access Charge

The ISO imposes a transmission access charge on usersfor the Utility’s use of the ISO-controlled electricityCAISO-controlled electric transmission grid.grid in serving its customers. The ISO'sCAISO's transmission access charge methodology, approved by the FERC in December 2004, provides for a transition over a 10-year period, from 2000-2009, to a uniform statewide high-voltage transmission rate.  This rate is based on the revenue requirements of all participating transmission owners associated with facilities operated at 200 kV and above.above of all transmission-owning entities that become participating transmission owners under the CAISO tariff. The transmission access charge methodology may result in a cost shift from transmission owners whose costs for existing transmission facilities at 200 kV and above are higher than that embedded in the uniform transmission access charge rate, to transmission owners with lower embedded costs for existing high voltage transmission, such as the Utility. The Utility's obligation for this cost differential has been capped at $32 million per year during the 10-year transition period.

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Natural GasIn December 2007, the FERC approved a settlement between the Utility and PacificCorp, both  owners of an electric transmission line which is part of  the California – Oregon Intertie, and other entities, relating to the termination of agreements that govern electric transmission service over the California – Oregon Intertie.  For more information, see “Electric Utility Operations – Electric Transmission” below.  As a condition of the settlement, the Utility will lease back a portion of the capacity allocated to PacifiCorp from 2008 through 2017 over the eastern 500 KV line between the substation in Malin, Oregon, and the Round Mountain substation located in California.  In addition, the Utility’s lease payments to PacifiCorp will be fully recovered through the Utility’s transmission owner rates.


Under a ratemaking pact called the Gas Accord, the Utility's natural gas transportation and storage services were separated for ratemaking purposes from its distribution services. The Gas Accord established natural gas transportation rates and natural gas storage rates.

On December 16, 2004,September 20, 2007, the CPUC approvedissued a final decision approving a multi-party settlement agreement, to retainknown as the Gas Accord market structure,IV, to establish the Utility’s natural gas transmission and resolve thestorage rates and terms and conditions of service for the Utility'sassociated revenue requirements from January 1, 2008 through December 31, 2010.  The Gas Accord IV establishes a 2008 natural gas transportationtransmission and storage systemrevenue requirement of $446 million (approximately 0.6% above the currently authorized revenue requirement for 2007), a 2009 revenue requirement of $459 million (approximately 2.8% above the three-year periodproposed 2008 revenue requirement), and a 2010 revenue requirement of 2005 through 2007. The Utility continues$471 million (approximately 2.7% above the proposed 2009 revenue requirement).  A substantial portion of the authorized revenue requirements, primarily those costs allocated to core customers, will continue to be atassured of recovery through balancing account mechanisms and/or fixed reservation charges.  The Utility’s ability to recover the remaining revenue requirements will continue to depend on throughput volumes, gas prices, and the extent to which non-core customers and other shippers contract for firm transmission services. This volumetric cost recovery risk associated with each function (backbone transmission, local transmission, and storage) is summarized below:

Backbone Transmission.  The backbone transmission revenue requirement is recovered through a combination of not recovering its natural gas transportationfirm, two-part rates (consisting of fixed monthly reservation charges and volumetric usage charges) and as-available, one-part rates (consisting only of volumetric usage charges).  The mix of firm and as-available backbone services provided by the Utility continually changes.  The Utility’s backbone transmission costs are partly assured of recovery to the extent backbone capacity is subscribed under long-term firm contracts, and to the extent the costs of that contracted capacity are recovered through fixed reservation charges.  Core procurement entities (including core customers served by the Utility) are the primary long-term subscribers to backbone capacity.  Core customers are allocated approximately 32% of the total backbone capacity on the Utility’s system. Core customers pay approximately 71% of the costs of the backbone capacity that is allocated to them through fixed reservation charges.

Local Transmission.  The local transmission revenue requirement is allocated approximately 70% to core customers and 30% to non-core customers.  The core portion is protected through a balancing account and therefore represents assured revenues.  The non-core portion is subject to volumetric cost recovery risk.

Storage.  The storage revenue requirement is allocated approximately 71% to core customers, 13% to non-core storage service, and 17% to pipeline load balancing service.  The core portion is protected through a balancing account and therefore represents assured revenues.  Recovery of the non-core portion is subject to volumetric and price risk.  The pipeline load balancing

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portion is recovered in backbone transmission rates and is subject to the same cost recovery risks described above for backbone transmission.

Taken together, the backbone transmission, local transmission, and storage costs that are either protected through balancing accounts or recovered through long-term firm contract reservation charges amount to approximately 47% of the Utility’s total revenue requirement for gas transmission and does not have regulatory balancing account protection for over-collections or under-collections of most of its natural gas transportation or storage revenues, except for core local transmission revenue and core storage costs.storage.


Certain of the Utility's natural gas distribution costs and balancing account balances are allocated to customers in the CPUC’s Biennial Cost Allocation Proceeding. This proceeding normally occurs every two years and is updated in the interim year for purposes of adjusting natural gas rates to recover from customers any under-collection, or refund to customers any over-collection, in the balancing accounts. Balancing accounts for gas distribution and other authorized expenses accumulate differences between authorized amounts and actual revenues.


Natural Gas Procurement

The Utility sets the natural gas procurement rate for core customers monthly, based on the forecasted costs of natural gas, core pipeline capacity and storage costs. The Utility reflects the difference between actual natural gas purchase costs and forecasted natural gas purchase costs in several natural gas balancing accounts, with under-collections and over-collections taken into account in subsequent monthly rates.

The CPIMUtility recovers the cost of gas (subject to the ratemaking mechanism discussed below), acquired on behalf of core  customers, through its retail gas rates.  The Utility is used to determineprotected against after-the-fact reasonableness reviews of these gas procurement costs under an incentive mechanism, the reasonableness of the Utility's costs of purchasing natural gas for its customers.CPIM.  Under the CPIM, the Utility's natural gas purchase costs (including Canadian and interstate capacity and volumetric transportation charges) for a fixed twelve-month period are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility typically purchases natural gas.  Costs that fall within a tolerance band, which is currently between 99% andto 102% of the benchmark, are considered reasonable and are fully recoverablerecovered in customers' rates. One-half of the costs above 102% of the benchmark are recoverable in customers' rates, and the Utility's customers receive three-fourthsin their rates 75% of any savings resulting from the savings when the costs are belowUtility's cost of natural gas that is less than 99% of the benchmark. The shareholder award is capped at the lower of 1.5% of total natural gas commodity costs or $25 million.  Any awards associatedWhile this incentive mechanism remains in place, changes in the price of natural gas, consistent with the CPIM are reflected annually in the purchased natural gas balancing account after the close of the annual period ending October 31 that is used to measure the CPIM. These awardsmarket-based benchmark, are not included in earnings until approved by the CPUC.
In responseexpected to rising naturalmaterially impact net income. The Utility also has received CPUC approval for a long-term gas prices, on October 6, 2005, the CPUC granted the Utility authority to purchase hedgeshedging program on behalf of the Utility's core gas customers for the winters of 2005-06, 2006-07, and 2007-08, and to book the costs of such hedges in a separate balancing account, outside of the CPIM. As a result, core customers, will pay the cost of these hedges and receive any payouts under these hedges. Since the hedging is outside of CPIM, the Utility is at risk to the extent that the CPUC may disallow portionsthrough 2011.  The costs of the hedging cost based on its subsequent review of the Utility’s performance under the filed hedging plan. As part of the hedging plan, the Utility also agreed to forgo a shareholder award underprogram are recovered directly from gas customers, outside the CPIM formechanism, and are subject only to a compliance review, not an after-the-fact reasonableness review. (For more information see the 2004-2005 CPIM year.“Risk Management Activities” section of MD&A in the 2007 Annual Report).

On September 2, 2004, the CPUC issued an order establishing a process whereby utilities receive CPUC pre-approval of contracts for interstate and Canadian pipeline capacity to support their natural gas procurement activities.


The Utility's interstate and Canadian natural gas transportation agreements with third partythird-party service providers are governed by tariffs that detail rates, rules and terms of service for the provision of natural gas transportation services to the Utility on interstate and Canadian pipelines. United States tariffs are approved for each pipeline for service to all of its shippers, including the Utility, by the FERC in a FERC ratemaking review process, and the applicable Canadian tariffs are approved by the Alberta Energy and Utilities Board and the National Energy Board. The Utility's agreements with interstate and Canadian natural

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gas transportation service providers are administered as part of the Utility's core natural gas procurement business. Their purpose is to transport natural gas from the points at which the Utility takes delivery of natural gas (typically in Canada and the southwestern United States) to the points at which the Utility's natural gas transportation system begins. In 2007, in conjunction with the settlement of a FERC rate case filed by TransCanada’s Gas Transmission Northwest Corporation, which transports Canadian natural gas to California, the Utility agreed to extend its existing contract commitment for a series of multiple-year terms. The FERC approved the settlement in January 2008. The settlement is further discussed below under “Natural Gas Utility Operations – Interstate and Canadian Natural Gas Transportation Services Agreements.”








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The following table shows the percentage of the Utility's total sources of electricity for 2007 represented by each major electricity resource:
Owned generation (nuclear, fossil fuel-fired and hydroelectric facilities)
32%
DWR
25%
Qualifying Facilities/Renewables
20%
Irrigation Districts
3%
Other Power Purchases
20%

The Utility is required to dispatch, or schedule, all of the electricity resources within its portfolio, including electricity provided under DWR contracts, in the most cost-effective way. Least-cost dispatch requires the Utility, in certain cases, to schedule more electricity than is necessary to meet its retail load and therefore to sell this electricity on the wholesale electricity market. The Utility typically schedules excess electricity when the expected sales proceeds exceed the variable costs to operate a generation facility or buy electricity under an optional contract.  Proceeds from the sale of surplus electricity are allocated between the Utility and the DWR, based on the percentage of volume supplied by each entity to the Utility's total load.  The Utility's net proceeds from the sale of surplus electricity after deducting the portion allocated to the DWR are recorded as a reduction to the cost of electricity.


At December 31, 2007, the Utility owned and operated the following generation facilities, all located in California, listed by energy source:

Generation Type  County Location 
Number of
Units
 
Net Operating
Capacity (MW)
Nuclear:      
Diablo Canyon
 
San Luis Obispo
 
2
 
2,240
Hydroelectric:
      
Conventional
 
16 counties in northern
and central California
 
107
 
2,684
Helms pumped storage
 
Fresno
 
3
 
1,212
Hydroelectric subtotal
   
110
 
3,896
Fossil fuel:
      
Humboldt Bay(1)
 
Humboldt
 
2
 
105
Mobile turbines
 
Humboldt
 
2
 
30
Fossil fuel subtotal
   
4
 
135
Total
   
116
 
6,271
(1)
The Humboldt Bay facilities consist of a retired nuclear generation unit, Humboldt Bay Unit 3, and two operating fossil fuel-fired plants.  As described below, the CPUC has approved the Utility’s application to re-power the two fossil fuel-fired plants.

Diablo Canyon Power Plant.  The Utility's Diablo Canyon power plant consists of two nuclear power reactor units, Units 1 and 2, with a total-plant net generation capacity of approximately 2,240 MW of electricity. Unit 1 began commercial operation in May 1985, and the operating license for this unit expires in November 2024. Unit 2 began commercial operation in March 1986, and the operating license for this unit expires in August 2025.  For the 10-year period ended December 31, 2007, the Utility's Diablo Canyon power plant achieved an average overall capacity factor of approximately 90.2%.

The Utility has entered into various purchase agreements for nuclear fuel that are intended to ensure long-term fuel supply.  For more information about these agreements, see Note 17: Commitments and Contingencies— Nuclear Fuel Agreements, of the Notes to the Consolidated Financial Statements in the 2007 Annual Report.

The following table outlines the Diablo Canyon power plant's refueling schedule for the next five years.  The Diablo Canyon power plant refueling outages are typically scheduled every 20 months.  The average length of a refueling outage over the last five years has been approximately 48 days.  The Utility will replace the steam generators in Unit 2 during the scheduled refueling outage which began on February 4, 2008 and will replace the steam generators in Unit 1 during the scheduled refueling outage to begin January 2009.  Due to this additional work, each of these refueling outages is expected to last approximately 76 days.  (The capital

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expenditures necessary to complete these projects are discussed further in the “Capital Expenditures” section of MD&A in the 2007 Annual Report.)  The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors.

  2008 2009 201020112012
Unit 1        
   Refueling
 
-
 
January
 
October
 
April
   Duration (days)
 
-
 
76
 
35
 
30
   Startup
 
-
 
April
 
November
 
May
Unit 2
        
   Refueling
 
February
 
October
 
-
May
 
   Duration (days)
 
76
 
35
 
-
30
 
   Startup
 
April
 
November
 
-
June
 

In addition, as discussed below under “Environmental Matters — Nuclear Fuel Disposal,” the Utility is constructing an on-site dry cask storage facility to store the spent nuclear fuel that is expected to be completed in 2008.  To provide another storage alternative in the event that construction of the dry cask storage facility is delayed, in December 2006, the Utility completed the installation of temporary storage racks in each unit's existing spent fuel storage pool that increase the on-site storage capability to permit the Utility to operate Unit 1 until 2010 and Unit 2 until 2011.  If the Utility is unable to complete the dry cask storage facility, or if construction is delayed beyond 2010, and if the Utility is otherwise unable to increase its on-site storage capacity, the operation of Unit 1 may have to be curtailed or halted as early as 2010 and the operation of Unit 2 may have to be curtailed or halted as early as 2011 until such time as additional spent fuel can be safely stored.

Hydroelectric Generation Facilities.  The Utility's hydroelectric system consists of 110 generating units at 68 powerhouses, including a pumped storage facility, with a total generating capacity of 3,896 MW. The system includes 99 reservoirs, 56 diversions, 170 dams, 184 miles of canals, 44 miles of flumes, 135 miles of tunnels, 19 miles of pipe and 5 miles of natural waterways. The system also includes water rights as specified in 90 permits or licenses and 160 statements of water diversion and use.  All but three of the Utility's powerhouses are licensed by the FERC, with license terms between 30 and 50 years. In the last five years, the FERC renewed six hydroelectric licenses with a total of 699 MW of hydroelectric power.  The Utility is in the process of renewing licenses for projects with approximately 1,314 MW of additional hydroelectric power.  Although the original licenses associated with 917 MW of the 1,314 MW have expired, the licenses are automatically renewed each year until completion of the relicensing process.  Licenses associated with approximately 2,569 MW of hydroelectric power will expire between 2013 and 2043.


During 2007, electricity from the DWR contracts allocated to the Utility provided approximately 25% of the electricity delivered to the Utility's customers.  The DWR purchased the electricity under contracts with various generators.  The Utility, as an agent, is responsible for administration and dispatch of these DWR contracts and acts as a billing and collection agent.  The DWR remains legally and financially responsible for its contracts.  During 2007, the DWR terminated a long-term power purchase agreement it had with Calpine Corporation over the objections of the Utility and other interested parties.  As a result, the Utility has  had to purchase replacement power on behalf of its customers at a significantly higher price.  The Utility expects that the amount of power supplied under the DWR’s contracts will diminish in the future as the contracts expire or are terminated.  For more information regarding the DWR contracts, see Note 17: Commitments and Contingencies – Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2007 Annual Report.


Qualifying Facility Power Purchase Agreements.  As of December 31, 2007, the Utility had agreements with 257 QFs for approximately 4,097 MW that are in operation.  Agreements for approximately 3,754 MW expire at various dates between 2008 and 2028.  QF power purchase agreements for approximately 343 MW have no specific expiration dates and will terminate only when the owner of the QF exercises its termination option.  The Utility also has power purchase agreements with approximately 74 inoperative QFs.  The total of approximately 4,097 MW consists of approximately 2,524 MW from cogeneration projects, 580 MW from wind projects and 994 MW from projects with other fuel sources, including biomass, waste-to-energy, geothermal, solar, and hydroelectric.  QF power purchase agreements accounted for approximately 20%, 20%, and 22% of the Utility’s 2007, 2006, and 2005 electricity sources, respectively.  No single QF accounted for more than 5% of the Utility's 2007, 2006, or 2005 electricity sources.

Irrigation Districts and Water Agencies.  The Utility has contracts with various irrigation districts and water agencies to purchase hydroelectric power.  Under these contracts, the Utility must make specified semi-annual minimum payments based on the irrigation districts' and water agencies' debt service requirements, whether or not any hydroelectric power is supplied, and variable

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payments for operation and maintenance costs incurred by the suppliers.  These contracts expire on various dates from 2008 to 2031.  The Utility's irrigation district and water agency contracts accounted for approximately 3% of the Utility’s 2007 electricity sources, approximately 6% of the Utility’s 2006 electricity sources and 5% of the Utility’s 2005 electricity sources.

Renewable Energy Contracts.  California law requires each California retail seller of electricity, except for municipal utilities, to increase its purchases of renewable energy (such as biomass, wind, solar, and geothermal energy) by at least 1% of its retail sales, so that the amount of electricity purchased from renewable resources equals at least 20% of its total retail sales by the end of 2010.  The CPUC has adopted "flexible compliance" rules, which allow deliveries above interim required levels to be carried forward, permit a retail seller to maintain a procurement deficit for up to three years following the year in which the deficit is incurred, and may, in certain cases, provide allowable reasons for noncompliance.  During 2007, the Utility entered into 9 new renewable power purchase agreements, representing approximately 3,000 GWh per year of renewable generation that will help the Utility to meet its goals. The Utility expects to use the flexible compliance Rules to meet the 2010 requirement.  Failure to satisfy the targets may result in a penalty of five cents per kWh, with an annual penalty cap of $25 million. The exact amount of any penalty and conditions under which it would be applied are subject to the CPUC’s review of whether supply-side factors or other circumstances caused the under-delivery.

Long Term Power Purchase Agreements.  In December 2007, the CPUC approved, with several modifications, the long-term electricity procurement plans (“LTPPs”) of the California investor-owned electric utilities covering the 10-year period from 2007 through 2016.  Each utility is required to submit an LTPP designed to reduce greenhouse gas emissions and uses the State of California’s preferred loading order to meet forecasted demand (i.e., increases in future demand will be offset through energy efficiency programs, demand response programs, renewable generation resources, distributed generation resources, and new conventional generation).  The decision notes that if a previously approved contract is terminated before the generation project is built, the utilities will retain the procurement authority for the MWs subject to the terminated contract.  At the end of the solicitation or request-for-offer (“RFO”) process, the utilities must justify why each bid was selected or rejected.  Utilities can acquire ownership of new conventional generation resources in the utilities’ competitive RFO process only through turnkey and engineering, procurement, and construction arrangements proposed by third parties.  The utilities are required to submit revised LTPPs reflecting the changes required by the CPUC within 90 days of the date the decision is mailed.

For more information regarding the Utility's power purchase contracts, see Note 17: Commitments and Contingencies— Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2007 Annual Report.
Future Long-Term Generation Resources

On December 20, 2007, the CPUC issued a decision that approves, with several modifications, the California investor-owned utilities’ long-term electricity procurement plan covering procurement during 2007-2016.  The CPUC forecasts that the Utility will need to obtain an additional 800 to 1,200 MW of new conventional generation by 2015 based on forecasts prepared by the CEC. The decision finds that in earlier years (i.e., 2007-2013), the Utility has a surplus of resources and in 2014 the forecast shows a small need for 66 MW.

The decision allows the utilities to acquire ownership of new conventional generation resources only through turnkey and engineering, construction, and procurement (“EPC”) arrangements proposed by third parties.  The decision prohibits the utilities from submitting bids for utility-build generation in their respective RFOs until questions can be resolved about how to compare utility-owned generation bids with bids from independent power producers.  The decision also permits utility-owned generation projects to be proposed through a separate application outside of the RFO process in the following circumstances: (1) to mitigate market power demonstrated by the utility to be held by others, (2) to support a use of preferred resources, such as renewable energy sources, (3) to expand existing facilities, (4) to take advantage of a unique and fleeting opportunity (such as a bankruptcy settlement) and (5) to meet unique reliability needs.  




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Gas & Electric Company, and several California municipal utilities) under which the transmission owners have assigned operational control of their electric transmission systems to the CAISO.The Utility is required to give the CAISO two years’ notice and receive approval from the FERC if it wishes to withdraw from the Transmission Control Agreement and take back operational control of its transmission facilities.

The CAISO, which is regulated by the FERC, controls the operation of the transmission system and provides open access transmission service on a nondiscriminatory basis. The CAISO also is responsible for ensuring that the reliability of the transmission system is maintained.  The Utility acts as a scheduling coordinator to schedule electricity deliveries to the transmission grid. The Utility also acts as a scheduling coordinator to deliver electricity produced by several governmental entities to the transmission grid under contracts the Utility entered into with these entities before the CAISO commenced operation in 1998.  In addition, under the mandatory reliability standards implemented following EPAct, all users, owners, and operators of the transmission system, including the Utility, are also responsible for maintaining reliability through compliance with the reliability standards.  See the discussion of reliability standards above under “The Utility’s Regulatory Environment- Federal Energy Regulation.”

In April 2006, the Utility completed a new 230-kV transmission line from Redwood City to Brisbane, known as the Jefferson-Martin 230-kV Line.  The completed transmission line provides additional transmission system reliability in San Francisco and northern San Mateo County.  As result of the completion of the transmission line, the Utility was able to retire the Hunters Point power plant in San Francisco.  The Utility expects to undertake various additional transmission projects over the next few years to upgrade and expand the Utility’s transmission system in order to accommodate system load growth, to secure access to renewable generation resources, to replace aging or obsolete equipment, to maintain system reliability, and to reduce reliance on generation provided under reliability must run (“RMR”) agreements with the CAISO.  (RMR agreements require various power plant owners, including the Utility, to keep designated units in certain power plants, known as RMR units, available to generate electricity upon the CAISO's demand when the generation from those RMR units is needed for local transmission system reliability.)  Potential transmission projects include a 500-kV transmission line to increase access to southern California and Southwest generation resources and to reduce RMR generation contracts in the Fresno, California area (referred to as the “Central California Clean Energy Transmission Project”) and a high voltage transmission line between Northern California and British Columbia, Canada to access renewable generation resources in British Columbia.  In addition, the Utility is currently working with several stakeholders in the western United States to assess the feasibility of new large-scale electric transmission expansion projects to address regional electricity needs over the long term.  

In December 2007, the FERC approved a settlement between the Utility and PacifiCorp, both owners of an electric transmission line which is part of the California – Oregon Intertie (“COI”), as well as other entities, relating to the termination of agreements that govern transmission service over the COI. The COI is a major electric transmission link connecting California with the Pacific Northwest and vital to electric grid reliability.  The settlement provides for the shared usage and coordinated planning, operation, and maintenance of the eastern 500 kV transmission line between the Malin substation in Oregon and the Round Mountain substation in California.  As a result of the settlement, the Utility and PacifiCorp will each have rights to half of the capacity on the eastern 500 kV transmission line between the Malin and Round Mountain substations for a twenty year period.  In addition, the Utility will lease back a portion of the capacity allocated to PacifiCorp for the first ten years.  The settlement allows the Utility to continue its rights to all existing available transmission service over the eastern 500 KV line between the Malin and Round Mountain substations through December 31, 2011; these rights decrease to half of the total capacity by 2018.  The settlement also provides that the Utility’s lease payments to PacifiCorp will be fully recovered through the Utility’s transmission owner rates.


The Utility's electricity distribution network extends through 47 of California's 58 counties, comprising most of northern and central California. The Utility's network consists of 140,684 circuit miles of distribution lines (of which approximately 19% are underground and approximately 81% are overhead). There are 93 transmission substations and 48 transmission-switching stations. A transmission substation is a fenced facility where voltage is transformed from one transmission voltage level to another. The Utility’s network includes 605 distribution substations and 110 low-voltage distribution substations. The 54 combined transmission and distribution substations have both transmission and distribution transformers.

The Utility's distribution network interconnects to the Utility's electricity transmission system at 1,106 points. This interconnection between the Utility's distribution network and the transmission system typically occurs at distribution substations where transformers and switching equipment reduce the high-voltage transmission levels at which the electricity transmission system transmits electricity, ranging from 500 kV to 60 kV, to lower voltages, ranging from 44 kV to 2.4 kV, suitable for distribution to the Utility's customers. The distribution substations serve as the central hubs of the Utility's electricity distribution network and consist of transformers, voltage regulation equipment, protective devices and structural equipment. Emanating from each substation are primary and secondary distribution lines connected to local transformers and switching equipment that link distribution lines and provide delivery to end-users. In some cases, the Utility sells electricity from its distribution lines or other facilities to entities, such as

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municipal and other utilities, that then resell the electricity.

During 2006, the Utility began the installation of an advanced metering infrastructure, known as the SmartMeter™ program, for virtually all of the Utility's electric and gas customers.  These meters will enable the Utility to measure usage on an hourly basis for electricity and on a daily basis for natural gas, which will allow for demand-response rates to encourage customers to reduce energy consumption during peak demand periods, thus reducing peak period procurement costs. Advanced meters can record usage in time intervals and be read remotely.  The Utility expects to complete the installation of the network infrastructure and advanced meters throughout its service territory by the end of 2011.  On December 12, 2007, the Utility filed an application with the CPUC requesting approval to upgrade elements of the Utility’s SmartMeter™ program.  The Utility seeks approval to install solid-state electric meters and associated devices that would offer an expanded range of service features for customers and increased operational efficiencies for the Utility.  These upgraded meters and associated devices would provide additional energy conservation and demand response options for electric customers.  In addition, the solid-state electric meters are designed to facilitate the Utility’s ability to incorporate future advanced metering technology innovations in a timely and cost-effective manner.  (For more information about the advanced metering infrastructure, see the section entitled “Capital Expenditures” in the MD&A portion of the 2007 Annual Report.)


The following table shows the percentage of the Utility's total 2007 electricity deliveries represented by each of its major customer classes:

Total 2007 Electricity Delivered: 86,179 GWh

Agricultural and Other Customers7%
Industrial Customers18%
Residential Customers36%
Commercial Customers39%


The following table shows certain of the Utility's operating statistics from 2003 to 2007 for electricity sold or delivered, including the classification of sales and revenues by type of service.
  2007  2006  2005  2004  2003 
Customers (average for the year):               
Residential
  4,464,483   4,417,638   4,353,458   4,366,897   4,286,085 
Commercial
  521,732   515,297   509,786   509,501   493,638 
Industrial
  1,261   1,212   1,271   1,339   1,372 
Agricultural
  80,366   79,006   78,876   80,276   81,378 
Public street and highway lighting
  29,643   28,799   28,021   27,176   26,650 
Other electric utilities
  2   4   4   3   4 
Total (1)
  5,097,487   5,041,956   4,971,416   4,985,192   4,889,127 
Deliveries (in GWh):(2)
                    
Residential
  30,796   31,014   29,752   29,453   29,024 
Commercial
  33,986   33,492   32,375   32,268   31,889 
Industrial
  15,159   15,166   14,932  ��14,796   14,653 
Agricultural
  5,402   3,839   3,742   4,300   3,909 
Public street and highway lighting
  833   785   792   2,091   605 
Other electric utilities
  3   14   33   28   76 
Subtotal
  86,176   84,310   81,626   82,936   80,156 
California Department of Water Resources (DWR)
  (21,193)  (19,585)  (20,476)  (19,938)  (23,554)
Total non-DWR electricity
  64,986   64,725   61,150   62,998   56,602 
Revenues (in millions):
                    
Residential
 $4,580  $4,491  $3,856  $3,718  $3,671 
Commercial
  4,484   4,414   4,114   4,179   4,440 
Industrial
  1,252   1,293   1,232   1,204   1,410 
Agricultural
  664   483   446   491   522 
Public street and highway lighting
  78   72   66   71   69 
Other electric utilities
  85   59   4   22   24 
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Subtotal
  11,143   10,812   9,718   9,685   10,136 
DWR
  (2,229)  (2,119)  (1,699)  (1,933)  (2,243)
Direct access credits
              (277)
Miscellaneous(3)
  215   261   235   (248)  (52)
Regulatory balancing accounts
  352   (202)  (327)  363   18 
Total electricity operating revenues
 $9,481  $8,752  $7,927  $7,867  $7,582 
Other Data:
                    
Average annual residential usage (kWh)
  6,898   7,020   6,834   6,744   6,772 
Average billed revenues (cents per kWh):
                    
Residential
  14.87   14.48   12.96   12.62   12.65 
Commercial
  13.19   13.18   12.71   12.95   13.92 
Industrial
  8.26   8.53   8.25   8.14   9.62 
Agricultural
  12.29   12.58   11.92   11.41   13.35 
Net plant investment per customer
 $3,418  $3,148  $2,966  $2,790  $2,689 

(1)Starting in 2005, the Utility’s methodology used to count customers changed from the number of billings to the number of active service agreements.
(2)These amounts include electricity provided to direct access customers who procure their own supplies of electricity.
(3)Miscellaneous revenues in 2003 include a $125 million reduction due to refunds to electricity customers from generation-related revenues in excess of generation-related costs.


The Utility owns and operates an integrated natural gas transportation, storage and distribution system in California that extends throughout all or a part of 39 of California's 58 counties and includes most of northern and central California.  In 2007, the Utility served approximately 4.3 million natural gas distribution customers. The total volume of natural gas throughput during 2007 was approximately 875 Bcf.

As of December 31, 2007, the Utility's natural gas system consisted of 41,805 miles of distribution pipelines, 6,393 miles of backbone and local transmission pipelines, and three storage facilities. The Utility's distribution network connects to the Utility's transmission and storage system at approximately 2,200 major interconnection points. The Utility’s backbone transmission system, composed primarily of Lines 300, 400 and 401, is used to transport gas from the Utility’s interconnection with interstate pipelines, other local distribution companies, and California gas fields to the Utility’s local transmission and distribution system. The Utility's Line 300, which interconnects with the U.S. Southwest and California-Oregon pipeline systems owned by third parties (Transwestern Pipeline Co., El Paso Natural Gas Company, Questar Southern Trails Pipeline Company and Kern River Pipeline Company), has a receipt capacity at the California-Arizona border of approximately 1.1 Bcf per day. The Utility's Line 400/401 interconnects with the natural gas transportation pipeline of Gas Transmission Northwest Corporation at the California-Oregon border. This line has a receipt capacity at the border of approximately 2.0 Bcf per day. Through interconnections with other interstate pipelines, the Utility can receive natural gas from all the major natural gas basins in western North America, including basins in western Canada, the Rocky Mountains and the southwestern United States. The Utility also is supplied by natural gas fields in California.

The Utility also owns and operates three underground natural gas storage fields connected to the Utility's transmission and storage system. These storage fields have a combined firm capacity of approximately 47 Bcf. In addition, two independent storage operators are interconnected to the Utility's northern California transportation system.
In September 2007, the Utility announced that it had entered into an agreement with Gill Ranch Storage, LLC, a subsidiary of Northwest Natural Gas Company, to develop an underground natural gas storage facility near Fresno, California.  The new storage facility would provide approximately 20 Bcf of total capacity once the initial phase is completed, expected in 2010.  On February 4, 2008, the parties executed a Joint Project Agreement which provides the Utility a 25% interest in the initial project phase.  Development of the project is subject to CPUC issuance of a Certificate of Public Convenience and Necessity and an environmental review to be conducted by the CPUC under the California Environmental Quality Act. The parties plan to file an application with the CPUC in May 2008.
The CPUC divides the Utility's natural gas customers into two categories: core and non-core customers. This classification is based largely on a customer's annual natural gas usage. The core customer class is comprised mainly of residential and smaller commercial natural gas customers. The non-core customer class is comprised of industrial, larger commercial and electric generation natural gas customers. In 2007, core customers represented more than 99% of the Utility's total customers and 38% of its total natural

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gas deliveries, while non-core customers comprised less than 1% of the Utility's total customers and 62% of its total natural gas deliveries.
The Utility provides natural gas transportation services to all core and non-core customers connected to the Utility's system in its service territory. Core customers can purchase natural gas procurement service (i.e., natural gas supply) from either the Utility or alternate energy service providers. When the Utility provides both transportation and procurement services, the Utility refers to the combined service as bundled natural gas service. Currently, over 99% of core customers, representing over 96% of core market demand, receive bundled natural gas service from the Utility.

The Utility does not provide procurement service to non-core customers. However, some non-core customers are permitted to elect core service and receive Utility procurement service through that avenue.  Electricity generators, QF cogenerators, enhanced oil recovery customers, refiners, and other large non-core customers may not elect core service, and smaller non-core customers must contract for a minimum five-year term if they elect core service. These restrictions were put in place because large increases in demand for the Utility's procurement service caused by significant transfers of non-core customers to core service would raise prices for all other core procurement customers and obligate the Utility to reinforce its pipeline system to provide core service reliability on a short-term basis to serve this new load.

The Utility offers backbone gas transmission, gas delivery (local transmission and distribution), and gas storage services as separate and distinct services to its non-core customers. Access to the Utility's backbone gas transmission system is available for all natural gas marketers and shippers, as well as non-core customers.

The Utility has regulatory balancing accounts for core customers designed to ensure that the Utility's results of operations over the long term are not affected by weather variations, conservation or changes in their consumption levels. The Utility's results of operations can, however, be affected by non-core consumption levels because there are fewer regulatory balancing accounts related to non-core customers.  Approximately 97% of the Utility's natural gas distribution base revenues are recovered from core customers and 3% are recovered from non-core customers.

The California Gas Report is prepared by the California electric and natural gas utilities to present an outlook for natural gas requirements and supplies for California over a long-term planning horizon. It is prepared in even-numbered years followed by a supplemental report in odd-numbered years. The 2006 California Gas Report forecasts average annual growth in the Utility's natural gas deliveries (for core customers and non-core transportation) of approximately 1.3% for the years 2006 through 2025. The natural gas requirements forecast is subject to many uncertainties, and there are many factors that can influence the demand for natural gas, including weather conditions, level of economic activity, conservation, price, and the number and location of electricity generation facilities.


The following table shows the percentage of the Utility's total 2007 natural gas deliveries represented by each of the Utility's major customer classes:

Total 2007 Natural Gas Deliveries: 875 Bcf

Residential Customers26%
Transport-only Customers (non-core)62%
Commercial Customers12%


The following table shows the Utility's operating statistics from 2003 through 2007 (excluding subsidiaries) for natural gas, including the classification of sales and revenues by type of service:

  2007  2006  2005  2004  2003 
Customers (average for the year):               
Residential
  4,030,499   3,989,331   3,929,117   3,812,914   3,744,011 
Commercial
  223,330   220,024   216,749   215,547   208,857 
Industrial
  958   988   962   2,178   1,988 
Other gas utilities
  6   6   6   6   6 
Total
  4,254,793   4,210,349   4,146,834   4,030,645   3,954,862 
Gas supply (MMcf):
                    
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Purchased from suppliers in:
                    
Canada
  199,870   202,274   204,884   205,180   196,278 
California
  (23,065)  (13,401)  (18,951)  (9,108)  (7,421)
Other states
  101,271   103,658   103,237   103,801   102,941 
Total purchased
  278,076   292,531   289,170   299,873   291,798 
Net (to storage) from storage
  (1,120)  4,359   (3,659)  (532)  1,359 
Total
  276,955   296,890   285,511   299,341   293,157 
Utility use, losses, etc. (1)
  (12,760)  (27,610)  (14,312)  (19,287)  (14,307)
Net gas for sales
  264,196   269,280   271,199   280,054   278,850 
Bundled gas sales (MMcf):
                    
Residential
  196,092   196,092   194,108   201,601   198,580 
Commercial
  67,293   73,178   77,056   78,080   79,891 
Industrial
      10   35   373   379 
Other gas utilities
 
___
  
___
          
Total
  264,196   269,280   271,199   280,054   278,850 
Transportation only (MMcf):
  605,259   559,270   572,869   597,706   525,353 
Revenues (in millions):
                    
Bundled gas sales:
                    
Residential
 $2,378  $2,452  $2,336  $1,944  $1,836 
Commercial
  766   859   885   712   697 
Industrial
                  1 
Other gas utilities
                  1 
Miscellaneous
  88   121   (22)  (29)  (31)
Regulatory balancing accounts
  186   40   340   316   68 
Bundled gas revenues
  3,417   3,472   3,539   2,943   2,572 
Transportation service only revenue
  340   315   237   270   284 
Operating revenues
 $3,757  $3,787  $3,776  $3,213  $2,856 
Selected Statistics:
                    
Average annual residential usage (Mcf)
  49   49   49   53   53 
Average billed bundled gas sales revenues per Mcf:
                    
Residential
 $12.07  $12.50  $12.04  $9.64  $9.25 
Commercial
  11.38   11.73   11.48   9.12   8.73 
Industrial
      1.03   0.61   (0.56)  2.48 
Average billed transportation only revenue per Mcf
  0.56   0.56   0.42   0.45   0.54 
Net plant investment per customer
 $1,375  $1,304  $1,262  $1,266  $1,261 
                     
(1)Includes fuel for the Utility's fossil fuel-fired generation plants.


The Utility purchases natural gas to serve the Utility's core customers directly from producers and marketers in both Canada and the United States. The contract lengths and natural gas sources of the Utility's portfolio of natural gas purchase contracts have fluctuated, generally based on market conditions.  During 2007, the Utility purchased approximately 278,076 Mcf of natural gas (net of the sale of excess supply) from 67 suppliers. Consistent with existing CPUC policy directives, substantially all this natural gas was purchased under contracts with a term of one year or less. The Utility's largest individual supplier represented approximately 11% of the total natural gas volume the Utility purchased during 2007.

The following table shows the total volume and the average price of natural gas in dollars per Mcf of the Utility's natural gas purchases by region during each of the last five years. The average prices for Canadian and U.S. Southwest gas shown below include the commodity natural gas prices, pipeline demand or reservation charges, transportation charges and other pipeline assessments. The volumes purchased are shown net of sales of excess supplies of gas. In 2007, the sale of excess supplies to parties located in California exceeded purchases from parties located in California.
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  2007  2006  2005  2004  2003 
  MMcf  Avg. Price  MMcf  Avg. Price  MMcf  Avg. Price  MMcf  Avg. Price  MMcf  Avg. Price 
Canada  199,870  $6.63   202,274  $6.27   204,884  $7.12   205,180  $5.37   196,278  $4.73 
California (1)  (23,065) $6.77   (13,401) $7.04   (18,951) $7.70   (9,108) $4.89   (7,421) $3.39 
Other states (substantially all  U.S.    southwest)  101,271  $6.30   103,658  $6.51   103,237  $7.10   103,801  $5.44   102,941  $4.63 
Total/weighted average  278,076  $6.50   292,531  $6.32   289,170  $7.07   299,873  $5.41   291,798  $4.73 
(1)California purchases include supplies from various California producers and supplies transported into California by others.


The Utility's gas gathering system collects natural gas from third-party wells in California. During 2007, approximately 6% of the gas transported on the Utility's system came from various California producers, with the balance coming from supplies transported into California by others. The natural gas well production is processed by producers to remove various impurities from the natural gas stream and the Utility then odorizes the natural gas so that it may be detected in the event of a leak. The facilities include approximately 117.26 miles of gas gathering pipelines. The Utility receives gas well production at approximately 230 metering facilities. The Utility’s gas gathering system is geographically dispersed and is located in 8 California counties. Approximately 132 MMcf per day of natural gas produced in northern California was delivered into the Utility's gas gathering system during 2007.


In 2007, approximately 60% of the gas transported on the Utility's system came from western Canada. The Utility has a number of arrangements with interstate and Canadian third-party transportation service providers to serve core customers' service demands. The Utility has firm transportation agreements for delivery of natural gas from western Canada to the United States- Canadian border with TransCanada NOVA Gas Transmission, Ltd. and TransCanada Foothills Pipe Lines Ltd., B.C. System.  hese companies' pipeline systems connect at the border to the pipeline system owned by TransCanada’s Gas Transmission Northwest Corporation (“GTN”) which provides natural gas transportation services to a point of interconnection with the Utility's natural gas transportation system on the Oregon-California border near Malin, Oregon. The Utility, the largest firm shipper on GTN’s pipeline, has a firm transportation agreement with GTN for these services.  As described below, as part of the FERC-approved all-party settlement of GTN’s most recent general rate case, the Utility’s contract with GTN will be replaced beginning November 1, 2009 by three smaller contracts totaling the same amount with staggered terms.

During 2007, approximately 34% of the gas transported on the Utility's system came from the western United States, excluding California. The Utility has firm transportation agreements with Transwestern Pipeline Company and El Paso Natural Gas Company to transport this natural gas from supply points in this region to interconnection points with the Utility's natural gas transportation system in the area of California near Topock, Arizona.

The following table shows certain information about the Utility's firm natural gas transportation agreements in effect during 2007, including the contract quantities, contract durations and associated demand charges, net of sales of excess supplies, for capacity reservations. These agreements require the Utility to pay fixed demand charges for reserving firm capacity on the pipelines. The total demand charges may change periodically as a result of changes in regulated tariff rates approved by Canadian regulators in the case of TransCanada NOVA Gas Transmission, Ltd. and TransCanada Foothills Pipe Lines Ltd., B.C. System, and by the FERC in all other cases.  The Utility may, upon prior notice and with the CPUC’s approval, extend each of these natural gas transportation agreements. On the FERC-regulated pipelines, the Utility has either a right of first refusal or evergreen rights allowing it to renew natural gas transportation agreements at the end of their terms. If another prospective shipper also wants the capacity, the Utility would be required to match the competing bid with respect to both price and term.
Pipeline 
Expiration
Date
  
Quantity
MDth per day
 
Demand Charges
for the Year Ended
December 31, 2007
(In millions)
        
TransCanada NOVA Gas Transmission, Ltd. 12/31/2009(1) 619 $29.5
TransCanada PipeLines Ltd., B.C. System 10/31/2009  611 15.7
Gas Transmission Northwest Corporation 10/31/2009  610 89.6
Transwestern Pipeline Company 03/31/2010  150 15.9
El Paso Natural Gas Company (2) Various  252 17.2
Kern River Gas Transmission Company(3) 2/28/2007  29 0.4


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(1)A small portion (23 MDth/d) of the Utility’s capacity is due to expire on October 31, 2009.
(2)As of December 31, 2007, the Utility had four active contracts with El Paso with expiration dates ranging from February 29, 2008 to June 30, 2012.
(3)This contract was not renewed.

As required by the all-party settlement of GTN’s most recent general rate case approved by the FERC on January 7, 2008, the Utility has entered into three smaller contracts with GTN with terms that begin on November 1, 2009 and terminate on various dates unless renewed, as follows:

 
Expiration
Date
  
Quantity
MDth per day
 
Estimated Annual Charges
2009-2011 (In millions)
       
 10/31/2011  250 $58
 10/31/2016  280 71
 10/31/2020  80 20

Also, as part of the same settlement, the Utility has entered into a separate contract with GTN for firm transportation service to support the Utility’s need for natural gas for electric power plant fuel. This new contract is for a quantity of 50 MDth/d for a 59-month term, July 1, 2009, through May 31, 2014.

The settlement sets rates on the GTN pipeline for a minimum term of five years commencing January 1, 2007, and provides for substantial refunds to the Utility and other shippers for the higher rates paid since that time.  The Utility estimates it will receive refunds on behalf of customers of approximately $24 million by early April 2008.  For contract commitments extending beyond December 31, 2011, the Utility will be obligated to pay the then-effective GTN rate as set by the FERC.

In addition, in December 2007, the Utility entered into an agreement to subscribe for 375 MDth per day of firm service rights on the proposed Ruby Pipeline for a 15-year term commencing in 2011, when the pipeline is proposed to be placed into service.  The Utility’s commitment is contingent upon the satisfaction of certain conditions precedent, including CPUC approval.  (For more information, see “Competition” above.)  The Utility expects the CPUC will issue a decision by the end of 2008.


The following discussion includes certain forward-looking information relating to estimated expenditures for environmental protection measures and the possible future impact of environmental compliance.compliance measures. The information below reflects current estimates, thatwhich are periodically evaluated and revised. Future estimates and actual results may differ materially from those indicated below. These estimates are subject to a number of assumptions and uncertainties, including changing laws and regulations, the ultimate outcome of complex factual investigations, evolving technologies, selection of compliance alternatives, the nature and extent of required remediation, the extent of the facility owner's responsibility, and the availability of recoveries or contributions from third parties.



The Utility is subject to a number of federal, state and local laws and requirements relating to the protection of the environment and the safety and health of the Utility's personnel and the public. These laws and requirements relate to a broad range of activities, including:

·  The
the discharge of pollutants into air, water and soil;

·  The
the identification, generation, storage, handling, transportation, treatment, disposal, record keeping, labeling, reporting, of, remediation of and emergency response in connection with hazardous and radioactive substances; and

·  Landenvironmental impacts of land use, including endangered species and habitat protection.

The penalties for violation of these laws and requirements can be severe, and may include significant fines, damages and criminal or civil sanctions. These laws and requirements also may require the Utility, under certain circumstances, to interrupt or curtail operations. To comply with these laws and requirements, the Utility may need to spend substantial amounts from time to time to construct, acquire, modify or replace equipment, acquire permits and/or marketable allowances or other emission credits for facility operations and clean upclean-up or decommission waste disposal areas at the Utility's current or former facilities and at third-party sites where

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the UtilityUtility’s wastes may have disposed of wastes.
been disposed.

Generally, the Utility has recovered the costs of complying with environmental laws and regulations in the Utility's rates, subject to reasonableness review. Environmental costs associated with the clean-up of sites that contain hazardous substances are subject to a special ratemaking mechanism under which the Utility is authorized to recover hazardous waste remediation costs for environmental claims (from customers (e.g.e.g., for costs of cleaning up the Utility's facilities and sites where the Utility has sentUtility’s hazardous substances) from customers.substances have been sent). This mechanism allows the Utility to include 90% of theeligible hazardous waste remediation costs in the Utility's rates without a reasonableness review. Ten percent of any net insurance recoveries associated with hazardous waste remediation sites areis assigned to the Utility's customers.  The balance of any insurance recoveries (90%) areis retained by the Utility until it has been reimbursed for the 10% share of clean-up costs not included in rates. Any insurance recoveries above full cost reimbursement levels would then beare allocated 60% to customers and 40% to the Utility. Finally, 10% of any recoveries from the Utility's claims against third parties associated with hazardous waste remediation sites areis retained by the Utility;Utility, with the remainder, 90% of any such recoveries, are assigned to the Utility's customers.

Hazardous waste remediation costs are rising and are likely to be significant into the foreseeable future. Based on the Utility's past experience, it believes that it can recover most of the future costs that it may incur to remediate hazardous waste through rates and insurance recoveries. The Utility cannot provide assurance, however, that these costs will not be material, or that the Utility will be able to recover its costs in the future.



The Utility's electricity generation plants, and natural gas pipeline operations, fleet and fuel storage tanks are subject to numerous air pollution control laws, including the federal Clean Air Act and similaras well as state and local statutes. These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon monoxide, sulfur dioxide, nitrogen oxide and particulate matter.

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  In addition, various laws and regulations addressing climate change are being considered or implemented at the federal and state levels, as discussed below. Fossil fuel-fired electric utility plants and gas compressor stations used in the Utility's pipeline operations are sources of air pollutants and, therefore, are subject to substantial regulation and enforcement oversight by the applicable governmental agencies.

During 2003, 2004The Utility’s existing and 2005, various multi-pollutant initiatives were introducedforecast emissions of climate-changing “greenhouse gases,” or GHGs, are relatively low compared to average emissions by other electric utilities and generators in the U.S. Senatecountry, but the Utility anticipates that it will be affected by the increasing attention of the federal and Housestate government to the control of Representatives. TheseGHGs is gaining increasing attention. At the federal level, several legislative initiatives proposedhave been introduced recently in Congress aimed at addressing climate change through imposition of nation-wide regulatory limits on the emissions of nitrogen oxide, sulfur dioxide, mercuryGHGs.  No such legislation has yet been enacted by Congress, but extensive hearings and carbon dioxide,discussion are expected in the coming year. At the state level, in 2006 California enacted Assembly Bill 32 (“AB 32”), the California Global Warming Solutions Act of 2006, to address climate change.  AB 32 establishes a regulatory program and some would allowschedule to gradually reduce GHG emissions in California to 1990 levels by 2020 on a schedule beginning in 2012.  AB 32 also authorizes the use of trading mechanismsCalifornia Air Resources Board (“CARB”) to achieve or maintainmonitor and enforce compliance with the proposed rules. Although these initiatives wereGHG reduction program and to consider implementing market-based mechanisms, including trading of GHG emissions allowances. Pursuant to AB 32, on December 6, 2007, the CARB adopted a state-wide GHG 1990 emissions baseline of 427 million metric tons of carbon dioxide (or its equivalent).  This 1990 baseline serves as the 2020 emissions reduction target for the state of California.  The CARB has not enacted into law, similar legislation is expectedyet determined reduction goals applicable to be introducedthe utility sector or individual utilities within the utility sector. The CARB also adopted a GHG reporting regulation that will require reporting of 2008 GHG emissions in 2006. Two of the local air districts in which the Utility owns and operates fossil fuel-fired generation facilities adopted final rules under the California Clean Air Act and the federal Clean Air Act that required reductions in nitrogen oxide emissions from the facilities of approximately 90% by 2004.2009. The Utility is in compliance with these rules. The Utility is permitted to recover in customer rates the Utility's costs for its nitrogen oxide retrofit projects related to natural gas compressor stations on the Utility's Line 300, which delivers gas from the southwest. Several other air districts are considering nitrogen oxide rules that would apply to the Utility's other natural gas compressor stations in California. Eventually, the rules are likely to require nitrogen oxide reductions of up to 80% at many of these natural gas compressor stations. Substantially all these costs will be capital costs whichrequired to submit verified GHG emissions reports under CARB’s reporting regulation.  AB 32 requires CARB to adopt a Scoping Plan by January 2, 2009 for achieving the Utility expectsmaximum technologically feasible and cost-effective GHG reductions to recover through rates.meet the 2020 reduction target.

In addition,California Senate Bill 1368, also enacted in 2006, prohibits any load-serving entity in California, including investor-owned electric utilities, from entering into a long-term financial commitment for baseload electricity generation unless the generation complies with a GHG emission performance standard. As required by Senate Bill 1368, on January 25, 2007, the CPUC adopted an interim GHG emissions performance standard of 1,100 pounds of carbon dioxide per MWh that applies to new commitments for baseload electricity procured under contracts with a term of five years or longer or generated by the Utility.  After a state-wide GHG emissions limit is established and is in operation, in accordance with AB 32, the CPUC will re-evaluate its interim GHG emissions performance standard and determine whether to continue, modify or rescind it.

The new California legislation, as well as current federal and other state regulatory initiatives relating to emissions of carbon dioxide and other greenhouse gases,GHGs, particulates and other toxic pollutants, could increasecause the Utility's compliance costs and capital expenditures primarily with respect to the Utility's gas transportation facilities, fleet and fuel storage tanks. If enacted, theseincrease. These laws could require the Utility to replace equipment, install additional pollution controls, purchase various emission allowances or curtail operations. Although associated costs and capital expenditures could be material, the Utility expects that it would be able towill recover these costs and capital expenditures in rates.rates consistent with the recovery of other reasonable costs of complying with

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environmental laws and regulations.



The federal Clean Water Act generally prohibits the discharge of any pollutants, including heat, into any body of surface water, except in compliance with a discharge permit issued by a state environmental regulatory agency and/or the U.S. Environmental Protection Agency, or the EPA. The Utility's generation facilities are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. The Utility's steam-electric generation facilities comply in all material respects with the discharge constituents standards and the thermal standards. In addition, under the federal Clean Water Act, the Utility is required to demonstrate that the location, design, construction and capacity of generation facility cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts at its existing water-cooled thermal plants. The Utility has submitted detailed studies of each steam-electric generation facility's intake structure to various governmental agencies and each power plant's existing intake structure was found to meet the best technology available requirements.

The Utility's Diablo Canyon power plant employs a "once-through"“once-through” cooling water system that is regulated under a Clean Water Act National Pollutant Discharge Elimination System or NPDES,(“NPDES”) permit issued by the Central Coast Regional Water Quality Control Board or (“Central Coast Board.Board”). This permit allows the Diablo Canyon power plant to discharge the cooling water at an averagea temperature of no more than 22 degrees above the temperature of the ambient receiving water, and requires that the beneficial uses of the water be protected. The beneficial uses of water in this region include industrial water supply, recreation, commercial/sport fishing, marine and wildlife habitat, shellfish harvesting, and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft cease and desist order alleging that, although the temperature limit has never been exceeded, the Diablo Canyon power plant's discharge was not protective of beneficial uses.

In October 2000, the Utility and the Central Coast Board reached a tentative settlement under which the Central Coast Board agreed to find that the Utility's discharge of cooling water from the Diablo Canyon power plant protects beneficial uses and that the intake technology reflects the best technology available, as defined in the federal Clean Water Act.  As part of the tentative settlement, the Utility agreed to take measures to preserve certain acreage north of the plant and to fund approximately $6 million in environmental projects and future environmental monitoring related to coastal resources. On March 21, 2003, the Central Coast Board voted to accept the settlement agreement. On June 17, 2003, the settlement agreement was executed by the Utility, the Central Coast Board and the California Attorney General's Office. A condition to the effectiveness of the settlement agreement is that the Central Coast Board renew Diablo Canyon's NPDES permit.

At its meeting on July 10, 2003, the Central Coast Board did not renew the NPDES permit and continued the permit renewal hearing indefinitely. Several Central Coast Board members indicated that they no longer supported the settlement agreement, and the Central Coast Board requested a team of independent scientists, as part of a technical working group, to develop additional information on possible mitigation measures for Central Coast Board staff. In January 2005, the Central Coast Board published athe scientists' draft report prepared by a team of scientists recommending several measures to mitigate the effect of the cooling water system.such mitigation measures. If the Central Coast Board adopts the scientists' recommendations, and if the Utility ultimately is required to implement the projects proposed in the draft report, it could incur costs of up to approximately $30 million. The Utility would seek to recover these costs through rates charged to customers. For a further discussion of this matter, see “Item 3. Legal Proceedings,” below.

In addition, on July 9, 2004, the EPAU.S. Environmental Protection Agency (“EPA”) published regulations under Section 316(b) of the Clean Water Act for cooling water intake structures. The regulations affectthat apply to existing electricity generation facilities usingthat use over 50 million gallons of water per day, which typically includinginclude some form of "once-through" cooling.cooling in which water from natural bodies of water is used to cool a generating facility and the heated water is discharged back into the source.  The Utility's Diablo Canyon Hunters Point and Humboldt Bay power plants areplant is among an estimated 539 generation facilities nationwide that are affected by this rulemaking.  The EPA regulations establish a set of performance standards that vary with the type of water body and that are intended to reduce impacts to aquatic organisms. Significant capital investment may be required to achieve the standards. Theorganisms by establishing a set of performance standards for cooling water intake structures.  These regulations allow site-specific compliance

26


determinations measures if a facility's cost of compliance is significantly greater than either the benefits to be achieved or the compliance costs considered by the EPA.  The EPA regulations also allow the use of environmental mitigation or restoration to meet compliance requirements in certain cases.  In response to the EPA regulations, in June 2006, the California State Water Resources Control Board (“Water Board”) published a draft policy for California’s implementation of Section 316(b) that proposes to eliminate the EPA’s site-specific compliance options, although the draft state policy would permit environmental restoration as a compliance option for nuclear facilities if the installation of cooling towers would conflict with a nuclear safety requirement.  Various parties separately challenged the EPA's regulations in court, and the cases were consolidated in U.S. Court of Appeals for the Second Circuit (“Second Circuit”).  In January 2007, the Second Circuit remanded significant provisions of the regulations to the EPA for reconsideration and held that a cost-benefit test could not be used to comply with performance standards or to obtain a variance from the standards.  The Second Circuit also ruled that environmental restoration cannot be used to comply with the standard.  Petitions seeking Supreme Court review of the Second Circuit’s decision are pending, and the EPA has suspended its regulations. It is uncertain when the EPA will issue revised regulations, whether the Supreme Court will accept review of the Second Circuit decision, how judicial developments will affect the EPA’s revised regulations; how judicial developments and EPA’s revised regulations will affect the Water Board’s proposed policy, and when the Water Board will issue its final policy.  Depending on the nature of the final regulations that may ultimately be adopted by the EPA or the Water Board, the Utility may incur significant capital expense to comply with the final regulations which the Utility would seek to recover through rates.  If either the final regulations adopted by the EPA or the Water Board require the installation of cooling towers at Diablo Canyon, and if installation of such cooling towers is developing compliance strategies for each plant.not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon.

Groundwater
Compressor Station Litigation

Several lawsuits have been filed against the Utility alleging that exposure to chromium at or near the Utility’s Hinkley and TopockUtility's natural gas compressor stations contains hexavalent chromium ascaused personal injuries, wrongful deaths or other injuries. During 2006, the Utility entered into a resultsettlement

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agreement to resolve most of these claims.  Pursuant to the settlement agreement, in April 2006 the Utility released $295 million from escrow for payment to approximately 1,100 plaintiffs. Three complaints, filed by approximately 125 plaintiffs who did not participate in the settlement, are still pending in the Superior Court for the County of Los Angeles.  During 2007 some individual plaintiffs’ claims were dismissed based on the applicable statute of limitations.  Also, during 2007 the Utility agreed to settle with the remaining plaintiffs, subject to execution of final documentation and court approval of the Utility’s past operating practices. The Utility has a comprehensive programsettlement of the minor plaintiffs' claims which is expected to monitor a networkoccur during the first half of groundwater wells at both the Hinkley2008.  PG&E Corporation and Topock natural gas compressor stations. At Hinkley, the Utility is cooperating with the Regional Water Quality Control Board to evaluate and remediate the chromium groundwater plume. In 2005, the Utility took interim measures to control movement of the Hinkley plume, as well as evaluated options to remediate the plume. At the Topock gas compressor station, located near Needles, California adjacent to the Colorado River, hexavalent chromium has been detected in samples taken from groundwater monitoring wells located approximately 65 feet from the Colorado River. The Utility is cooperating with the California Department of Toxic Substances Control, or DTSC, other state agencies, appropriate federal agencies and other interested parties, to implement interim measures as well as develop a long-term plan to ensuredo not expect that the hexavalent chromium does not affect the Colorado River. In 2005, the Utility took interim measures to control the chromium plume by extracting impacted groundwater and spent approximately $38.8 million on these measures. The Utility plans to continue these activities in 2006 and to work toward the development of a final plan to address the plume in 2006. The Utility currently estimates that itsettlement will spend at least $22 million in 2006 for remediation activities at Topock and $7.4 million in 2006 for remediation activities at Hinkley. Although work at the Topock site poses several technical and regulatory obstacles, the Utility’s remediation costs for Topock are subject to the ratemaking mechanism described above. The Utility does not expect the remediation of the Topock and Hinkley gas compressor sites to have a material adverse effect on itstheir financial condition or results of operations or financial condition. The Utility does not expect that it will incur any material expenditures related to any remediation at its Kettleman natural gas compressor station.operations.



Many of the Utility's facilities and operations are located in, or pass through, areas that are designated as critical habitats for federal or state-listed endangered, threatened or sensitive species. The Utility may be required to incur additional costs or be subjected to additional restrictions on operations if additional threatened or endangered species are listed or additional critical habitats are designated at or near the Utility's facilities or operations. The Utility is seeking to secure "habitat“habitat conservation plans"plans” to ensure long-term compliance with the state and federal endangered species acts. The Utility expects that it will be able to recover costs of complying with state and federal endangered species acts through rates.


The Utility's facilities are subject to the requirements issued by the EPA under the Resource Conservation and Recovery Act or RCRA,(“RCRA”) and the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended or CERCLA,(“CERCLA”) as well as other state hazardous waste laws and other environmental requirements. CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site.site, and in some cases corporate successors to the operators or arrangers. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, damages to natural resources and the costs of required health studies. In the ordinary course of the Utility's operations, the Utility generates waste that falls within CERCLA's definition of a hazardous substancesubstances and, as a result, has been and may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

The Utility assesses, on an ongoing basis, measures that may be necessary to comply with federal, state and local laws and regulations related to hazardous materials and hazardous waste compliance and remediation activities. The Utility has a comprehensive program to comply with hazardous waste storage, handling and disposal requirements issued by the EPA under RCRA and CERCLA, state hazardous waste laws and other environmental requirements.

The Utility has been, and may be, required to pay for environmental remediation at sites where the Utility has been, or may be, a potentially responsible party under CERCLA and similar state environmental laws. These sites include former manufactured gas plant sites, power plant sites, gas gathering sites, compressor stations and sites where the Utility stores, recycles and disposes of potentially hazardous materials. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances even if it did not deposit those substances on the site.

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Operations at the Utility's current and former generation facilities may have resulted in contaminated soil or groundwater. Although the Utility sold most of its geothermal generation facilities and most of its fossil fuel-fired plants, in many cases the Utility retained pre-closing environmental liability under various environmental laws. The Utility currently is investigating or remediating several such sites with the oversight of various governmental agencies.  Additionally, the Utility’s Hunters Point power plant in San Francisco closed in May 2006 and is in the decommissioning process.  Preliminary remedial investigations are underway, with agency approval of a remediation plan expected by second quarter 2009.  The Utility estimates that it will spend approximately $16.6 million in 2008 and approximately $22.7 million in 2009 for these activities.

In addition, the federal Toxic Substances Control Act regulates the use, disposal and clean-up of polychlorinated biphenyls, or PCBs, which are used in certain electrical equipment. The Utility has removed from service all of the distribution capacitors and network transformers containing high concentrations of PCBs, representing the vast majority of PCBs existingthat had existed in the Utility's electricity distribution system.

The Utility is assessing whether and to what extent remedial action may be necessary to mitigate potential hazards posed by certain disposal sites and retired manufactured gas plant sites. During their operation, from the mid-1800s through the early 1900s, manufactured gas plants produced lampblack and tar residues. The residues thatfrom these operations, which may remain at some sites, contain chemical compounds that now are classified as hazardous. There are 95 such sites within the Utility’s service territory that are owned by the

29



Utility or third parties. The Utility owns all or a portionhas determined that it is liable for the remediation of 27 manufactured gas plant42 sites, is potentially liable for remediation of an additional 33 sites, and is not liable for remediation at the
remaining 20 sites.  The Utility has a program, in cooperation with environmental agencies and third party owners, to evaluate and take appropriate action to mitigate any potential health or environmental hazards at these sites.the 42 sites for which the Utility is liable. The Utility spent approximately $2$7 million in 20052007 and expects to spend approximately $5$25 million in 20062008 on these projects.sites. The Utility expects that expenses at these sites will increase as remedial actions related to these sites are approved by regulatory agencies. In addition, approximately 68 other manufactured gas plants in the Utility's service territoryagencies and claims by third party owners are now owned by others.settled.    The Utility spent approximately $4.1 million settling third-partyis implementing a new program to analyze potential liability for remediation claims byat the current owners of former manufactured gas plant sites in 2005 and33 additional sites.  Although it is possiblelikely that the Utility maywill incur additional clean-upremediation costs related to some of these sites in the future if hazardous substances for which the Utility has liability are found.
cannot quantify the potential amount.  

Under environmental laws such as CERCLA, the Utility has been or may be required to take remedial action at third-party sites used for the disposal of waste from the Utility's facilities, or to pay for associated clean-up costs or natural resource damages. The Utility is currently aware of eightsix such sites where investigation or clean-up activities are currently underway. At the Geothermal Incorporated site in Lake County, California, the Utility has been directed to perform site studiessubstantially completed closure of the disposal facility, which was abandoned by its operator. The Utility was the major responsible party and any necessary remedial measures by regulatory agencies. Atled the remediation effort on behalf of the responsible parties. For the Casmalia disposal facility near Santa Maria, California, the Utility and several other generators ofparties that sent waste sent to the site have entered into a court-approved agreement with the EPA that requires the Utility and the other parties to perform certain site investigation and mitigationremediation measures.

In addition, the Utility has been named as a defendant in several civil lawsuits in which plaintiffs allege that the Utility is responsible for performing or paying for remedial action at sites that it no longer owns or never owned. Remedial actions may include investigations, health and ecological assessments, and removal of wastes.

Groundwater at the Utility’s Hinkley and Topock natural gas compressor stations contains hexavalent chromium as a result of the Utility’s past operating practices. The Utility has a comprehensive program to monitor a network of groundwater wells at both the Hinkley and Topock natural gas compressor stations. At Hinkley, the Utility is cooperating with the Regional Water Quality Control Board to evaluate and remediate the chromium groundwater plume. In 2006, the Utility took interim measures to control movement of the Hinkley plume, and evaluated options to remediate the plume. At the Topock gas compressor station, located near Needles, California, hexavalent chromium has been detected in samples taken from groundwater monitoring wells located approximately 65 feet from the Colorado River, which is adjacent to the site. The Utility, in cooperation with the California Department of Toxic Substances Control, other state agencies and appropriate federal agencies, has implemented interim measures including a system of extractions wells and a treatment plant designed to prevent movement of the plume toward the river.  In addition the Utility is working with the agencies to develop a long-term plan to ensure that the hexavalent chromium does not affect the Colorado River. In 2007, the Utility spent approximately $23 million on the interim measures and for work on the longer term site solution. The Utility plans to continue these activities in 2008 and to work toward the development of a final plan to address the plume in 2008. The Utility currently estimates that it will spend at least $20 million in 2008 for remediation activities at Topock and $14 million in 2008 for remediation activities at Hinkley. Although work at the Topock site poses several technical and regulatory obstacles, the Utility’s remediation costs for Topock are subject to the ratemaking mechanism described above. The Utility does not expect the remediation of the Topock and Hinkley gas compressor sites to have a material adverse effect on its results of operations or financial condition. The Utility does not expect that it will incur any material expenditures related to any remediation at its Kettleman natural gas compressor station.

The cost of environmental remediation is difficult to estimate.  The Utility records an environmental remediation liability when site assessments indicate remediation is probable and it can estimate a range of reasonably likely clean-up costs.  The Utility reviews its remediation liability on a quarterly basis for each site where it may be exposed to remediation responsibilities.  The liability is an estimate of costs for site investigations, remediation, operations and maintenance, monitoring and site closure using current technology, and considers enacted laws and regulations, experience gained at similar sites, and an assessment of the probable level of involvement and financial condition of other potentially responsible parties.  Unless there is a better estimate within this range of possible costs, the Utility records the costs at the lower end of this range.  The Utility estimates the upper end of this cost range using reasonably possible outcomes that are least favorable to the Utility.  It is reasonably possible that a change in these estimates may occur in the near term due to uncertainty concerning the Utility's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. The Utility estimates the upper end of the cost range using reasonably possible outcomes least favorable to the Utility.

The Utility had an undiscounted environmental remediation liability of approximately $469$528 million at December 31, 20052007 and approximately $327$511 million at December 31, 2004. During the year ended December 31, 2005, the liability increased by approximately $142 million. This net increase reflects a $131 million increase attributable to a revised remediation estimate for the Topock gas compressor station and a $24 million increase attributable to a revised remediation estimate for the Hinkley gas compressor station. These increases, in addition to other increases in liability, were offset by remediation payments.2006.  The approximately $469 million accrued at December 31, 2005, includes approximately $193 million for remediation at these gas compressor sites, approximately $100 million related to the pre-closing remediation liability associated with divested generation facilities, and approximately $176 million related to remediation costs for those generation facilities that the Utility still owns, gas gathering sites, third-party disposal sites, and manufactured gas plant sites that either are owned by the Utility or are the subject of remediation orders by environmental agencies or claims by the current owners of the former manufactured gas plant sites. Of the approximately $469 million environmental remediation liability, approximately $141 million has been included in prior rate-setting proceedings and the Utility expects that an additional approximately $259 million will be allowable for inclusion in future

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rates in accordance with the ratemaking mechanism described above. The Utility also recovers its costs from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the Utility's ultimate obligations may be subject to refund to customers. The Utility'sUtility’s undiscounted future costs could increase to as much as $680$834 million if the other potentially responsible parties are not financially able to contribute to these costs, or if the extent of contamination or necessary remediation is greater than anticipated. The amount

For more information about environmental remediation liabilities, see Note 17 of approximately $680 million does not include an estimate for the cost of remediation at known sites owned or operatedNotes to the Consolidated Financial Statements in the past by the Utility's predecessor corporations for which the Utility has not been able to determine whether a liability exists.2007 Annual Report.


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Under       As part of the Nuclear Waste Policy Act of 1982, or Nuclear Waste Act,Congress authorized the DOE is responsible forand electric utilities with commercial nuclear power plants to enter into contracts under which the transportation, and permanent storage and disposal of spent nuclear fuel and high-level radioactive waste. Under the Nuclear Waste Act, utilities areDOE would be required to provide interim storage facilities until permanent storage facilities are provided bydispose of the federal government. The Nuclear Waste Act mandates that one or more permanent disposal sites be in operation by 1998. Consistent with the law, the Utility entered into a contract with the DOE providing for the disposal of theutilities' spent nuclear fuel and high-level radioactive waste from the Utility's nuclear power facilities beginning notno later than January 1998. The DOE has been unable to meet its contractual commitment to begin accepting spent fuel. First, there was a delay31, 1998, in identifying a storage site. Then, afterexchange for fees paid by the utilities.  In 1983, the DOE selected Yucca Mountain, Nevada for the site, protracted litigation has prevented the DOE from constructing the storage facility. The DOE's current estimate for an available site to begin accepting physical possession of the spent nuclear fuel is 2010. However, considerable uncertainty exists regarding when the DOE will begin to accept spent fuel for storage or disposal. Under the Utility'sentered into a contract with the Utility to dispose of nuclear waste from the Utility’s two nuclear generating units at Diablo Canyon and its retired nuclear facility at Humboldt Bay. The DOE iffailed to develop a permanent storage site by January 31, 1998.  The Utility believes that the DOE completes a storage facility by 2010, the earliest Diablo Canyon'sexisting spent fuel would be acceptedpools at Diablo Canyon (which include newly constructed temporary storage racks) have sufficient capacity to enable the Utility to operate Diablo Canyon until approximately 2010 for storage or disposal would be 2018.Unit 1 and 2011 for Unit 2.

On January 22, 2004,Because the DOE failed to develop a permanent storage site, the Utility filed separate complaints inobtained a permit from the U.S. Court of Federal Claims against the DOE alleging that the DOE has breached its contractual obligation to move used nuclear fuel from Diablo Canyon and Humboldt Bay Unit 3 to a national repository beginning in 1998. The complaints seek recovery of the Utility's costs incurred for the planning and development of on-site storage at both facilities as a result of the DOE's failure to meet its obligations. The Utility's complaints are similar to complaints filed by at least 20 other utilities with nuclear facilities. Trial is scheduled to begin on June 5, 2006.
At the projected level of operation for Diablo Canyon, the Utility's current facilities are able to store on-site all spent fuel produced through approximately 2007. In March 2004, the NRC authorized the Utility to build an on-site dry cask storage facility to store spent fuel through approximately 2021 for Unit 1 and to 2024 for Unit 2. Several intervenersat least 2024.  After various parties appealed the NRC's decision toNRC’s issuance of the permit, the U.S. Court of Appeals for the Ninth Circuit or Ninth Circuit. The Ninth Circuit heard oral argumentissued a decision in 2006 requiring the NRC to issue a supplemental environmental assessment report on the appealpotential environmental consequences in October 2005,the event of a terrorist attack at Diablo Canyon, as well as to review other contentions raised by the appealing parties related to potential terrorism threats.  In August 2007, the NRC staff issued a final supplemental environmental assessment report concluding there would be no significant environmental impacts from potential terrorist acts directed at the Diablo Canyon storage facility.  On January 15, 2008, the NRC decided to hold hearings on whether it provided a complete list of the references upon which it relied to find that there would not be a significant environmental impact and a decision is pending. PG&E Corporationwhether it sufficiently addressed the impacts on land and the Utility cannot predict the outcomelocal economy of this appeal.

In April 2004, San Luis Obispo County (the California county where Diablo Canyona potential terrorist attack.  It is located) issued a permit under the California Coastal Act, subject to a number of conditions. The Utility, along with several other interested parties, filed appeals of the County's decision with the California Coastal Commission. The Utility's appeal challenged one of the conditions pertaining to the granting of public access to the coast and other portions of the Utility's property surrounding Diablo Canyon. On December 8, 2004, the California Coastal Commission granted the Utility's application for a coastal development permit authorizing it to proceed with its planned construction of an on-site dry cask storage facility. The Commission granted the Utility's appeal, denied the appeals of other parties and conducted a de novo review of the application. The Commission's December 8, 2004 decision requiresexpected that the Utility provide expanded public access to the coast and other lands surrounding Diablo Canyon, although such public access is less expansive than the County had originally required andNRC will be subject toissue a one-year study process. Construction of the on-site dry cask storage facility beganfinal decision in the third quarter 2005 and is expected to be completed byof 2008.

To provide another storage alternative in the event construction ofThe Utility expects to complete the dry cask storage facility is delayed, in November 2005 the NRC authorized the Utility to install a temporary storage rack in each unit's existingand begin loading spent fuel storage pool that would increase the on-site storage capability to permit the Utility to operate Unit 1 until 2010 and Unit 2 until 2011. The Utility anticipates that it would complete the installation of the temporary storage racks by December 2006. This temporary option does not require local or California Coastal Commission permits to be obtained.in 2008.  If the Utility is unable to complete the dry cask storage facility, or if constructionoperation of the facility is delayed beyond 2010, andor if the Utility is otherwise unable to increase its on-site storage capacity, it is possible that the operation of Diablo Canyon may have to be curtailed or halted as early as 2010 with respect to Unit 1 and 2011 with respect to Unit 2 and continued until such time as additional safe storage for spent fuel can be safely stored.

is made available.
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In July 1988,The Utility and other nuclear power plant owners have sued the NRC gave theDOE for breach of contract.  The Utility final approvalseeks to store radioactive waste from the Utility's retired nuclear generating facility,recover its costs to develop on-site storage at Diablo Canyon and Humboldt Bay Unit 3, at3.  In October 2006, the plant until 2015 before ultimately decommissioningU.S. Court of Federal Claims found the unit.DOE had breached its contract and awarded the Utility approximately $42.8 million of the $92 million incurred by the Utility through 2004.  The Utility has agreedappealed to remove all spent fuel when the federal disposal site is available. In 1988,U.S. Court of Appeals for the Federal Circuit seeking to increase the amount of the award and challenged the U.S. Court of Federal Claims’ finding that the Utility completedwould have incurred some of the first stepcosts for the on-site storage facilities even if the DOE had complied with the contract.  A decision on the appeal is expected by the end of 2008.  The Utility will seek to recover costs incurred after 2004 in future lawsuits against the DOE.  Any amounts recovered from the DOE will be credited to customers through rates.

PG&E Corporation and the Utility are unable to predict the outcome of this appeal or the amount of any additional awards the Utility may receive.  If the U.S. Court of Federal Claims’ decision is not overturned or modified on appeal, it is likely that the Utility will be unable to recover all of its future costs for on-site storage facilities from the DOE.  However, reasonably incurred costs related to the on-site storage facilities are, in the decommissioningcase of Diablo Canyon, recoverable through rates and, in the case of Humboldt Bay Unit 3, and placed the unit into SAFSTOR, a condition of monitored safe storage in which the unit will be maintained until the spent nuclear fuel is removed from the spent fuel pool and the facility is dismantled. The used fuel assemblies currently are stored in metal racks submerged in a pool of water called a wet storage pool. The specially designed storage pool is constructed of steel-reinforced concrete and lined with stainless steel.recoverable through its decommissioning trust fund. 


In June 2004, the Utility reported to the NRC that the Utility was unable to account for all of the used fuel segments from Humboldt Bay Unit 3 that the Utility's records indicate were sent to storage, and that the Utility was evaluating whether the used fuel was placed in the storage pool. On August 19, 2005, the NRC issued an inspection report concluding that the Utility was unable to account for the location of three 18-inch segments of used nuclear fuel. The NRC issued its report after the Utility filed its final report in May 2005 updating the NRC as to the Utility's efforts to locate the used fuel. The Utility's report concludes that it is very likely that these pieces were shipped to a low-level radioactive waste facility. In its August 19, 2005 report,nuclear power facilities consist of two units at Diablo Canyon and the NRC determined that the Utility's inability to conclusively locate the used fuel did not pose any threat to the health and safety of the public. In December 2005, the NRC issued a notice of violation to the Utility and imposed a penalty of $96,000 on the Utility for failure to control its inventory and to keep adequate records of these materials. The Utility did not contest the finding of a violation and paid the penalty in January 2006.

The Utility has received a license from the NRC to build an on-site dry cask storageretired facility at Humboldt Bay Unit 3. The Utility also has received approval from the California Coastal Commission for a permit to build the facility. Transfer of spent fuel to the dry cask facility would allow early decommissioning of Humboldt Bay Unit 3. The Utility anticipates that construction of the dry cask storage facility can be completed in time for decommissioning of Humboldt Bay Unit 3 to begin in 2009.


Nuclear decommissioning requires the safe removal of nuclear facilities from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use.  For ratemaking purposes,The Utility makes contributions to trusts to provide for the eventual decommissioning of each nuclear unit.  In the Utility’s 2005 Nuclear Decommissioning Cost Triennial Proceeding (“NDCTP”), used to determine the level of Utility trust contributions and related revenue requirement, the CPUC assumed that the eventual decommissioning of Diablo Canyon Unit 1 iswould be scheduled to begin in 20212024 and to be completed in 2040. Decommissioning2044; that decommissioning of Diablo Canyon Unit 2 iswould be scheduled to begin in 2025 and to be completed in 2041,2041; and that decommissioning of Humboldt Bay Unit 3 iswould be scheduled to begin in 2009 and to be completed in 2015.

As presented in the  The Utility’s Nuclear Decommissioning Costs Triennial Proceeding, or NDCTP, pending at the CPUC, the estimated nuclear decommissioning cost for the Diablo Canyon Units 1 and 2 and Humboldt Bay Unit 3 is approximately $2.03 billion in 2005 dollars (or approximately $5.12 billion in future dollars). These estimates are based on the 2005 decommissioning cost studies, prepared in accordance with CPUC requirements. The Utility's revenue requirements for nuclear decommissioning costs are recovered from customers through a non-bypassable charge that will continue until those costs are fully recovered.  The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants.  Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates, regulatory requirements, technology, and costs of labor, materials and equipment.

The nuclear decommissioning cost estimate described above is used for regulatory purposes. Under generally accepted accounted principles, or GAAP, requirements, the decommissioning cost estimate is calculated using a different method. In accordance with Statement of Financial Accounting Standards No. 143, the Utility adjusts its nuclear decommissioning obligation to reflect the fair value of decommissioning its nuclear power facilities.  The Utility records the Utility's total nuclear decommissioning obligation as an asset retirement obligation on the Utility's Consolidated Balance Sheet. Decommissioning costs are recorded as a component of depreciation expense, with a corresponding credit to the asset retirement costs regulatory liability. The total nuclear decommissioning obligation accrued in accordance with GAAP was approximately $1.3 billion at December 31, 2005 and $1.2 billion at December 31, 2004. The primary difference between the Utility'srecovers its revenue requirements for estimated nuclear decommissioning obligation as recorded in accordance with GAAP andcosts from customers through a non-bypassable charge that the estimate prepared in accordance with the CPUC requirements is that GAAP incorporates various potential settlement dates for the obligation and includes an estimated amount for third-party laborUtility expects will continue until those costs into the fair value calculation.

are fully recovered.  Decommissioning costs recovered in rates are placed in nuclear decommissioning trusts.  The funds in the decommissioning trusts, along with accumulated earnings, will be used exclusively for

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decommissioning and dismantling the Utility's nuclear facilities. The Utility has three decommissioning trusts for its Diablo Canyon and Humboldt Bay Unit 3 nuclear facilities. The Utility has elected that two of these trusts be treated under the Internal Revenue Code as qualified trusts. If certain

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conditions are met, the Utility is allowed a deduction for the payments made to the qualified trusts. These payments cannot exceed the amount collected from customers through the decommissioning charge. The qualified trusts are subject to a lower tax rate on income and capital gains, thereby increasing the trusts' after-tax returns. Among other requirements, to maintain the qualified trust status the IRS must approve the amount to be contributed to the qualified trusts for any taxable year. The remaining non-qualified trust is exclusively for decommissioning Humboldt Bay Unit 3. The Utility cannot deduct amounts contributed to the non-qualified trust until such decommissioning costs are actually incurred.

As authorized in the 2002 NDCTP, in 2005, the Utility was authorized to collect approximately $18.4 million in rates and contributed approximately $18.4 million to the qualified nuclear decommissioning trust for Humboldt Bay Unit 3. For 2006, the Utility is authorized to collect approximately $18.4 million in rates for decommissioning Humboldt Bay Unit 3. The Utility expects to contribute that entire amount to the qualified trusts for Humboldt Bay Unit 3. The Utility has received approval from the IRS to contribute all of the collected amounts to the qualified trust for Humboldt Bay Unit 3 for 2005. The Utility expects to file a ruling request with the IRS in the first quarter of 2006 for contributions made in 2006. The CPUC issued a decision in the 2002 NDCTP finding that the funds in the Diablo Canyon nuclear decommissioning trusts are sufficient to pay for the eventual decommissioning. Therefore, no contributions were made to the Diablo Canyon trusts in 2005 and no contributions are expected for 2006.

On November 10, 2005, the Utility filed its 2005 NDCTP, seeking approval for its proposed nuclear decommissioning revenue requirements for the years 2007-2009. The Utility’s 2005 NDCTP seeks recovery of $9.5 million in revenue requirements relating to the qualified trust for Diablo Canyon and $14.6 million in revenue requirements relating to the qualified trust for Humboldt Bay Unit 3. The Utility expects to begin evidentiary hearings with the CPUC in May 2006 and expects a decision in October 2006.

For more information about nuclear decommissioning, including the estimated decommissioning costs, see Note 13 of the Notes to the Consolidated Financial Statements in the 20052007 Annual Report.


Several lawsuits have been filed against the Utility seeking damages from alleged chromium contamination at the Utility's Hinkley, Topock and Kettleman natural gas compressor stations. See “Item 3. Legal Proceedings,” below for a description of the pending litigation.


Electric and magnetic fields or EMFs,(“EMFs”) naturally result from the generation, transmission, distribution and use of electricity.  In January 1991, the CPUC opened an investigation to address increasing public concern, especially with respect to schools, regarding potential health risks that may be associated with EMFs from utility facilities. In its order instituting the investigation, the CPUC acknowledged that the scientific community has not reached consensus on the nature of any health impacts from contact with EMFs, but went on to state that a body of evidence has been compiled that raises the question of whether adverse health impacts might exist.

In November 1993, the CPUC adopted an interim EMF policy for California energy utilities that, among other things, requires California energy utilities to take no-cost and low-cost steps to reduce EMFs from new or upgraded utility facilities. California energy utilities were required to fund an EMF education program and an EMF research program managed by the California Department of Health Services. As part of the Utility's effort to educate the public about EMFs, the Utility provides interested customers with information regarding the EMF exposure issue. The Utility also provides a free field measurement service to inform customers about EMF levels at different locations in and around their residences or commercial buildings.

In October 2002, the California Department of Health Services released its report to the CPUC and the public, based primarily on its review of studies by others, evaluating the possible risks from EMFs, to the CPUC and the public.EMFs.  The report's conclusions contrast with other
recent reports by authoritative health agencies in that the California Department of Health Services' report has assigned a higher probability to the possibility that there isof a causal connection between EMF exposures and a number of diseases and conditions, including childhood leukemia, adult leukemia, amyotrophic lateral sclerosis and miscarriages.

On January 26, 2006, the CPUC issued a decision which affirms the CPUC’s “low-cost/no-cost, prudent avoidance” policy to mitigatereduce EMF exposure for new utility transmission and substation projects. The CPUC ordered the continued use of a 4% of project cost benchmark for EMF mitigation. In addition, the CPUC (1) adopted rules and policies to improve

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utility design guidelines for reducing EMFs, (2) ordered a utility workshop to implement these policies and standardize design guidelines, and (3) established a rule whereby the CPUC will not take EMF testimony in any future proceedings other than issues concerning utilities’ compliance with established CPUC mitigation standards.reduction measures.  The CPUC also reaffirmed that it has exclusive jurisdiction with respect to utility EMF matters.

The Utility currently is not involved in third-party litigation concerning EMFs. In August 1996, the California Supreme Court held that homeowners are barred from suing utilities for alleged property value losses caused by fear of EMFs from power lines. The court expressly limited its holding to property value issues, leaving open the question as to whether lawsuits for allegedIn a case involving allegations of personal injury, resulting from exposure to EMFs are similarly barred. The Utility was one of the defendants in civil litigation in which the plaintiffs alleged personal injuries resulting from exposure to EMFs. In January 1998, thea California appeals court in this matter held that the CPUC has exclusive jurisdiction over personal injury and wrongful death claims arising from allegations of harmful exposure to EMFs, and barred plaintiffs' personal injury claims. Plaintiffs filed an appeal of this decision with the California Supreme Court. The California Supreme Court declined to hear the case.plaintiffs’ appeal of this decision.

Item 1A. Risk Factors


A discussion of the significant risks associated with investments in the securities of PG&E Corporation and the Utility is set forth under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations— Risk“Risk Factors” in the 2005MD&A in the 2007 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.

Item 1B. Unresolved Staff Comments


Not applicable.Item 2. Properties


The Utility owns or has obtained the right to occupy and/or use real property comprising the Utility's electricity and natural gas distribution facilities, natural gas gathering facilities and generation facilities, and natural gas and electricity transmission facilities, all of which are described above under "Electricity“Electric Utility Operations"Operations” and "Gas“Natural Gas Utility Operations."Operations” above.  In total, the Utility occupies 8.29.8 million square feet of real property, including 7.08.5 million square feet that the Utility owns.  Of the 8.29.8 million square feet of occupied real property, approximately 1.51.7 million square feet represent the Utility's corporate headquarters located in several buildings in San Francisco, California.  The Utility leases approximately 120,000 square feet of the approximate 1.51.7 million square feet of office space.  The Utility occupies or uses real property that it does not own primarily through various leases, easements, rights-of-way, permits or licenses from private landowners or governmental authorities

authorities.  The Utility currently owns approximately 167,000 acres of land, approximately 140,000 acres of which it will encumber with conservation easements and/or donate to public agencies or non-profit conservation organizations under the Chapter 11 Settlement Agreement.  Approximately 75,000 acres of this land may be donated in fee and encumbered with conservation easements.  The remaining land contains the Utility's or a joint licensee's hydroelectric generation facilities and will only be encumbered with conservation easements. As contemplated in the Chapter 11 Settlement Agreement, the Utility formed an entity, the Pacific Forest Watershed Lands Stewardship Council or the Council,(“Council”) to oversee the development and implementation of a Land Conservation Plan or LCP,(“LCP”) that will articulate the long-term management objectives for the 140,000 acres.  The Council is guidedgoverned by an 18-member Board of Directors that representrepresents a range of diverse interests, including the CPUC, California environmental agencies, organizations representing underserved and minority constituencies, agricultural and business interests, and public officials.  The Utility has appointed one1 out of 18 members of the Board of Directors of the Council. TheIn December 2007, the Council is charged to adopt and presentadopted the LCP and submitted it to the Utility by April 2007. Utility.

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The Utility has accepted the LCP and will then seek authorization from the CPUC, the FERC and other approving entities to proceed with the transactions necessary to implement the LCP. If the Council is unable to reach consensus on all or part of the LCP, the Utility will seek regulatory approval of the transactions required to implement its own plan, along with a description of the positions of the disputing board members before April 2013.

PG&E Corporation also leases approximately 74,000 square feet of office space from a third party in San Francisco, California.  This lease expires in 2012.

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In addition to the following legal proceedings, PG&E Corporation and the Utility are involved in various legal proceedings in the ordinary course of their business.


On April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code, or Chapter 11, in the U.S. Bankruptcy Court for the Northern District of California, or Bankruptcy Court. On April 12, 2004, the Utility's plan of reorganization under Chapter 11 became effective. On this date, the effective date, the Utility emerged from Chapter 11. On the effective date, the Utility paid all valid claims, deposited funds into escrow accounts for the payment of disputed claims upon their resolution, reinstated certain obligations, and paid other obligations.

The Utility's plan of reorganization incorporated the terms of the Settlement Agreement. Under the Settlement Agreement, the CPUC has waived all existing and future rights of sovereign immunity, and all other similar immunities, as a defense in connection with any action or proceeding concerning the enforcement of, or other determination of the parties' rights under the Settlement Agreement, the plan of reorganization or the confirmation order. The CPUC also consented to the jurisdiction of any court or other tribunal or forum for those actions or proceedings, including the Bankruptcy Court. The CPUC's waiver is irrevocable and applies to the jurisdiction of any court, legal process, suit, judgment, attachment in aid of execution of a judgment, attachment before judgment, set-off or any other legal process with respect to the enforcement of, or other determination of the parties' rights under, the Settlement Agreement, the plan of reorganization or the confirmation order. The Settlement Agreement contemplates that neither the CPUC nor any other California entity acting on its behalf may assert immunity in an action or proceeding concerning the parties' rights under the Settlement Agreement, the plan of reorganization or the confirmation order.

The Settlement Agreement generally terminates nine years after the effective date of the plan of reorganization, except that the rights of the parties to the Settlement Agreement that vest on or before termination, including any rights arising from any default under the Settlement Agreement, will survive termination for the purpose of enforcement. The parties agreed that the Bankruptcy Court will have jurisdiction over the parties for all purposes relating to enforcement of the Settlement Agreement, the plan of reorganization and the confirmation order. The Bankruptcy Court retains jurisdiction to resolve remaining disputed claims. The parties also agreed that the Settlement Agreement, the plan of reorganization or any order entered by the Bankruptcy Court contemplated or required to implement the Settlement Agreement or the plan of reorganization will be irrevocable and binding on the parties and enforceable under federal law notwithstanding any future decisions or orders of the CPUC.

Two former CPUC commissioners who did not vote to approve the Settlement Agreement filed an appeal of the Bankruptcy Court's confirmation order with the U.S. District Court for the Northern District of California, or the District Court. On July 15, 2004, the District Court dismissed their appeal. The former commissioners have appealed the District Court's order to the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit. The Ninth Circuit heard oral arguments on the appeal on February 13, 2006. It is uncertain when a decision will be issued.

Under applicable federal precedent, once the plan of reorganization has been "substantially consummated," any pending appeals of the confirmation order should be dismissed as moot. If the Bankruptcy Court's confirmation order is overturned or modified on appeal, PG&E Corporation's and the Utility's financial condition and results of operations, and the Utility's ability to pay dividends or otherwise make distributions to PG&E Corporation, could be materially adversely affected. PG&E Corporation and the Utility believe the former commissioners' appeal of the confirmation order is without merit and will be rejected.


On November 8, 2000, the Utility filed a lawsuit in the District Court against the CPUC commissioners. In this lawsuit, the Utility seeks a declaration that the federally tariffed wholesale electricity costs that the Utility had incurred to serve the Utility's customers are recoverable in retail rates under the federal filed rate doctrine.

Under the Settlement Agreement, the Utility agreed to dismiss the filed rate case with prejudice on or as soon as practicable after the later of the effective date of the plan of reorganization and the date on which CPUC approval of the Settlement Agreement is no longer subject to appeal. On August 11, 2003, the Ninth Circuit issued an order staying proceedings in the filed rate case as requested by the Utility. Since the appeal brought by two former CPUC commissioners challenging the

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Bankruptcy Court’s confirmation order incorporating the terms of the Settlement Agreement is still pending in the Ninth Circuit, as discussed above, the Utility has not yet dismissed its complaint.


The Utility's Diablo Canyon power plant employs a "once-through"“once-through” cooling water system that is regulated under a NPDESClean Water Act National Pollutant Discharge Elimination System (“NPDES”) permit issued by the Central Coast Regional Water Quality Control Board or (“Central Coast Board.Board”).  This permit allows the Diablo Canyon power plant to discharge the cooling water at a temperature no more than 22 degrees above the temperature of the ambient receiving water, and requires that the beneficial uses of the water be protected.  The beneficial uses of water in this region include industrial water supply, marine and wildlife habitat, shellfish harvesting, and preservation of rare and endangered species.  In January 2000, the Central Coast Board issued a proposed draft cease and desist order alleging that, although the temperature limit has never been exceeded, the Utility's Diablo Canyon power plant's discharge was not protective of beneficial uses.

In October 2000, the Utility and the Central Coast Board reached a tentative settlement of this matter pursuant tounder which the Central Coast Board agreed to find that the Utility's discharge of cooling water from the Utility's Diablo Canyon power plant protects beneficial uses and that the intake technology reflects the best technology available, as defined in the federal Clean Water Act.  As part of the Central Coasttentative settlement, agreement, the Utility agreed to take measures to preserve certain acreage north of the plant and to fund approximately $6 million in environmental projects and future environmental monitoring related to coastal resources.  On March 21, 2003, the Central Coast Board voted to accept the Central Coast settlement agreement.  On June 17, 2003, the Central Coast settlement agreement was executed by the Utility, the Central Coast Board and the California Attorney General's Office.  A condition to the effectiveness of the settlement agreement is that the Central Coast Board renew Diablo Canyon's NPDES permit.

At its July 10, 2003 meeting, the Central Coast Board did not renew the NPDES permit and continued the permit renewal hearing indefinitely. Several Central Coast Board members indicated that they no longer supported the Central Coast settlement agreement, accepted in March 2003, and the Central Coast Board requested a team of independent scientists, as part of a technical working group, to develop additional information on possible mitigation measures for Central Coast Board staff.  In January 2005, the Central Coast Board published the scientists' draft report recommending several such mitigation measures. If the Central Coast Board adopts the scientists' recommendations, and if the Utility ultimately is required to implement the projects proposed in the draft report, it could incur costs of up to approximately $30 million.  The Utility would seek to recover these costs through rates charged to customers.  The California State Water Resources Control Board is developing a state policy for the implementation of Section 316(b) of the Clean Water Act, the adoption of which could affect future negotiations between the Central Coast Board and the Utility.  For more information about the draft state policy, see “Environmental Matters—Water Quality” in this report.

ThePG&E Corporation and the Utility believesbelieve that the ultimate outcome of this matter will not have a material adverse impact on thetheir Utility's financial condition or results of operations.


On January 10, 2002, the California Attorney General filed a complaint in the San Francisco Superior Court for the County of San Francisco or (“Superior Court,Court”) against PG&E Corporation and its directors, as well as against directors of the Utility, based on allegations of unfair or fraudulent business acts or practices in violation of California Business and Professions Code Section 17200 or (“Section 17200.17200”).  Among other allegations, the California Attorney General alleged that past transfers of funds from the Utility to PG&E Corporation during the period from 1997 through 2000 (primarily in the form of dividends and stock repurchases), and allegedly from PG&E Corporation to other affiliates of PG&E Corporation, violated various conditions established by the CPUC in decisions approving the holding company formation.  The California Attorney General alleged that the defendants violated these conditions when PG&E Corporation allegedly failed to provide adequate financial support to the Utility during the California energy crisis.

The complaint seeks injunctive relief, the appointment of a receiver, restitution in an amount according to proof, civil penalties of $2,500 against each defendant for each violation of Section 17200, a total penalty of not less than $500 million and costs of suit.  The California Attorney General's complaint also seeks restitution of assets allegedly wrongfully transferred to PG&E

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Corporation from the Utility.

On February 11, 2002, a complaint entitled City and County of San Francisco; People of the State of California v. PG&E Corporation, and Does 1-150, was filed in the Superior Court.  The complaint contains some of the same allegations contained in the California Attorney General's complaint, including allegations of unfair competition in violation of Section 17200.  In addition, the complaint alleges causes of action for conversion, claiming that PG&E Corporation "took“took at least

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$5.2 $5.2 billion from the Utility," and for unjust enrichment. The City and County of San Francisco or CCSF,(“CCSF”) seeks injunctive relief, the appointment of a receiver, restitution, disgorgement, the imposition of a constructive trust, civil penalties of $2,500 against each defendant for each violation of Section 17200 and costs of suit.

The complaints, which have been consolidated in the Superior Court, were filed after the CPUC issued two decisions in its investigative proceeding commenced in April 2001 into whether the California investor-owned electric utilities, including the Utility, complied with past CPUC decisions, rules and orders authorizing their holding company formations and/or governing affiliate transactions, as well as applicable statutes.  The order states that the CPUC would, among other matters, investigate the utilities' transfer of money to their holding companies, including during times when their utility subsidiaries were experiencing financial difficulties, the failure of the holding companies to financially assist the utilities when needed, the transfer by the holding companies of assets to unregulated subsidiaries, and the holding companies' actions to "ringfence"“ringfence” their unregulated subsidiaries.  In May 2005, the CPUC closed this investigation without making any findings. Under the Settlement Agreement, the CPUC agreed to dismiss with prejudice PG&E Corporation and the Utility from the CPUC's investigation as to past practices.

PG&E Corporation believes that the intercompany transactions challenged by the California Attorney General and CCSF were in full compliance with applicable law and CPUC conditions.  The challenged transactions forming the bulk of the restitution claims were regular quarterly dividends and stock repurchases.  As part of its annual cost of capital proceedings, the Utility advised the CPUC in advance of its forecast stock repurchases and dividends.  The CPUC did not challenge or question those payments.

In February and March 2002, PG&E Corporation filed noticesJanuary 2006, the U.S. Court of removal inAppeals for the Ninth Circuit (“Ninth Circuit”) issued a decision on the parties’ appeals of various rulings by the Bankruptcy Court to transferand the complaints toU.S. District Court for the Bankruptcy Court. Subsequently,Northern District of California  concerning jurisdictional issues.  The Ninth Circuit found that the plaintiffs filed motions to remand their actions to state court. In June 2002, the BankruptcySuperior Court held that federal law preemptedhad jurisdiction over the California Attorney General’s allegations concerningand CCSF’s restitution claims.  (In October 2006, the U.S. Supreme Court declined to grant PG&E Corporation’s participation inrequest to review the Utility’s bankruptcy proceedings.Ninth Circuit’s decision.)  The Bankruptcy Court directed the California Attorney General to file an amended complaint omitting certain of his Section 17200 allegations and remanded the amended complaint to the Superior Court. The Bankruptcy Court retained jurisdiction over CCSF’s causes of action for conversion and unjust enrichment, finding that these claims belong solely to the Utility and cannot be asserted by CCSF, but remanded CCSF’s Section 17200 cause of action to state court. In both cases, the parties appealed the Bankruptcy Court’s remand order to the District Court. In August 2002, the California Attorney General filed its amended complaint in the Superior Court. The Superior Court has coordinatedNinth Circuit did not address the California Attorney General’s case withand CCSF’s underlying allegations that PG&E Corporation and the case filed by CCSF.

On October 8, 2003,other defendants violated Section 17200.  The Ninth Circuit also did not decide the District Court reversed, in part,issue of who would be entitled to receive the Bankruptcy Court’s June 2002 decisionproceeds, if any, of a restitution award, and orderedPG&E Corporation continues to believe that the plaintiffs’ restitution claims under Section 17200any such proceeds would be sent to the Bankruptcy Court. The District Court found that these claims, estimated by plaintiffs to be approximately $5 billion, are the property of the Utility’sUtility.  Pursuant to the Chapter 11 estate and are therefore properly withinSettlement Agreement, the Bankruptcy Court’s jurisdiction. The District Court also affirmed,CPUC released all claims against PG&E Corporation or the Utility arising out of or in part, the Bankruptcy Court’s June 2002 decision and found that the plaintiffs’ civil penalty and injunctive relief claims under Section 17200 could be resolved in Superior Court. The California Attorney General and CCSF appealed the District Court’s remand orderany way related to the Ninth Circuit.energy crisis, including the CPUC’s investigation into past PG&E Corporation actions during the California energy crisis.  Accordingly, PG&E Corporation believes that any claims for such proceeds by the CPUC would be precluded.

While the Ninth Circuit appeal was pending, the Superior Court held a trial in December 2004 to consider the appropriate standard to determine what constitutes a separate violation of Section 17200 in order to determine the magnitude of potential penalties under Section 17200 (up to $2,500 per separate “violation”). The Superior Court did not address the question of whether any violations occurred.  In March 2005, the Superior Court issued a decision rejecting the “per victim” and “per [customer] bill” approaches advocated by the plaintiffs, standards that potentially could have resulted in millions of separate “violations.”  The Superior Court found that the appropriate standard was each transfer of money from the Utility to PG&E Corporation that plaintiffs allege violated Section 17200.  In July 27, 2005, the California Court of Appeal summarily denied a petition filed by the California Attorney General and CCSF seeking to overturn this decision.

On January 10, 2006, a three-judge panel of the Ninth Circuit issued a 2-1 decision reversing the District Court’s October 2003 order regarding which court had jurisdiction of the California Attorney General’s and CCSF’s restitution claims.  The Ninth Circuit ruled that the plaintiffs’ restitution claims constituted actions to enforce their police or regulatory power, actions which are exempt from the provisions of the Bankruptcy Code permitting removal of state actions to Bankruptcy Court. The Ninth Circuit remanded the restitution claims back to thenext case management conference in Superior Court. PG&E Corporation has filed a request for rehearing en banc with the Ninth Circuit.

The Ninth Circuit did not address the California Attorney General’s and CCSF’s underlying allegations that PG&E Corporation and the other defendants violated Section 17200. The Ninth Circuit also did not decide the issue of who would

35


be entitled to receive the proceeds, if any, of a restitution award, and PG&E Corporation continues to believe that any such proceeds would be the property of the Utility. The Settlement Agreement provides that all claims by the CPUC against PG&E Corporation or the Utility arising out of or in any way related to the energy crisis are released, including the CPUC’s investigation into past PG&E Corporation actions during the energy crisis. Accordingly, PG&E Corporation believes that any claims for such proceeds by the CPUC would be precluded.Court is scheduled on May 13, 2008.

PG&E Corporation believes that the California Attorney General’s and CCSF’s allegations have no merit and will continue to vigorously respond to and defend against the litigation.PG&E Corporation believes that the ultimate outcome of this matter would not result in a material adverse effect on PG&E Corporation’s financial condition or results of operations.

Compressor Station Chromium LitigationSolano County District Attorney’s Office

The following 12In a letter dated July 11, 2007, the Solano County District Attorney's Office stated its intention to file a civil suits are pendingcomplaint against the Utility relatingfor record-keeping violations related to alleged chromium contamination: (1) Aguayo v. Pacific Gas and Electric Company, filed March 15, 1995,an underground storage tank at the Utility’s service center in the Superior Court for the County of Los Angeles or Los Angeles County Superior Court, (2) Aguilar v. Pacific Gas and Electric Company, filed October 4, 1996, in Los Angeles County Superior Court, (3) Acosta, et al. v. Betz Laboratories, Inc., et al., filed November 27, 1996, in Los Angeles County Superior Court, (4) Adams v. Pacific Gas and Electric Company and Betz Chemical Company, filed July 25, 2000, in Los Angeles County Superior Court, (5) Baldonado v. Pacific Gas and Electric Company, filed October 25, 2000, in Los Angeles County Superior Court, (6) Gale v. Pacific Gas and Electric Company, filed January 30, 2001, in Los Angeles County Superior Court, Puckett v. Pacific Gas and Electric Company, filed March 30, 2001, in Los Angeles County Superior Court, (9) Alderson, et al. v. PG&E Corporation, Pacific Gas and Electric Company, Betz Chemical Company, et al., filed April 11, 2001, in Los Angeles County Superior Court, (10) Bowers, et al. v. Pacific Gas and Electric Company, et al., filed April 20, 2001, in Los Angeles County Superior Court, (11) Boyd, et al. v. Pacific Gas and Electric Company, et al., filed May 2, 2001, in Los Angeles County Superior Court, (12) Martinez, et al. v. Pacific Gas and Electric Company, filed June 29, 2001, in San Bernardino County Superior Court and (13) Miller v. Pacific Gas and Electric Company, filed November 21, 2001, in Los Angeles County Superior Court.

All of these civil actions, referred to as the Chromium Litigation, are now pending in the Los Angeles County Superior Court, or Superior Court. There are now approximately 1,200 plaintiffs in the Chromium Litigation who seek compensatory damages, more than 1,000 of whom are also seeking punitive damages. Although the plaintiffs’ complaints in the Chromium Litigation do not state the amount of compensatory or punitive damages claimed, approximately 1,000Vallejo, California.  The letter attached a copy of the current plaintiffs filed claims in the Utility’s Chapter 11 proceeding requesting compensatory damages in an approximate aggregate amountdraft complaint, which detailed a series of $500 millionalleged California Health and others filed claims for an "unknown amount." These claims were not discharged when the Utility’s planSafety Code record-keeping violations, some of reorganization became effective.

In general, plaintiffswhich date back to 2004.  Alleged violations include failing to complete inspections, testing, and claimants allege that exposurecertifications, and to chromium contamination in the vicinity of the Utility's gas compressor stations located at Kettleman and Hinkley, California, and the area of California near Topock, Arizona, caused personal injuries, wrongful death or other injuries, and seek related damages.
On February 3, 2006, the Utility entered into a settlement agreement with attorneys for approximately 1,100 plaintiffs in the Chromium Litigation. The following cases are covered by the settlement agreement: Aguayo, Aguilar, Acosta, Baldonado, Bowers, Boyd, Gale, Martinez, Miller and Puckett. The Utility has agreed to pay $295 millionmake records available to the settling plaintiffs.County.  Under the California Health and Safety Code, penalties of up to $5,000 per day for each violation may be assessed.  The Utility will deposit the settlement amount into escrow on April 21, 2006. The settling plaintiffs are requireddraft complaint also seeks penalties for unfair and unlawful business practices under California Business and Professions Code Section 17200, under which penalties of up to execute general releases in favor of the Utility, PG&E Corporation, its officers, directors, employees, and other affiliates, as to any and all claims asserted or which could have been asserted in the Chromium Litigation. After receipt of releases from at least 90% of the settling plaintiffs, executed requests for dismissals with prejudice of the settled cases, and documentation evidencing the Superior Court’s approval of the compromises or settlements with the settling plaintiffs who are minors, payments will$2,500 per violation may be released from escrow to plaintiffs’ attorneys for the plaintiffs who have submitted executed releases. If 90% of the settling plaintiffs do not execute releases by September 15, 2006, including a release signed by each of the eighteen plaintiffs scheduled to participate in the first trial, the Utility may, at its option, terminate the settlement agreement. In order to obtain 100% of the settlement funds from escrow, plaintiffs’ attorneys must submit releases from or on behalf of 100% of the settling plaintiffs.
With respect to the unresolved claims, the Utility will continue to pursue appropriate legal defenses, including the statute of limitations and the exclusivity of workers’ compensation and factual defenses, including lack of exposure to chromium and the inability of chromium to cause certain of the illnesses alleged.
assessed.  There

3634



are no allegations related to the discharge of any hazardous substances.  The Utility is investigating the allegations and has recorded a $314 million reserve in its financial statementsentered into discussions with respect to the Chromium Litigation. PG&E Corporation and theDistrict Attorney.  The Utility do not expectbelieves that the ultimate outcome with respect to the remaining unresolved claims will haveof this matter would not result in a material adverse effect on theirits financial condition or results of operations.



Not applicable.

Not applicable.


EXECUTIVE OFFICERS OF THE REGISTRANTS

The names, ages and positions of PG&E Corporation "executive“executive officers," as defined by Rule 3b-7 of the General Rules and Regulations under the Securities and Exchange Act of 1934 or (“Exchange Act,Act”) at February 1, 2006,20, 2008, are as follows:


Name
 
Age
 
Position
P.Peter A. Darbee 5355 Chairman of the Board, Chief Executive Officer, and President
L. H. Everett55Senior Vice President, Communications and Public Affairs
K.M.Kent M. Harvey 4749 Senior Vice President and Chief Risk and Audit Officer
R. M. Jackson48Senior Vice President, Human Resources
C.Christopher P. Johns 4547 Senior Vice President, Chief Financial Officer, and Treasurer
T. B. KingNancy E. McFadden 4449 Senior Vice President; President, Public Affairs
William T. Morrow48President and Chief Executive Officer, Pacific Gas and Electric Company
R.Hyun Park46Senior Vice President and General Counsel
Greg S. Pruett50Senior Vice President, Corporate Relations
Rand L. Rosenberg 5254 Senior Vice President, Corporate Strategy and Development
B.John R. WorthingtonSimon 5643 Senior Vice President, and General CounselHuman Resources

All officers of PG&E Corporation serve at the pleasure of the Board of Directors. During the past five years through February 20, 2008, the executive officers of PG&E Corporation had the following business experience. Except as otherwise noted, all positions have been held at PG&E Corporation.


Name
 
Position
 
Period Held Office
     
P.Peter A. DarbeeChairman of the Board, Chief Executive Officer, and PresidentSeptember 19, 2007 to present
Chairman of the Board and Chief Executive OfficerJuly 1, 2007 to September 18, 2007
 Chairman of the Board, Chief Executive Officer, and President January 1, 2006 to presentJune 30, 2007
  Chairman of the Board, Pacific Gas and Electric Company January 1, 2006 to presentMay 31, 2007
  President and Chief Executive Officer January 1, 2005 to December 31, 2005
  Senior Vice President and Chief Financial Officer July 9, 2001September 20, 1999 to December 31, 2004
Senior Vice President, Chief Financial Officer, and TreasurerSeptember 20, 1999 to July 8, 2001
     
L. H. EverettSenior Vice President, Communications and Public AffairsJanuary 9, 2006 to present
Senior Vice President and Assistant to the Chief Executive OfficerJanuary 1, 2005 to January 8, 2006
Senior Vice President and Assistant to the ChairmanAugust 2, 2004 to December 31, 2004
Vice President and Assistant to the ChairmanJune 1, 2001 to August 1, 2004
Vice President, Corporate Secretary, and Assistant to the ChairmanMay 1, 2001 to May 31, 2001
Vice President and Corporate SecretaryJuly 1, 1997 to April 30, 2001
Vice President and Corporate Secretary, Pacific Gas and Electric CompanyNovember 1, 1996 to May 31, 2001
K.Kent M. Harvey Senior Vice President and Chief Risk and Audit Officer October 1, 2005 to present
  Senior Vice President, - Chief Financial Officer, and Treasurer, Pacific Gas   and Electric Company November 1, 2000 to September 30, 2005
  Senior Vice President - Chief Financial Officer, Controller, and Treasurer, Pacific Gas and Electric CompanyJanuary 1, 2000 to October 31, 2000
   
R. M. JacksonSenior Vice President, Human Resources, PG&E Corporation and Pacific Gas and Electric CompanyAugust 2, 2004 to present
Vice President, Human Resources, PG&E CorporationJune 1, 2004 to August 1, 2004
Vice President, Human Resources, Pacific Gas and Electric CompanyJune 1, 1999 to August 1, 2004
C.Christopher P. Johns Senior Vice President, Chief Financial Officer, and Treasurer October 4, 2005 to present
  Senior Vice President and Treasurer, Pacific Gas and Electric CompanyJune 1, 2007 to present
Senior Vice President, Chief Financial Officer, and Treasurer, Pacific Gas    and Electric Company October 1, 2005 to presentMay 31, 2007
  Senior Vice President, Chief Financial Officer, and Controller January 1, 2005 to October 3, 2005
  Senior Vice President and Controller September 19, 2001 to December 31, 2004
  Vice President and Controller July
Nancy E. McFaddenSenior Vice President, Public AffairsMarch 1, 19972007 to present
Senior Vice President, Public Affairs, Pacific Gas and Electric Company June 20, 2007 to present
Vice President, Governmental Relations, Pacific Gas and Electric CompanySeptember 18,26, 2005 to February 28, 2007
Chairperson, California Medical Assistance CommissionNovember 13, 2003 to November 30, 2005
Senior Advisor and Deputy Chief of Staff, Office of Governor Gray DavisMay, 2001 to November, 2003
35

     
William T. B. KingSenior Vice President, PG&E CorporationJanuary 1, 2006 to present
Morrow President and Chief Executive Officer, Pacific Gas and Electric Company JanuaryJuly 1, 20062007 to present
  Executive Vice President and Chief Operating Officer, Pacific Gas and Electric Company August 1, 2006 to June 30, 2007
Chief Executive Officer, Europe, Vodafone Group PLC (a global mobile telecommunications company)May 1, 2006 to July 31, 2006
President, Vodafone KK, JapanApril 1, 2005 to DecemberApril 30, 2006
Chief Executive Officer, Vodafone UK, Ltd.February 1, 2004 to March 31, 2005
  Executive Vice President, and Chief of Utility Operations, Pacific Gas and Electric CompanyAugust 2, 2004 to June 30, 2005
Senior Vice President and Chief of Utility Operations, Pacific Gas and Electric CompanyNovember 1, 2003 to August 1, 2004
Senior Vice President, PG&E CorporationJanuary 1, 1999 to October 31, 2003
President, PG&E National Energy Group,Japan Telecom Holdings Co., Inc. November 15, 2002December 21, 2001 to July 8, 2003
President and Chief Operating Officer, PG&E Gas Transmission CorporationAugust 27, 2002 to July 8, 2003
President and Chief Operating Officer, Gas Transmission, PG&E National Energy Group, Inc.August 9, 2002 to November 14, 2002
President and Chief Operating Officer, West Region, PG&E National Energy Group, Inc.July 1, 2000 to August 8, 2002
President and Chief Operating Officer, PG&E Gas Transmission CorporationNovember 23, 1998 to September 10, 2002January 31, 2004
     
R.Hyun ParkSenior Vice President and General CounselNovember 13, 2006 to present
Vice President, General Counsel, and Secretary, Allegheny Energy, Inc. (an investor-owned utility company headquartered in Pennsylvania)April 5, 2005 to October 17, 2006
Senior Vice President, General Counsel, and Secretary, Sithe Energies, Inc.March 2000 to February 2005
Greg S. PruettSenior Vice President, Corporate RelationsNovember 1, 2007 to present
Vice President, Corporate RelationsMarch 1, 2007 to October 31, 2007
Vice President, Communications and Marketing, American Gas AssociationApril 10, 2006 to February 23, 2007
Chief Public Affairs Officer, Bechtel National, Inc.June 12, 2004 to September 12, 2005
Vice President, Corporate Communications, PG&E CorporationJanuary 1, 1998 to September 12, 2003
Rand L. Rosenberg Senior Vice President, Corporate Strategy and Development November 1, 2005 to present
  Executive Vice President and Chief Financial Officer, Infospace, Inc. 
September 2000 to January 20, 2001
Chief Financial Officer and Senior Vice President, Finance and Corporate Development, Infospace, Inc.June 2000 to September 2000
     
B.John R. WorthingtonSimon Senior Vice President, and General CounselHuman Resources June 1, 1997April 16, 2007 to present
Senior Vice President, Human Resources, Pacific Gas and Electric CompanyApril 16, 2007 to present
Executive Vice President, Global Human Capital, TeleTech Holdings, Inc.March 21, 2006 to April 13,2007
Senior Vice President, Human Capital, TeleTech Holdings, Inc.July 31, 2001 to March 20, 2006

37


The names, ages and positions of the Utility's "executive“executive officers," as defined by Rule 3b-7 of the General Rules and Regulations under the Exchange Act at February 1, 2006,20, 2008, are as follows:


Name
 
Age
 
Position
P.A.Peter A. Darbee 5355 Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation
William T. B. KingMorrow 4448 President and Chief Executive Officer
T.Thomas E. Bottorff 5254 Senior Vice President, Regulatory Relations
J. D. ButlerHelen Burt 5051 Senior Vice President Energy Deliveryand Chief Customer Officer
L.H. EverettChristopher P. Johns 5547 Senior Vice President Communications and Public Affairs, PG&E CorporationTreasurer
R.M. JacksonJohn S. Keenan 4859 Senior Vice President Human Resourcesand Chief Operating Officer
C. P. JohnsPatricia M. Lawicki 4547 Senior Vice President and Chief FinancialInformation Officer and Treasurer
J. S. KeenanNancy E. McFadden 5749 Senior Vice President, Generation and Chief Nuclear OfficerPublic Affairs
S. M. RamsayHyun Park 47Vice President, Asset Management and Electric Transmission
F Wan44Vice President, Energy Procurement
B. R. Worthington5646 Senior Vice President and General Counsel, PG&E Corporation
Greg S. Pruett50Senior Vice President, Corporate Relations, PG&E Corporation
Edward A. Salas51Senior Vice President, Engineering and Operations
John R. Simon43Senior Vice President, Human Resources
Geisha J. Williams46Senior Vice President, Energy Delivery
G. Robert Powell44Vice President, Chief Financial Officer, and Controller
Fong Wan46Vice President, Energy Procurement

All officers of the Utility serve at the pleasure of the Board of Directors. During the past five years through February 1, 2006,20,

36


2008, the executive officers of the Utility had the following business experience. Except as otherwise noted, all positions have been held at Pacific Gas and Electric Company.


Name
 
Position
 
Period Held Office
     
P.Peter A. DarbeeChairman of the Board, Chief Executive Officer, and President,   PG&E CorporationSeptember 19, 2007 to present
Chairman of the Board and Chief Executive Officer, PG&E CorporationJanuary 1, 2006 to September 19, 2007
 Chairman of the Board, Pacific Gas and Electric Company January 1, 2006 to presentMay 31, 2007
  Chairman of the Board, Chief Executive Officer, and President,   PG&E Corporation January 1, 2006 to presentJune 30, 2006
  President and Chief Executive Officer, PG&E Corporation January 1, 2005 to December 31, 2005
  Senior Vice President and Chief Financial Officer, PG&E   Corporation July 9, 2001 to December 31, 2004
  Senior Vice President, Chief Financial Officer, and Treasurer, PG&E Corporation September 20, 1999
William T. Morrow President and Chief Executive OfficerJuly 1, 2007 to present
President and Chief Operating OfficerAugust 1, 2006 June 30, 2007
Chief Executive Officer, Europe, Vodafone Group PLC (a global   mobile telecommunications company)May 1, 2006 to July 8,31, 2006
President, Vodafone KK, JapanApril 1, 2005 to April 30, 2006
Chief Executive Officer, Vodafone UK, Ltd.February 1, 2004 to March 31, 2005
President, Japan Telecom Holdings Co., Inc.December 21, 2001 to January 31, 2004
     
T. B. KingPresident and Chief Executive OfficerJanuary 1, 2006 to present
Senior Vice President, PG&E CorporationJanuary 1, 2006 to present
Executive Vice President and Chief Operating OfficerJuly 1, 2005 to December 31, 2005
Executive Vice President and Chief of Utility OperationsAugust 2, 2004 to June 30, 2005
Senior Vice President and Chief of Utility OperationsNovember 1, 2003 to August 1, 2004
Senior Vice President, PG&E CorporationJanuary 1, 1999 to October 31, 2003
President, PG&E National Energy Group, Inc.November 15, 2002 to July 8, 2003
President and Chief Operating Officer, PG&E Gas Transmission CorporationAugust 27, 2002 to July 8, 2003
President and Chief Operating Officer, Gas Transmission, PG&E National Energy Group, Inc.August 9, 2002 to November 14, 2002
President and Chief Operating Officer, West Region, PG&E National Energy Group, Inc.July 1, 2000 to August 8, 2002
President and Chief Operating Officer, PG&E Gas Transmission CorporationNovember 23, 1998 to September 10, 2002
T.Thomas E. Bottorff Senior Vice President, Regulatory Relations October 14, 2005 to present
  Senior Vice President, Customer Service and Revenue March 1, 2004 to October 13, 2005
  Vice President, Customer Service June 1, 1999 to February 29, 2004
     
J. D. ButlerSenior Vice President, Energy DeliveryJanuary 9, 2006 to present
Senior Vice President, Transmission and DistributionMarch 1, 2004 to January 8, 2006
Vice President, Operations, Maintenance and ConstructionJune 12, 2000 to February 29, 2004
L. H. EverettSenior Vice President, Communications and Public Affairs, PG&E CorporationJanuary 9, 2006 to present
Helen Burt Senior Vice President and Assistant to the Chief ExecutiveCustomer Officer PG&E CorporationJanuary 1, 2005 to January 8, 2006
Senior Vice President and Assistant to the Chairman, PG&E CorporationAugust 2, 2004 to December 31, 2004
Vice President and Assistant to the Chairman, PG&E CorporationJune 1, 2001 to August 1, 2004
Vice President, Corporate Secretary, and Assistant to the Chairman, PG&E CorporationMay 1, 2001 to May 31, 2001
Vice President and Corporate Secretary, PG&E CorporationJuly 1, 1997 to April 30, 2001
Vice President and Corporate SecretaryNovember 1, 1996 to May 31, 2001
R. M. JacksonSenior Vice President, Human Resources, Pacific Gas and Electric Company and PG&E CorporationAugust 2, 2004 to present
Vice President, Human Resources, PG&E CorporationJune 1, 2004 to August 1, 2004
Vice President, Human ResourcesJune 1, 1999 to August 1, 2004
C. P. JohnsSenior Vice President, Chief Financial Officer and TreasurerOctober 1, 2005 to present
Senior Vice President, Chief Financial Officer and Treasurer, PG&E CorporationOctober 4, 2005 to present
Senior Vice President, Chief Financial Officer and Controller, PG&E CorporationJanuary 1, 2005 to October 3, 2005
Senior Vice President and Controller, PG&E CorporationSeptember 19, 2001 to December 31, 2004
Vice President and Controller, PG&E CorporationJuly 1, 1997 to September 18, 2001
J. S. KeenanSenior Vice President, Generation and Chief Nuclear OfficerDecember 19, 2005 to present
Vice President, Fossil Generation, Progress EnergyNovember 10, 2003 to December 18, 2005
Vice President, Brunswick Nuclear Plant, Progress EnergyMay 1, 1998 to November 9, 2003
S. M. RamsayVice President, Asset Management and Electric Transmission January 9, 2006 to present
  Vice President, Electric Transmission July 1, 2005 to January 8, 2006
  Vice President, Distribution Asset Management, American   Electric Power February 1, 2004 to June 30, 2005
  Senior Vice President, Power and Gas, UMS Group, Inc. October 1, 2001 to January 31, 2004
  Managing Director, UK Operations, UMS Group, Inc.
Christopher P. JohnsSenior Vice President and TreasurerJune 1, 2007 to present
Senior Vice President, Chief Financial Officer, and Treasurer, PG&E CorporationOctober 4, 2005 to present
Senior Vice President, Chief Financial Officer, and Treasurer,October 1, 2005 to May 31, 2007
Senior Vice President, Chief Financial Officer, and Controller, PG&E Corporation January 2,1, 2005 to October 3, 2005
Senior Vice President and Controller, PG&E CorporationSeptember 19, 2001 to September 30, 2001December 31, 2004
     
F.Patricia M. LawickiSenior Vice President and Chief Information OfficerNovember 1, 2007 to present
Vice President and Chief Information OfficerJanuary 12, 2005 to October 31, 2007
Vice President, Chief Information Officer, NiSource, Inc.April 23, 2003 to January 7, 2005
John S. KeenanSenior Vice President and Chief Operating OfficerJanuary 1, 2008 to present
Senior Vice President, Generation and Chief Nuclear OfficerDecember 19, 2005 to December 31, 2007
Vice President, Fossil Generation, Progress EnergyNovember 10, 2003 to December 18, 2005
Vice President, Brunswick Nuclear Plant, Progress EnergyMay 1, 1998 to November 9, 2003
Nancy E. McFaddenSenior Vice President, Public AffairsJune 20, 2007 to present
Senior Vice President, Public Affairs, PG&E CorporationMarch 1, 2007 to present
Vice President, Governmental RelationsSeptember 26, 2005 to February 28, 2007
Chairperson, California Medical Assistance CommissionNovember 13, 2003 to November 30, 2005
Senior Advisor and Deputy Chief of Staff, Office of Governor Gray DavisMay 2001 to November 2003
37

Hyun ParkSenior Vice President and General Counsel, PG&E CorporationNovember 13, 2006 to present
Vice President, General Counsel, and Secretary, Allegheny Energy, Inc. (an investor-owned utility company headquartered in Pennsylvania)April 5, 2005 to October 17, 2006
Senior Vice President, General Counsel, and Secretary, Sithe Energies, Inc.March 2000 to February 2005
Greg S. PruettSenior Vice President, Corporate Relations, PG&E CorporationNovember 1, 2007 to present
Vice President, Corporate Relations, PG&E CorporationMarch 1, 2007 to October 31, 2007
Vice President, Communications and Marketing, American Gas AssociationApril 10, 2006 to February 23, 2007
Chief Public Affairs Officer, Bechtel National, Inc.June 12, 2004 to September 12, 2005
Vice President, Corporate Communications, PG&E CorporationJanuary 1, 1998 to September 12, 2003
Edward A. SalasSenior Vice President, Engineering and OperationsApril 11, 2007 to present
Staff Vice President, Network Planning, Verizon Wireless, Basking Ridge, N.J.
Contractor, Verizon Wireless, Local Number Portability Implementation
May 2004 to April 2007
May 2003  to April 2004
John R. SimonSenior Vice President, Human ResourcesApril 16, 2007 to present
Senior Vice President, Human Resources, PG&E CorporationApril 16, 2007 to present
Executive Vice President, Global Human Capital, TeleTechMarch 21, 2006 to April 13, 2007
Senior Vice President, Human Capital, TeleTech Holdings, Inc.July 13, 2001 to March 20, 2006
Geisha J. WilliamsSenior Vice President, Energy DeliveryDecember 1, 2007 to present
Vice President, Power Systems, Distribution, Florida Power and Light CompanyJuly 2003 to July 2007
Vice President, Distribution Operations, Florida Power and Light CompanyFebruary 2002 to July 2003
G. Robert PowellVice President, Chief Financial Officer, and ControllerJune 1, 2007 to present
Vice President and ControllerDecember 21, 2005 to May 31, 2007
Controller (Interim)November 9, 2005 to December 20, 2005
Vice President and Controller, PG&E CorporationOctober 4, 2005 to present
Partner, PricewaterhouseCoopers LLPJuly  2002 to September 2005
Fong Wan Vice President, Energy Procurement January 9, 2006 to present
  Vice President, Power Contracts and Electric Resource   Development May 1, 2004 to January 8, 2006
  Vice President, Risk Initiatives, PG&E Corporation Support   Services, Inc. November 1, 2000 to April 30, 2004
B. R. WorthingtonSenior Vice President and General Counsel, PG&E CorporationJune 1, 1997 to present


38




(a)As of February 1, 2006,19, 2008, there were 98,08388,752 holders of record of PG&E Corporation common stock.  PG&E Corporation common stock is listed principally on the New York Stock Exchange. PG&E Corporation common stock also is listed on the Pacific Exchange and the Swiss stock exchanges.  The high and low sales prices of PG&E Corporation common stock for each quarter of the two most recent fiscal years are set forth under the heading "Quarterly“Quarterly Consolidated Financial Data (Unaudited)" in the 20052007 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.  The discussion of dividends with respect to PG&E Corporation's common stock is hereby incorporated by reference from "Management'sset forth under the heading “Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Financial Resources—Dividends"Dividends” in the 2007 Annual Report, which information is hereby incorporated by reference and filed as part of the 2005 Annual Report.Exhibit 13 to this report.

38



As previously disclosed, in connection with its entry into certain credit agreements, in June 2002 and October 2002, PG&E Corporation issued warrants to purchase 5,066,931did not repurchase any shares of its common stock of PG&E Corporation at an exercise price of $0.01 per share. On November 17, 2005 and December 29, 2005, warrant holders exercised, on a net exercise basis, warrants to purchase, in the aggregate, 73,559 shares, and received, in the aggregate, 73,538 shares of PG&E Corporation common stock in reliance on the exemption from the registration requirements of the Securities Act of 1933 provided by Section 4(2) of the Act.

Pacific Gas and Electric Company did not make any sales of unregistered equity securities during the quarter ended December 31, 2005.

(b)Issuer Purchases of Equity Securities

PG&E Corporation common stock:

Period
 
Total Number of Shares Purchased
 
Average Price Paid Per Share
 
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(1)(2)(3)
 
Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs
 
              
October 1 through October 31, 2005  - $-  - $- 
November  1 through November 30, 2005  31,650,300 $34.75  31,650,300 $500,000,000 
December 1 through December  31, 2005  - $-  - $- 
Total
  31,650,300 $34.75  31,650,300 $500,000,000 


(1)
On September 15, 2004, the PG&E Corporation Board of Directors authorized PG&E Corporation and its subsidiaries to repurchase shares of PG&E Corporation's common stock with an aggregate purchase price not to exceed PG&E Corporation's net cash proceeds from sales of PG&E Corporation's common stock upon exercise of options granted under PG&E Corporation's Stock Option Plan. The program was publicly announced in a Current Report on Form 8-K filed by PG&E Corporation on October 14, 2004. The program expired on December 31, 2005.
(2) 
On December 15, 2004, the PG&E Corporation Board of Directors authorized the repurchase of up to $975 million in PG&E Corporation common stock. The program was publicly announced in a Current Report on Form 8-K filed by PG&E Corporation on December 16, 2004. On February 16, 2005, the Board of Directors increased the repurchase authorization to $1.05 billion, which was announced in PG&E Corporation’s Annual Report on Form 10-K for the year ended December 31, 2004. PG&E Corporation used all of this authorization to enter into an accelerated share repurchase arrangement on March 4, 2005 with Goldman, Sachs & Co., Inc., or GS&Co, to repurchase 29,489,400 shares at an initial price of $35.60 per share. Under the share forward component of the March 2005 arrangement, certain additional payments were required by both PG&E Corporation and GS&Co upon termination. Most significantly, PG&E Corporation was to receive from, or be required to pay to, GS&Co a price adjustment on the repurchased shares based on the difference between the amount it paid and the daily volume weighted average price, or VWAP, of PG&E Corporation common stock over the approximately six-month intended arrangement period. PG&E Corporation made additional payments to GS&Co of $78,000 on June 30, 2005 and $22 million on September 12, 2005. The amount of the price adjustment based on the VWAP of PG&E Corporation common stock over the term of the arrangement increased the average purchase price per share to $36.19.
(3)
On October 19, 2005, the PG&E Corporation Board of Directors authorized the repurchase of up to $1.6 billion in shares of PG&E Corporation's common stock, from time to time, but no later than December 31, 2006. The program was publicly announced in a Current Report on Form 8-K filed by PG&E Corporation on October 21, 2005. As described in a Current Report on Form 8-K filed by PG&E Corporation on November 18, 2005, PG&E Corporation entered into an accelerated share repurchase arrangement with GS&Co on November 16, 2005 under which PG&E Corporation repurchased 31,650,300 shares of its outstanding common stock at an initial price of $34.75 per share and an aggregate price of approximately $1.1 billion. As with the March 2005arrangement, PG&E Corporation may receive from, or be required to pay, GS&Co various payments, including a price adjustment based on the daily VWAP of PG&E Corporation common stock over a period of approximately seven months.

During the fourth quarter of 2005, Pacific Gas and Electric Company2007.  The Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.outstanding during of 2007.

Item 6. Selected Financial Data

A summary of selected financial information, for each of PG&E Corporation and Pacific Gas and Electric Company for each of the last five fiscal years, is set forth under the heading "Selected“Selected Financial Data"Data” in the 20052007 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.


A discussion of PG&E Corporation's and Pacific Gas and Electric Company's consolidated financial condition and results of operations and financial condition is set forth under the heading "Management's“Management's Discussion and Analysis of Financial Condition and Results of Operations"Operations” in the 20052007 Annual Report, which discussion is hereby incorporated by reference and filed as part of Exhibit 13 to this report.


Information responding to Item 7A appears in the 20052007 Annual Report under the heading "Management's“Management's Discussion and Analysis of Financial Condition and Results of Operations—Risk Management Activities," and under Notes 12 and 12 of the "Notes“Notes to the Consolidated Financial Statements"Statements” of the 20052007 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.


Information responding to Item 8 appears in the 20052007 Annual Report under the following headings for PG&E Corporation: "Consolidated“Consolidated Statements of Income," "Consolidated” “Consolidated Balance Sheets," "Consolidated” “Consolidated Statements of Cash Flows," and "Consolidated“Consolidated Statements of Shareholders' Equity;" under the following headings for Pacific Gas and Electric Company: "Consolidated“Consolidated Statements of Income," "Consolidated” “Consolidated Balance Sheets," "Consolidated” “Consolidated Statements of Cash Flows," and "Consolidated“Consolidated Statements of Shareholders' Equity;" and under the following headings for PG&E Corporation and Pacific Gas and Electric Company jointly: "Notes“Notes to the Consolidated Financial Statements," "Quarterly” “Quarterly Consolidated Financial Data (Unaudited)," and "Report“Report of Independent Registered Public Accounting Firm," which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.


Not applicable.

Not applicable.

39



Based on an evaluation of PG&E Corporation's and the Utility's disclosure controls and procedures as of December 31, 2005,2007, PG&E Corporation's and the Utility's respective principal executive officers and principal financial officers have concluded that such controls and procedures are effective to ensure that information required to be disclosed by PG&E Corporation and the Utility in reports that the companies file or submit under the Securities and Exchange Act of 1934 (“1934 Act”) is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange CommissionSEC rules and forms.  In addition, PG&E Corporation's and the Utility's respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective in ensuring that information required to be disclosed by PG&E Corporation and the Utility in the reports that PG&E Corporation and the Utility file or submit under the 1934 Act is accumulated and communicated to PG&E Corporation’s and the Utility’s management, including PG&E Corporation's and the Utility's respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

There were no changes in internal control over financial reporting that occurred during the quarter ended December 31, 20052007 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation's or the Utility's internal control over financial reporting.

Management of PG&E Corporation and the Utility have prepared an annual report on internal control over financial reporting.  Management's report, together with the report of the independent registered public accounting firm, appears in their joint 2005the 2007 Annual Report to Shareholders under the heading "Management's“Management's Report on Internal Control Over Financial Reporting"Reporting” and "Report“Report of Independent Registered Public Accounting Firm," which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.

 
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report.

Item 9B. Other Information


In response to a shareholder proposal that was approved at PG&E Corporation’s 2005 annual meeting of shareholders onOn February 15, 2006,20, 2008, the BoardBoards of Directors of PG&E Corporation orand the Utility amended the respective company’s Bylaws to decrease the authorized number of directors, effective May 14, 2008, to eliminate the vacancy on the Board adoptedof Directors that will result from the retirement of David A. Coulter as a Golden Parachute Restriction Policydirector of each company following the companies’ joint annual meeting of shareholders.  Under PG&E Corporation’s Bylaws, the authorized number of directors may not be less than 7 or more than 13, but within that became effective on February 15, 2006, subjectrange the Board of Directors may set the exact number of directors by an amendment to existing contractual obligations. This policy requiresthe Bylaws.  Under the Utility’s Bylaws, the authorized number of directors may not be less than 9 or more than 17, but within that range the holdersBoard of a majorityDirectors may set the exact number of directors by an amendment to the Bylaws.  Effective May 14, 2008, PG&E Corporation’s authorized number of directors will decrease from 10 to 9 and the Utility’s authorized number of directors will decrease from 11 to 10.  The text of the shares representedamendment to PG&E Corporation’s Bylaws is attached to this report as Exhibit 3.4 and voting approve executive severance payments providedthe text of the amendment to the Utility’s Bylaws is attached to this report as Exhibit 3.7.
Under PG&E Corporation’s and the Utility’s Corporate Governance Guidelines, at least 75% of its Board is required to be composed of independent directors, generally defined as directors who (1) are neither current nor former officers or employees of, nor consultants to, PG&E Corporation, the Utility, or their consolidated subsidiaries, (2) are neither current nor former officers or employees of any other corporation on whose board of directors any officer of the Utility serves as a member, and (3) otherwise meet the definition of “independence” set forth in connection with a change in controlthe stock exchange rules applicable to PG&E Corporation and the Utility.  The composition of PG&E Corporation to the extent that those payments exceed 2.99 times the sum of a covered officer’s base salary and target annual bonus. The Golden Parachute Restriction Policy applies generally to the value of cash, special benefits, or perquisites that would be due to the executive following both a change in controlCorporation’s and the termination or constructive terminationUtility’s Board of an officer covered byDirectors currently meets the Corporate Governance Guidelines and will continue to do so after May 14, 2008.
2008 Officer Compensation

On February 20, 2008, the Compensation Committee of the PG&E Corporation Officer Severance Policy. It does not apply toBoard of Directors (“Committee”) approved the value of benefits that would be triggered by a change in control without severance, or to the value of benefits that would be triggered by severance in the absence of a change in control. Under the Golden Parachute Restriction Policy, the Board has delegated to the Nominating, Compensation and Governance Committeespecific performance targets for each component of the Board, or the Committee, full authority to make determinations regarding the interpretation of the provisions of the Golden Parachute Restriction Policy in its sole discretion.
On February 15, 2006, the Board also adopted amendments to the definition of the term “change in control” that appears in the PG&E Corporation Officer Severance Policy, or the Officer Severance Policy, and the PG&E Corporation 2006 Long-Term Incentive Plan, or the 2006 LTIP. The definition of the term “change in control” has been amended so that a “change in control” will occur upon the consummation of a consolidation or merger of PG&E Corporation, other than a merger or consolidation that would result in the voting securities of PG&E Corporation outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent of such surviving entity) at least 70 percent of the combined voting power of PG&E Corporation, such surviving entity, or the parent of such surviving entity outstanding immediately after the merger or consolidation. Under the prior definition, a “change in control” would have occurred upon shareholder approval of such a transaction. Certain other events, including the turnover of two-thirds of the incumbent board members without incumbent board member approval within two years, the acquisition of a 20 percent voting stake in PG&E Corporation, and shareholder approval of certain asset sales or a plan of liquidation or dissolution, will continue to constitute a change in control.
Payments granted pursuant to the Officer Severance Policy became subject to the Golden Parachute Restriction Policy and the new definition of “change in control” effective as of February 15, 2006, subject to existing contractual obligations. The Officer Severance Policy provides that any changes which would reduce the aggregate level of benefits provided under the policy will become effective three years after the covered officers receive notice of those changes. The Golden Parachute Restriction Policy and the amendments to the Officer Severance Policy would reduce the aggregate level of benefits, and therefore will become effective three years after the covered officers receive notice of those changes. PG&E Corporation intends to provide such notice shortly.

40


The Officer Severance Policy has been further amended to provide that: (i) the term “Participating Employers” is defined to more clearly identify which entities may provide severance benefits to their officers pursuant to the Officer Severance Policy and (ii) upon severance related to a change in control, benefits conditioned upon continued future employment will accelerate in full. These amendments became effective on February 15, 2006.
The 2006 LTIP also has been amended such that a change in control by itself will not generally result in the accelerated vesting or settling of grants under the 2006 LTIP. Accelerated vesting or settling will occur upon a change in control only if (1) the successor or surviving company does not assume or continue the grants in a manner that preserves the value of the grants or (2) the grant holder is terminated within a set amount of time before or after the change in control. These amendments will take effect starting with grants made in 2007. The 2006 LTIP administrative provisions were amended to clarify that benefits that may be payable upon termination of employment following the sale or other divestiture of a subsidiary will be identical to those provided upon severance. These amendments became effective February 15, 2006.
In addition, the Committee amended the Executive Stock Ownership Program Administrative Guidelines, or the Guidelines, to replace the reference to the current PG&E Corporation Long-Term Incentive Program, which expired on December 31, 2005, with the new 2006 LTIP, which became effective on January 1, 2006. The Guidelines also were amended to be consistent with the amended terms of the 2006 LTIP as described above. These changes became effective February 15, 2006.
As previously disclosed, the Committee has approved the structure of the 20062008 Short-Term Incentive Plan or(“STIP”).  The Committee previously approved the STIP under which officersstructure and the weighting of each component in December 2007.  Officers of PG&E Corporation and the Utility are provided an opportunityeligible to receive cash incentives under the STIP based on the extent to which the adopted 2008 performance targets are met.  The Committee will continue to retain full discretion as to the determination of final officer STIP payments.

The 2008 STIP structure for officers focuses the annual incentive cash payments. For these officers, corporateopportunity on returns to shareholders by emphasizing financial objectives such as earnings from operations.  The structure also recognizes the equal importance of improving reliability and customer satisfaction, and employee safety and engagement.  Corporate financial performance, as measured by corporate earnings from operations, will account for 70 percent40% of the award and Utility operational performance, as measured by 11 equally weighted financial, operating, and service measures, will account for 30 percentincentive, 20% of the award. At its meetingincentive will be based on February 15, 2006,the Utility’s success in improving reliability, 20% of the incentive will be based on the Utility’s success in improving customer satisfaction, 10% will be based on the results of an employee opinion survey, and the remaining 10% will be based on achieving safety standards.  For 2008, the Committee approved the specific performance scalehas adopted a mechanism stating that will be used to determine the extent to which theif corporate financial objective, as measured byperformance does not exceed 98% of the budgeted earnings from operations, has been met. The Committee used the same methodologyaggregate operational metric contribution to establish the performance scale for the corporate financial performance portion2008 STIP pool will be capped at 100% of the 2006operational component target award, or 60% of the total target STIP as was used for the 2005 STIP. award pool.

The corporate financial performance measure is based on PG&E Corporation's budgeted earnings from operations that were previously approved by the Board of Directors, consistent with the basis for reporting and guidance to the financial community.  As with previous earnings performance scales, unbudgeted items impacting comparability such as changes in accounting methods, workforce restructuring, and one-time occurrences will be excluded.
The Committee also approved the following 20062008 performance targets for each of the 11 equally weighted financial, operating, and servicefour other measures that will be used to determine whetherset forth in the portiontable below.  The 2007 performance results for each of these measures are included for comparative purposes.

2008 STIP Operational Performance Targets(1)

Measure Relative Weight 2007 Results 2008 Target
Customer Satisfaction and Brand Health Index (Residential & Business)(2)
 
20%
 
76.00
 
77.00
Reliable Energy Delivery Index(3)
 
20%
 
1.17
 
1.0
Employee Survey (Premier) Index(4)
 
10%
 
64.3%
 
66.0%
Occupational Safety and Health Administration (OSHA) Recordable Injury Rate(5)
 
10%
 
4.097
 
3.483


40


1.      As explained above, 40% of the STIP award will be based on the achievement of operational excellence and improved customer service has been met. The 2005 performance results for each measure are included for reference:

41


2006 STIP Performance Targetscorporate earnings from operations targets.
 

  
Measure
 
2005 Results
 
2006 Target
1. 
Customer Satisfaction (Residential & Business) 1
 94.0 96.0
2. Timely bills (% issued within 35 days) 99.38% 99.51%
3. Estimate of Outage Restoration Accuracy 47% 50%
4. 
System Average Interruption Duration Index (SAIDI) 2
 178.7 166
5. 
System Average Interruption Frequency Index (SAIFI) 2
 1.344 1.31
6. 
Energy Availability (Generation and Procurement) 3
 
-- 3
 
-- 3
7. 
Telephone Service Level 4
 75/20 76/20
8. Expense Per Customer $278 
$283 5
9. 
Diablo Canyon composite performance index6
 98.2 98.2
10. Employee survey (Premier) index 64.0% 68.0%
11. 
Lost workday case rate7
 1.04 0.878

1.This measure is based on the JD Power Residential Survey and the JD Power Business Survey combined with equal weighting. The 2006 target assumes the 2006 quartile ranges will be the same as the 2005 quartile ranges. The 2006 target will be adjusted to reflect the revised quartile ranges expected to be available in July 2006.

2.“SAIDI,” or system average interruption duration index, refers to the average outage time over a one-year period. “SAIFI,” or system average interruption frequency index, refers to the average number of sustained outages over a one-year period.

3.The Energy Availability measure combines two separate reliability measures, each equally weighted. One assesses whether Utility-owned generation is available as planned and the other assesses whether the Utility has obtained adequate electric supplies for its customers, as measured by California Independent System Operator alerts. This is a new measure in 2006.

4.This refers to the percentage of customer calls to the contact centers that are answered within a specified number of seconds; 75/20 means that 75% of calls are answered within 20 seconds.

5. The 2006 target expense per customer amount is based on the approved budget for 2006. The increase of 1.7 percent over the 2005 recorded amount of $278 is comprised of a 3.3 percent increase in expenses, offset by a 1.5 percent increase in customers.

6.The composite performance index provides a quantitative indication of plant performance in the areas of nuclear plant safety and reliability and plant efficiency.
2.The Customer Satisfaction and Brand Health Index is the result of a quarterly survey performed by an independent research firm, Research International, and is a combination of a customer satisfaction score, which has a 75% weighting, as well as a brand favorability score (measuring the relative strength of the PG&E brand against a select group of companies), which has a 25% weighting.  The customer satisfaction score will measure overall satisfaction with the Utility’s operational performance in delivering its services.  The brand favorability score will measure residential, small business and medium business customer perceptions.  This index replaces the index used in the 2006 and 2007 STIP structures based on residential and business customer satisfaction indices as reported the J.D. Power Residential Customer Satisfaction Survey and the J.D. Power Business Customer Satisfaction Survey.
 
7.This measures the number of non-fatal injury and illness cases that (1) satisfy certain federal requirements for recordability, (2) occur in the current year, and (3) result in at least one day away from work. The rate measures how frequently new lost workday cases occur for every 200,000 hours worked, or for approximately every 100 employees.
3.The Reliable Energy Delivery Index is a composite index score that measures key drivers of reliability, including outage frequency and duration (System Average Interruption Frequency Index (SAIFI), Customer Average Interruption Duration Index (CAIDI)), Execution of Electric-Based Work Units, and Gas Transmission and Distribution Integrity.  This index replaces the Business Transformation Index used in the 2007 STIP structure.
 
4.The Premier Survey is the primary tool used to measure employee engagement at PG&E Corporation and the Utility.  The employee index is designed around 15 key drivers of employee engagement and organizational health.  The average overall employee survey index score provides a comprehensive metric that is derived by adding the percent of favorable responses from all 40 core survey items (all of which fall into one of 15 broader topical areas), and then dividing the total sum by 40.
5.An “OSHA Recordable” is an occupational (job-related) injury or illness that requires medical treatment beyond first aid, or results in work restrictions, death or loss of consciousness. The “OSHA Recordable Rate” is the number of OSHA Recordables for every 200,000 hours worked, or for approximately 100 employees.  This metric measures the percentage reduction in the Corporation’s OSHA Recordable rate from the prior year and is used to monitor the effectiveness of the Corporation’s safety programs, which are intended to significantly reduce the number and degree of employee injuries and illnesses.

 
The Chief Executive OfficerCash awards under the STIP may range from 30 percent to 100 percent of base salary depending on officer level, with a maximum payout of 200 percent of base salary, as determined by the Committee.

Non-Employee Director Compensation

Also on February 20, 2008, the Boards of Directors of PG&E Corporation hasand the discretionUtility amended each company’s resolution regarding non-employee director compensation to recommendclarify and restate the application of the compensation program for non-employee directors in light of (1) the division of the PG&E Corporation Nominating, Compensation, and Governance Committee into two separate committees (the Nominating and Governance Committee and the Compensation Committee), and (2) recent changes to the Committee an additional performance ratingprocess for an individual officer. This rating will be determinedselecting the lead director.  The amended resolutions do not change the compensation levels previously authorized by such officer’s effortsthe Boards of Directors on December 20, 2006.  The amended resolutions are effective as of January 1, 2008 and are attached to manage their organization’s respective financial budget. This additional performance rating can modify (up or down) an individual officer’s final STIP award by no more than 15 percent. The Committee will continue to retain full discretionthis report as to the determination of final officer STIP awards.
exhibits.



42


PART III



Information regarding executive officers of PG&E Corporation and Pacific Gas and Electric Company is included above in a separate item captioned "Executive“Executive Officers of the Registrants"Registrants” at the end of Part I of this report.  Other information responding to Item 10 is included under the heading "Item“Item No. 1: Election of Directors of PG&E Corporation and Pacific Gas and Electric Company"Company” and under the heading "Section“Section 16(a) Beneficial Ownership Reporting Compliance"Compliance” in the Joint Proxy Statement relating to the 20062008 Annual Meetings of Shareholders, which information is hereby incorporated by reference.

Website Availability of Code of Ethics, Corporate Governance and Other Documents

The following documents are available both on PG&E Corporation's website www.pgecorp.comwww.pgecorp.com, and Pacific Gas and Electric Company's website, www.pge.comwww.pge.com: (1) the codes of conduct and ethics adopted by PG&E Corporation and Pacific Gas and Electric Company applicable to their respective directors and employees, including their respective Chief Executive Officers, Chief Financial Officers, Controllers and other executive officers, (2) PG&E Corporation's and Pacific Gas and Electric Company's corporate governance guidelines, and (3) key Board Committee charters, including charters for the companies' Audit Committees and the PG&E Corporation Nominating Compensation, and Governance Committee and Compensation Committee.  Shareholders also may obtain print copies of these documents by submitting a written request to Linda Y.H. Cheng, Vice President, Corporate Governance and Corporate Secretary of PG&E Corporation and Pacific Gas and Electric Company, One Market, Spear Tower, Suite 2400, San Francisco, California 94105.

If any amendments are made to, or any waivers are granted with respect to, provisions of the codes of conduct and ethics adopted by PG&E Corporation and Pacific Gas and Electric Company that apply to their respective Chief Executive Officers, Chief Financial Officers or Controllers, the company whose code is so affected will disclose the nature of such amendment or waiver on its respective website and any waivers to the code will be disclosed in a Current Report on Form 8-K filed within 4 business days of the waiver.



41


Procedures for Shareholder Recommendations of Nominees to the Boards of Directors

During 2007 there were no material changes to the procedures described in PG&E Corporation’s and the Utility’s Joint Proxy Statement relating to the 2007 Annual Meetings of Shareholders by which security holders may recommend nominees to PG&E Corporation’s or the Utility’s Boards of Directors.

Audit Committees and Audit Committee Financial Expert

Information regarding the Audit Committees of PG&E Corporation and the Utility and the “audit committee financial expert” as defined by the SEC is included under the heading “Information Regarding the Boards of Directors of PG&E Corporation and Pacific Gas and Electric CompanyBoard CommitteesAudit Committees” in the Joint Proxy Statement relating to the 2008 Annual Meetings of Shareholders, which information is hereby incorporated by reference.


Information responding to Item 11, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under the heading "Compensation of Directors" and under
the headings "Summary“Compensation Discussion and Analysis,” “Compensation Committee Report,”  “Summary Compensation Table" "Option/SAR Grants in 2005," "Aggregated Option/SAR Exercises in 2005 and Year-End Option/SAR Values," "Long-Term Incentive Program— - 2007,” “Grants of Plan-based Awards in 2005," "Retirement2007,” “Outstanding Equity Awards at Fiscal Year End - 2007,” “Option Exercises and Stock Vested During 2007,” “Pension Benefits,"” “Non-Qualified Deferred Compensation,” “Compensation of Directors,” and "Employment Contracts,“Potential Payments Upon Resignation, Retirement, Termination, of Employment, and Change Inin Control, Provisions"Death, or Disability” in the Joint Proxy Statement relating to the 20062008 Annual Meetings of Shareholders, which information is hereby incorporated by reference.


Information responding to Item 12, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under the heading "Security“Security Ownership of Management"Management” and under the heading "Principal Shareholders"“Principal Shareholders” in the Joint Proxy Statement relating to the 20062008 Annual Meetings of Shareholders, which information is hereby incorporated by reference.


43


Equity Compensation Plan Information

The following table provides information as of December 31, 20052007 concerning shares of PG&E Corporation common stock authorized for issuance under PG&E Corporation's existing equity compensation plans.
Plan Category
(a)
Number of Securities to
be Issued Upon Exercise
of Outstanding Options,
Warrants and Rights
(b)
Weighted Average
Exercise Price of
Outstanding Options,
Warrants and Rights
(c)
Number of Securities
Remaining Available for
Future Issuance Under
Equity Compensation Plans
(Excluding Securities
Reflected in Column(a))
Equity compensation plans approved by shareholders
3,970,661(1)
$24.00
10,847,999(2)
Equity compensation plans not approved by shareholders$—
Total equity compensation plans
3,970,661(1)
$24.00
10,847,999(2)
 (1)      Includes 87,989 phantom stock units and restricted stock units.  The weighted average exercise price reported in column (b) does not take these awards into account.
 (2)      Represents the total number of shares available for issuance under the PG&E Corporation's Long-Term Incentive Program (“LTIP”) and the PG&E Corporation 2006 Long-Term Incentive Plan (“2006 LTIP”) as of December 31, 2007.  Outstanding stock-based awards granted under the LTIP include stock options, restricted stock and phantom stock payable in an equal number of shares upon termination of employment or service as a director. The LTIP expired on December 31, 2005.  The 2006 LTIP, which became effective on January 1, 2006 authorizes up to 12 million shares to be issued pursuant to awards granted under the 2006 LTIP.  Outstanding stock-based awards granted under the 2006 LTIP include stock options, restricted stock, restricted stock units and phantom stock payable in an equal number of shares upon termination of employment or service as a director.  For a description of the LTIP and the 2006 LTIP, see Note 14 of the Notes to the Consolidated Financial Statements in the 2007 Annual Report.

42




Plan Category
 
(a)
Number of Securities to
be Issued Upon Exercise
of Outstanding Options,
Warrants and Rights
 
(b)
Weighted Average
Exercise Price of
Outstanding Options,
Warrants and Rights
 
(c)
Number of Securities
Remaining Available for
Future Issuance Under
Equity Compensation Plans
(Excluding Securities
Reflected in Column(a))
Equity compensation plans approved by shareholders 12,012,774 $23.26 8,952,785(1)
Equity compensation plans not approved by shareholders  $— 
Total equity compensation plans 12,012,774 $23.26 8,952,785
(1) Represents the total number of shares available for issuance under PG&E Corporation's Long-Term Incentive Program, or LTIP, as of December 31, 2005. Outstanding stock-based awards granted under the LTIP include stock options, restricted stock and phantom stock payable in an equal number of shares upon termination of employment or service as a director. The LTIP expired on December 31, 2005. The PG&E Corporation 2006 Long-Term Incentive Plan, or 2006 LTIP, became effective on January 1, 2006. The 2006 LTIP authorizes up to 12 million shares to be issued pursuant to awards granted under the 2006 LTIP. For a description of the LTIP and the 2006 LTIP, see Note 14 of the Notes to the Consolidated Financial Statements in the 2005 Annual Report.


Information responding to Item 13, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under the heading "Certain Relationshipsheadings “Related Person Transactions,” “Review, Approval, and Ratification of Related Transactions"Person Transactions” and “Information Regarding the Boards of Directors of PG&E Corporation and Pacific Gas and Electric CompanyDirector Independence” in the Joint Proxy Statement relating to the 20062008 Annual Meetings of Shareholders, which information is hereby incorporated by reference.


Information responding to Item 14, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under the heading "Information“Information Regarding the Independent Registered Public Accounting Firm of PG&E Corporation and Pacific Gas and Electric Company"Company” in the Joint Proxy Statement relating to the 20062008 Annual Meetings of Shareholders, which information is hereby incorporated by reference.




44


PART IV


(a)The following documents are filed as a part of this report:

1.The following consolidated financial statements, supplemental information and report of independent registered public accounting firm are contained in the 20052007 Annual Report and are incorporated by reference in this report:

Consolidated Statements of Income for the Years Ended December 31, 2005, 2004,2007, 2006, and 2003,2005 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Balance Sheets at December 31, 2005,2007 and 20042006 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006, and 2005 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Shareholders' Equity for the Years Ended December 31, 2005, 2004,2007, 2006, and 2003,2005 for each of PG&E Corporation and Pacific Gas and Electric Company.

Notes to the Consolidated Financial Statements.

Quarterly Consolidated Financial Data (Unaudited).

Report of Independent Registered Public Accounting Firm (Deloitte & Touche LLP).

2.The following financial statement schedules and report of independent registered public accounting firm are filed as part of this report:

Report of Independent Registered Public Accounting Firm (Deloitte & Touche LLP).

I—Condensed Financial Information of Parent as of December 31, 20052007 and 20042006 and for the Years Ended December 31, 2005, 2004,2007, 2006, and 2003.2005.

II—Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 2005, 2004,2007, 2006, and 2003.2005.

Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto.

3.Exhibits required by Item 601 of Regulation S-K:

43

Exhibit
Number
Exhibit Description
2.1Order of the U.S. Bankruptcy Court for the Northern District of California dated December 22, 2003, Confirming Plan of Reorganization of Pacific Gas and Electric Company, including Plan of Reorganization, dated July 31, 2003 as modified by modifications dated November 6, 2003 and December 19, 2003 (Exhibit B to Confirmation Order and Exhibits B and C to the Plan of Reorganization omitted) (incorporated by reference to Pacific Gas and Electric Company's Registration Statement on Form S-3 No. 333-109994, Exhibit 2.1)
2.2Order of the U.S. Bankruptcy Court for the Northern District of California dated February 27, 2004 Approving Technical Corrections to Plan of Reorganization of Pacific Gas and Electric Company and Supplementing Confirmation Order to Incorporate such Corrections (incorporated by reference to Pacific Gas and Electric Company's Registration Statement on Form S-3 No. 333-109994, Exhibit 2.2)
3.1Restated Articles of Incorporation of PG&E Corporation effective as of May 29, 2002 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609), Exhibit 3.1)
3.2Certificate of Determination for PG&E Corporation Series A Preferred Stock filed December 22, 2000 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 3.2)
3.3Bylaws of PG&E Corporation amended as of January 1, 2006September 19, 2007 (incorporated by reference to PG&E Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007) (File No. 1-12609), Exhibit 3.1)
3.4Text of the amendment to the Bylaws of PG&E Corporation effective May 14, 2008
3.5Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 12, 2004 (incorporated by reference to Pacific Gas and Electric Company's Form 8-K filed April 12, 2004 (File No. 1-2348), Exhibit 3)
3.53.6Bylaws of Pacific Gas and Electric Company amended as of January 1, 20062008
3.7Text of the amendment to the Bylaws of Pacific Gas and Electric Company effective May 14, 2008
4.1Indenture, dated as of April 22, 2005, supplementing, amending and restating the Indenture of Mortgage, dated as of March 11, 2004, as supplemented by a First Supplemental Indenture, dated as of March 23, 2004, and a Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and The Bank of New York Trust Company, N.A. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q filed May 4, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 4.1)
4.2First Supplemental Indenture dated as of March 13, 2007 relating to the issuance of $700,000,000 principal amount of 5.80% Senior Notes due March 1, 2037 (incorporated by reference from Pacific Gas and Electric Company’s Current Report on Form 8-K dated March 14, 2007 (File No. 1-2348), Exhibit 4.1)
4.3Second Supplemental Indenture dated as of December 4, 2007 relating to the issuance of $500,000,000 principal amount of 5.625% Senior Notes due November 30, 2017(incorporated by reference from Pacific Gas and Electric Company’s Current Report on Form 8-K dated March 14, 2007 (file No. 1-2348), Exhibit 4.1)
4.4Indenture related to PG&E Corporation's 7.5% Convertible Subordinated Notes due June 2007, dated as of June 25, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.1).
4.34.5Supplemental Indenture related to PG&E Corporation's 9.50% Convertible Subordinated Notes due June 2010, dated as of October 18, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.1)
4.4Warrant Agreement, dated as of October 18, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.2)
10.1Amended and Restated Unsecured Revolving Credit Agreement dated as of April 8, 2005, among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JP Morgan Chase Bank, N.A., as syndication agent and a lender, Barclays Bank PLC, BNP Paribas and Deutsche Bank Securities Inc., as documentation agents and lenders, ABN Amro Bank N.V., Lehman Brothers Bank, FSB, Mellon Bank, N.A., Royal Bank of Canada, The Bank of New York, The Bank of Nova Scotia, UBS Loan Finance LLC, and Union Bank of California, N.A., as senior managing agents, and KBC Bank, NV, Morgan Stanley Bank and William Street Commitment Corporation, as lenders (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q filed May 4, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 10.3)
10.2First Amendment, dated as of November 30, 2005, to the Credit Agreemententered into among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JPMorgan Chase Bank, N.A.Securities Inc., as syndication agent, and a lender, Barclays Bank PLCPlc and BNP Paribas, as documentation agents and lenders, Deutsche Bank Securities Inc., as documentation agent, and the following other lenders: Deutsche Bank AG New York Branch, ABN Amro Bank N.V., Lehman Brothers Bank, FSB, Mellon Bank, N.A., Royal Bank of Canada, The Bank of New York, UBS Loan Finance LLC, Union Bank of California, N.A., KBC Bank, N.V., Morgan Stanley Bank and William Street Commitment Corporation.
10.3Credit Agreement,lenders, dated as of December 10, 2004, among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities, as syndication agent, ABN Amro Bank, N.V., Goldman Sachs Credit Partners L.P., and Union Bank of California, N.A., as documentation agents and lenders, and the following other lenders: Barclays Bank PLC, Citicorp USA, Inc., Deutsche Bank AG New York Branch, JP Morgan Chase Bank, N.A., Lehman Brothers Bank, FSB, Morgan Stanley Bank, Royal Bank of Canada, The Bank of Nova Scotia, and The Bank of New YorkFebruary 26, 2007 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed December 15, 200410-Q for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 1-2348), Exhibit 99)10.2)
44

45 

10.410.2First Amendment, dated as of April 8, 2005, to theAmended and Restated Unsecured Revolving Credit Agreement dated as of December 10, 2004,entered into among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities Inc., as syndication agent, and a lender, ABN AmroAMRO Bank, N.V., Goldman Sachs Credit Partners L.P.Bank of America, N.A., and UnionBarclays Bank of California, N.A.,Plc, as documentation agents and lenders, and the following other lenders: Barclays Bank PLC, Citicorp USA, Inc., Deutsche Bank AG New York Branch, JP Morgan Chase Bank, N.A., Lehman Brothers Bank, FSB, Morgan Stanley Bank, Royal Bank of Canada, The Bank of Nova Scotia, KBC Bank N.V., and The Bank of New Yorklenders, dated February 26, 2007 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q filed May 4, 2005for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2)
10.5Master Confirmation dated November 16, 2005, for accelerated share repurchase arrangements between PG&E Corporation and Goldman, Sachs & Co.
10.610.3Settlement Agreement among California Public Utilities Commission, Pacific Gas and Electric Company and PG&E Corporation, dated as of December 19, 2003, together with appendices (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 8-K filed December 22, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 99)
10.7Firm Transportation Service Agreement between Pacific Gas and Electric Company and Pacific Gas Transmission Company dated October 26, 1993, Rate Schedule FTS-1, and general terms and conditions (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 10.4)
10.8Operating Agreement between Pacific Gas and Electric Company and Pacific Gas Transmission Company dated July 9, 1996 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 10.5)
10.9PG&E Trans-User Agreement between Pacific Gas and Electric Company and PG&E Gas Transmission, Northwest Corporation dated November 15, 1999 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 10.6)
10.1010.4Transmission Control Agreement among the California Independent System Operator (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, effective as of March 31, 1998, as amended (CAISO, FERC Electric Tariff No. 7) (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.8)
10.1110.5Operating Agreement, as amended on November 12, 2004, effective as of December 22, 2004, between the State of California Department of Water Resources and Pacific Gas and Electric Company (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.9)
*10.1210.6PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001, and frozen after December 31, 2004 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.10)
 46

*10.1310.7PG&E Corporation Supplemental Retirement Savings Plan effective as of January 1, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.11)
*10.14Description of Compensation Arrangement between PG&E Corporation and Peter Darbee (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.3)
*10.1510.8Letter regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective July 1, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.4)
*10.1610.9Letter regarding Compensation ArrangementRestricted Stock Award Agreement between PG&E Corporation and Peter A. Darbee dated January 3, 2007 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 12348), Exhibit 10.3)
*10.10Retention Agreement between PG&E Corporation and Thomas B. King dated November 4, 1998 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended DecemberAugust 31, 2000 (File No. 1-12609), Exhibit 10.6)
*10.17Letter regarding Compensation Arrangement between PG&E Corporation and Thomas B. King dated June 18, 20032006 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended JuneSeptember 30, 20032006 (File No. 1-12609), Exhibit 10.3)10.2)
*10.1810.11Letter regarding Compensation Arrangement between Pacific Gas and Electric Company and William T. Morrow dated June 20, 2006 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (File No. 1-12609), Exhibit 10.1)
*10.12Restricted Stock Award Agreement between PG&E Corporation and William T. Morrow dated January 29, 2007 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609), Exhibit 10.4)
*10.13Performance Share Agreement between PG&E Corporation and William T. Morrow dated November 6, 2007
*10.14Restricted Stock Award Agreement between PG&E Corporation and William T. Morrow dated November 6, 2007
*10.15Letter regarding Compensation Arrangement between PG&E Corporation and Rand L. Rosenberg dated October 19, 2005
*10.19Severance Agreement and Release by and between Pacific Gas and Electric Company and Gordon R. Smith dated September 21, 2005 (incorporated by reference to Pacific Gas and Electric Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005 (File No. 1-2348), Exhibit 10.1)
*10.20Actions taken by the Nominating, Compensation and Governance Committee of the PG&E Corporation Board of Directors on October 19, 2005, regarding the 2006 Officer Compensation Program (incorporated by reference to PG&E Corporation’s Quarterly Report on Form 10-Q10-K for the quarteryear ended September 30, 2005December 31, 2005) (File No. 1-12609), Exhibit 10.2)10.18)
*10.2110.16Letter regarding Compensation Arrangement between PG&E Corporation and Hyun Park dated October 10, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2006) (File No. 1-12609), Exhibit 10.18)
45

*10.17
Letter regarding Compensation Agreement between PG&E Corporation and G. Robert Powell dated
August 8, 2005
*10.18PG&E Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, effective as of January 1, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.17)
*10.2210.19Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 20062008
*10.2310.20Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 20052007 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.18)10.20)
*10.24Schedule of 2006 Base Salary and Short-Term Incentive Plan Target Participation Rates for certain officers of PG&E Corporation and its subsidiaries
*10.25Schedule of 2006 award values under the PG&E Corporation 2006 Long-Term Incentive Plan for certain officers of PG&E Corporation and its subsidiaries
*10.2610.21Supplemental Executive Retirement Plan of the Pacific Gas and Electric Company amended effective as of December 31, 2004, and frozen as of January 1, 2005 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004) (File No. 1-2348), Exhibit 10.20)
*10.2710.22Supplemental Executive Retirement Plan of PG&E Corporation as amended effective as of January 1, 2006
*10.28.1Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Robert D. Glynn, Jr. dated December 20, 2002 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-K for the year ended December 31, 20022005) (File No. 1-12609), Exhibit 10.37.1)
*10.28.2Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Bruce R. Worthington dated December 20, 2002 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.37.2)
*10.28.3Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gregory M. Rueger dated December 20, 2002 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2002 (File No. 1-12609 and File No. 1-2348), Exhibit 10.37.3)10.27)
*10.28.4Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gordon R. Smith dated December 20, 2002 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2002 (File No. 1-12609 and File No. 1-2348), Exhibit 10.37.4)
*10.29.1Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Robert D. Glynn, Jr. dated April 18, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.2.1)
 47

*10.29.2Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gordon R. Smith dated April 18, 2003 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2.2)
*10.29.3Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gregory M. Rueger dated April 18, 2003 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2.4)
*10.29.4Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Bruce R. Worthington dated April 18, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.2.5)
*10.3010.23Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16)
*10.3110.24Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16)
*10.3210.25
PG&E Corporation Non-Employee Director Stock Incentive Plan (a component of the PG&E Corporation Long-Term Incentive Program) as amended effective as of July 1, 2004 (reflecting amendments adopted by the PG&E Corporation Board of Directors on June 16, 2004 set forth in resolutions filed as Exhibit 10.3 to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004) (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.27)
*10.3310.26Resolution of the PG&E Corporation Board of Directors dated June 16, 2004,December 20, 2006, adopting director compensation arrangement effective January 1, 2007 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q10-K for the quarteryear ended June 30, 2004December 31, 2006 (File No. 1-12609 and File No. 12348), Exhibit 10.1)10.29)
*10.3410.27
Resolution of the Pacific Gas and Electric Company Board of Directors dated June 16, 2004,December 20, 2006, adopting director compensation arrangement effective January 1, 2007 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q10-K for the quarteryear ended June 30, 2004December 31, 2006 (File No. 1-12609 and File No. 12348), Exhibit 10.2)
10.30)
*10.3510.28
Resolution of the PG&E Corporation Board of Directors dated February 20, 2008, adopting director compensation arrangement effective January 1, 2008
*10.29Resolution of the Pacific Gas and Electric Company Board of Directors dated February 20, 2008, adopting director compensation arrangement effective January 1, 2008
*10.30PG&E Corporation 2006 Long-Term Incentive Plan, effective as of January 1, 2006, as amended on February 15, 2006 (with respect to change in control provisions) and December 20, 2006 and October 17, 2007 (with respect to Section 7 governing nondiscretionary awards to non-employee directors)
*10.3610.31PG&E Corporation Long-Term Incentive Program (including the PG&E Corporation Stock Option Plan and Performance Unit Plan), as amended May 16, 2001, (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10)
*10.3710.32Form of Restricted Stock Award Agreement for 2003 grants made under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.46)
46

*10.3810.33Form of Restricted Stock Award Agreement for 2004 grants made under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2003 (File No. 1-12609), Exhibit 10.37)
*10.3910.34Form of Restricted Stock Agreement for 2005 grants under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.3)
*10.4010.35Form of Restricted Stock Agreement for 2006 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 9, 2006, Exhibit 99.1)
*10.4110.36Form of Restricted Stock Agreement for 2007 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the PG&E Corporation 2006 Long-Term Incentive Plan made on February 15, 2006) (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.39)
*10.37Form of Non-Qualified Stock Option Agreement under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.1)
*10.4210.38Form of Performance Share Award Agreement for 2004 grants under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2003 (File No. 1-12609), Exhibit 10.38)
*10.4310.39Form of Performance Share Agreement for 2005 grants under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.2)
*10.4410.40Form of Performance Share Agreement for 2006 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 9, 2006, Exhibit 99.2)
*10.41
48 

Form of Performance Share Agreement for 2007 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the PG&E Corporation 2006 Long-Term Incentive Plan made on February 15, 2006)
*10.4510.42PG&E Corporation Executive Stock Ownership Program Guidelines dated as of February 19, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609) Exhibit 10. 2)10.2)
*10.4610.43PG&E Corporation Executive Stock Ownership Program Guidelines as amended February 15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.46)
*10.4710.44PG&E Corporation Officer Severance Policy, as amended effective as of January 1, 2005 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.37) (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.44)
*10.4810.45PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.48)
*10.4910.46PG&E Corporation Golden Parachute Restriction Policy effective as of February 15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.49)
*10.5010.47PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.1)
*10.5110.48PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998, as updated effective January 1, 2005 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.39)
47

*10.5210.49Resolution of the Board of Directors of PG&E Corporation regarding indemnification of officers and directors dated December 18, 1996 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.40)
*10.5310.50Resolution of the Board of Directors of Pacific Gas and Electric Company regarding indemnification of officers and directors dated July 19, 1995 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-2348), Exhibit 10.41)
11Computation of Earnings Per Common Share
12.1Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
12.2Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
13The following portions of the 20052007 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company are included: "Selected“Selected Financial Data," "Management's” “Management's Discussion and Analysis of Financial Condition and Results of Operations," financial statements of PG&E Corporation entitled "Consolidated“Consolidated Statements of Income," "Consolidated” “Consolidated Balance Sheets," "Consolidated” “Consolidated Statements of Cash Flows," and "Consolidated“Consolidated Statements of Shareholders' Equity," financial statements of Pacific Gas and Electric Company entitled "Consolidated“Consolidated Statements of Income," "Consolidated” “Consolidated Balance Sheets," "Consolidated” “Consolidated Statements of Cash Flows," and "Consolidated“Consolidated Statements of Shareholders' Equity," "Notes” “Notes to the Consolidated Financial Statements," and "Quarterly“Quarterly Consolidated Financial Data (Unaudited)," "Management's” “Management's Report on Internal Control Over Financial Reporting," "Report” “Report of Independent Registered Public Accounting Firm," and "Report“Report of Independent Registered Public Accounting Firm."
21Subsidiaries of the Registrant
23Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP)
24.1Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K
24.2Powers of Attorney
31.1Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
31.2Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
**32.1Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
**32.2Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002
*Management contract or compensatory agreement.

**Pursuant to Item 601(b) (32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.


4948


SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this Annual Report on Form 10-K for the year ended December 31, 20052007 to be signed on their behalf by the undersigned, thereunto duly authorized.

 PG&E CORPORATION PACIFIC GAS AND ELECTRIC COMPANY
By
(Registrant)
 
BRUCE R WORTHINGTON
(Bruce R. Worthington, Attorney-in-Fact)*PETER A. DARBEE
By
(Registrant)
 
BRUCE R WORTHINGTON
(Bruce R. Worthington, Attorney-in-Fact)*WILLIAM T. MORROW
By:
Peter A. Darbee
Chairman of the Board, Chief Executive Officer
and President
By:
William T. Morrow
President and Chief Executive Officer
Date:
February 17, 2006
22, 2008
Date:
February 17, 2006
22, 2008
    

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrants and in the capacities and on the dates indicated.

Signature
Title
Title
Date
A.
Principal Executive Officers
  
*PETER A. DARBEEChairman of the Board, Chief Executive Officer, President and PresidentDirector (PG&E Corporation)February 17, 200622, 2008
  Peter A. Darbee
 
*THOMAS B. KINGWILLIAM T. MORROWPresident and Chief Executive Officer (Pacific Gas and Electric Company)February 17, 200622, 2008
  William T. Morrow
    
B.
Principal Financial Officers
  
*CHRISTOPHER P. JOHNSSenior Vice President, Chief Financial Officer and Treasurer (PG&E CorporationCorporation)February 22, 2008
  Christopher P. Johns
*G. ROBERT POWELLVice President, Chief Financial Officer and PacificController (Pacific Gas and Electric Company )Company)February 17, 200622, 2008
  G. Robert Powell
C. Principal Accounting Officer   February 22, 2008
C.
Principal Accounting Officers
*G. ROBERT POWELLVice President and Controller (PG&E Corporation and Pacific(Pacific  Gas and Electric Company)February 17, 200622, 2008
  G. Robert Powell
D. Directors
*DAVID R. ANDREWSDirectorFebruary 22, 2008
  David R. Andrews
    
D.
*LESLIE S. BILLER
Directors
DirectorFebruary 22, 2008
  Leslie S. Biller
*DAVID A. COULTERDirectorFebruary 22, 2008
  David A. Coulter
*C. LEE COXDirectorFebruary 22, 2008
  C. Lee Cox
*MARYELLEN C. HERRINGERDirectorFebruary 22, 2008
  Maryellen C. Herringer  
 
*DAVID R. ANDREWSRICHARD A. MESERVEDirectorFebruary 22, 2008
  Richard A. Meserve
49

*DAVID A. COULTER
*C. LEE COX
*PETER A. DARBEE
*MARYELLEN C. HERRINGER
*THOMAS B. KING
(Director of Pacific Gas andElectric Company only)
*MARY S. METZ
*BARBARA L. RAMBO
*BARRY LAWSON WILLIAMS
Directors of PG&E Corporation and
Pacific
DirectorFebruary 22, 2008
  Mary S. Metz
*WILLIAM T. MORROWDirector (Pacific Gas and Electric Company
except as noted
only)
February 17, 200622, 2008

  William T. Morrow
*ByBARBARA L. RAMBO
BRUCE R WORTHINGTON
(Bruce R. Worthington, Attorney-in-Fact)
DirectorFebruary 22, 2008
  Barbara L. Rambo
*BARRY LAWSON WILLIAMSDirectorFebruary 22, 2008
  Barry Lawson Williams
*By:HYUN PARK                          
             HYUN PARK, Attorney-in-Fact  


50


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Boards of Directors and Shareholders of
PG&E Corporation and Pacific Gas and Electric Company

We have audited the consolidated financial statements of PG&E Corporation and subsidiaries (the “Company”"Company") and Pacific Gas and Electric Company and subsidiaries (the “Utility”) as of December 31, 20052007 and 2004,2006, and for each of the three years in the period ended December 31, 2005, management’s assessment of2007, and the effectiveness of the Company’sCompany's and the Utility’s internal control over financial reporting as of December 31, 2005, and the effectiveness of the Company’s and the Utility’s internal control over financial reporting as of December 31, 2005,2007, and have issued our reports thereon dated February 15, 2006;21, 2008; such consolidated financial statements and reports are included in your 20052007 Annual Report to Shareholders of the Company and the Utility and are incorporated herein by reference.  Our audits also included the condensedconsolidated financial statement schedules of the Company and the Utility listed in Item 15 (a) 15(a)2.  These condensedconsolidated financial statement schedules are the responsibility of the Company’sCompany's and the Utility’s management.  Our responsibility is to express an opinion based on our audits.  In our opinion, such condensedconsolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

DELOITTE & TOUCHE LLP

San Francisco, California
February 15, 200621, 2008

51


PG&E CORPORATION
SCHEDULE I --CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED BALANCE SHEETS
(in millions)

 
Balance at December 31,
  Balance at December 31, 
 
2005
 
2004
  2007 2006 
ASSETS
              
Current Assets:       
Cash and cash equivalents $250 $183  $204 $386 
Advances to affiliates  38  22   30  42 
Income taxes receivable  46  - 
Other current assets  3  3   3  3 
Total current assets  291  208   283  431 
Equipment  15  15   17  15 
Accumulated depreciation  (14) (13)  (15) (14)
Net equipment  1  2   2  1 
Investments in subsidiaries  7,401  8,848   8,886  7,959 
Other investments  71  31   87  81 
Deferred income taxes  127  104   51  132 
Other  15  14   9  10 
Total Assets $7,906 $9,207  $9,318 $8,614 
LIABILITIES AND SHAREHOLDERS' EQUITY
              
Current Liabilities       
Accounts payable—related parties $27 $3 
Accounts payable—other  17  15 
Current Liabilities:       
Accounts payable       
Related parties $40 $41 
Other  24  18 
Long-term debt, classified as current  -  280 
Income taxes payable  28  83   -  122 
Other  193  53   174  210 
Total current liabilities  265  154   238  671 
Noncurrent Liabilities:              
Long-term debt  280  280   280  - 
Income taxes payable  131  - 
Other  143  140   116  133 
Total noncurrent liabilities  423  420   527  133 
Preferred stock     
Common Shareholders' Equity              
Common stock  5,827  6,518   6,110  5,877 
Common stock held by subsidiary  (718) (718)  (718) (718)
Unearned compensation  (22) (26)
Reinvested earnings  2,139  2,863   3,151  2,670 
Accumulated other comprehensive loss  (8) (4)
Accumulated other comprehensive income (loss)  10  (19
Total common shareholders' equity  7,218  8,633   8,553  7,810 
Total Liabilities and Shareholders' Equity $7,906 $9,207  $9,318 $8,614 



52



PG&E CORPORATION
SCHEDULE I --CONDENSED FINANCIAL INFORMATION OF PARENT -- (Continued)(Continued)
CONDENSED STATEMENTS OF INCOME
(in millions, except per share amounts)

 
Year Ended December 31,
  Year Ended December 31, 
 
2005
 
2004
 
2003
  2007 2006 2005 
Administrative service revenue $97 $85 $101  $102 $110 $97 
Equity in earnings of subsidiaries  918  3,959  917   1,006  964  918 
Operating expenses  (97) (110) (133)  (112) (115) (97)
Interest income  9  15  20   15  15  9 
Interest expense  (35) (132) (200)  (31) (30) (35)
Other income (expense)  (17) (91) 2 
Other expense  
(6
) 
(1
) 
(17
)
Income before income taxes  875  3,726  707   974  943  875 
Income tax benefit  29  94  84   
32
  
48
  
29
 
Income from continuing operations  904  3,820  791   1,006  991  904 
Gain on disposal of NEGT  13  684     
--
  
--
  
13
 
Discontinued operations      (365)
Cumulative effect of changes in accounting principles      (6)
Net income before intercompany eliminations $917 $4,504 $420  $
1,006
 $
991
 $
917
 
Weighted average common shares outstanding
  372  398  385 
Earnings per common share, basic(1)
 $2.40 $10.80 $1.04 
Earnings per common share, diluted(1)
 $2.37 $10.57 $1.02 
Weighted average common shares outstanding, basic  
351
  
346
  
372
 
Weighted average common shares outstanding, diluted  
353
  
349
  
378
 
Earnings per common share, basic(1) $
2.79
 $
2.78
 $
2.40
 
Earnings per common share, diluted(1)
 
$
2.78
 
$
2.76
 
$
2.37
 

(1)           PG&E Corporation adopted the consensus reached by Emerging Issues Task Force, or EITF, in EITF issue No. 03-06, "Participating Securities and the Two-Class Method under FASB Statement No. 128," or EITF 03-06, as ratified by the Financial Accounting Standards Board on March 31, 2004.

PG&E Corporation currently has outstanding $280 million principal amount of convertible subordinated 9.50% notes due 2010, or Convertible Notes, that are entitled to receive (non-cumulative) dividend payments without exercising the conversion option. These Convertible Notes, which were issued in June 2002, meet the criteria of a participating security in the calculation of earnings per share using the "two-class" method.

Accordingly, the basic and diluted earnings per share calculations for each of the years in the three year period ended December 31, 2007 reflect the allocation of earnings between PG&E Corporation common stock and the participating security.



53


PG&E CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT (Continued)
CONDENSED STATEMENTS OF CASH FLOWS
(in millions)
  Year Ended December 31, 
  2007  2006  2005 
Cash Flows from Operating Activities:         
Net income $1,006  $991  $917 
Gain on disposal of NEGT (net of income tax benefit of $13 million in 2005)   --   --   (13)
Net income from continuing operations  1,006   991   904 
Adjustments to reconcile net income to net cash provided by operating activities:            
Depreciation  1   --   -- 
Equity in earnings of subsidiaries  (1,006)  (964)  (918)
Deferred taxes  47   2   (23)
Other  (24) )  130   86 
Net cash provided by operating activities  24   159   49 
Cash Flows From Investing Activities:            
Capital expenditures  (1)  (1)  (1)
Investment in subsidiaries  (405)  --   -- 
Stock repurchase by subsidiary  --   --   1,910 
Dividends received from subsidiaries  509   460   445 
Other  --   --   (38)
Net cash provided by investing activities  103   459   2,316 
Cash Flows From Financing Activities(2):
            
Common stock issued  175   131   243 
Common stock repurchased  --   (114)  (2,188)
Common stock dividends paid   (496)  (456)  (334)
Long-term debt redeemed  --   --   (2)
Other  12   (43)  (17)
Net cash used by financing activities  (309)  (482)  (2,298)
Net change in cash and cash equivalents  (182)  136   67 
Cash and cash equivalents at January 1  386   250   183 
Cash and cash equivalents at December 31 $204  $$386  $$250 


  
Year Ended December 31,
 
  
2005
 
2004
 
2003
 
Cash Flows from Operating Activities:          
Net income $917 $4,504 $(420)
Gain on disposal of NEGT (net of income tax benefit of $13 million in 2005 and income tax expense of $374 million in 2004)  (13) (684)  
Loss from operations of NEGT (net of income tax benefit of $320 million)      365 
Cumulative effect of changes in accounting principles      6 
Net income from continuing operations  904  3,820  791 
Adjustments to reconcile net income to net cash provided by operating activities:          
Equity in earnings of subsidiaries  (918) (3,959) (917)
Deferred taxes  (23) 27  265 
NEGT settlement payment    (30)  
Other  86  160  391 
Net cash provided by operating activities  49  18  530 
Cash Flows From Investing Activities:          
Capital expenditures  (1)    
Investment in subsidiaries    (28)  
Stock repurchase by subsidiary  1,910     
Dividends received from subsidiaries  445     
Increase in restricted cash    361   
Other  (38)    
Net cash provided by investing activities  2,316  333   
Cash Flows From Financing Activities(2):
          
Common stock issued  243  162  166 
Common stock repurchased  (2,188) (350)  
Common stock dividends paid   (334)    
Long-term debt issued      581 
Long-term debt redeemed  (2) (652) (787)
Other  (17) (1) 1 
Net cash used by financing activities  (2,298) (841) (39)
Net change in cash and cash equivalents  67  (490) 491 
Cash and cash equivalents at January 1  183  673  182 
Cash and cash equivalents at December 31 $250 $183 $673 
(2)           On January 15, 2007, PG&E Corporation paid a quarterly common stock dividend of $0.33 per share.  On April 15, July 15, and October 15, 2007, PG&E Corporation paid quarterly common stock dividends of $0.36 per share.  Of the total dividend payments made by PG&E Corporation in 2006, approximately $35 million was paid to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation.
        __________________________________

On January 16, April 15, July 15, and October 15, 2006, PG&E Corporation paid a quarterly common stock dividend of $0.33 per share, totaling approximately $489 million.  Of the total dividend payments made by PG&E Corporation in 2006, approximately $33 million was paid to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation.

(1)
PG&E Corporation adopted the consensus reached by Emerging Issues Task Force, or EITF, in EITF issue No. 03-06, "Participating Securities and the Two-Class Method under FASB Statement No. 128," or EITF 03-06, as ratified by the Financial Accounting Standards Board on March 31,On April 15, July 15 and October 17, 2005, PG&E Corporation paid a quarterly common stock dividend of $0.30 per share, totaling approximately $356 million.  Of the total dividend payments made by PG&E Corporation in 2005, approximately $22 million was paid to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation.  PG&E Corporation did not pay any dividends during 2004.
PG&E Corporation currently has outstanding $280 million principal amount of convertible subordinated 9.50% notes due 2010, or Convertible Notes, that are entitled to receive (non-cumulative) dividend payments without exercising the conversion option. These Convertible Notes, which were issued in June 2002, meet the criteria of a participating security in the calculation of earnings per share using the "two-class" method.
Accordingly, the basic and diluted earnings per share calculations for each of the years in the three year period ended December 31, 2005 reflect the allocation of earnings between PG&E Corporation common stock and the participating security.
(2)
On April 15, July 15 and October 17, 2005, PG&E Corporation paid a quarterly common stock dividend of $0.30 per share, totaling approximately $356 million. Of the total dividend payments made by PG&E Corporation in 2005, approximately $22 million was paid to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation. PG&E Corporation did not pay any dividends during 2004 and 2003.



54



PG&E CORPORATIONCorporation

SCHEDULE II—II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2005, 20032007, 2006, and 20042005

    
Additions
     
Description 
 
Balance
at Beginning of Period
 
Charged to Costs and
Expenses
 
Charged to Other
Accounts
 
Deductions(3)
 
Balance
at End of Period
 
  
(in millions)
 
Valuation and qualifying accounts deducted from assets: 
           
2005                
Allowance for uncollectible accounts(1)
 $93 $21 $ $37 $77 
2004:                
Allowance for uncollectible accounts(1)(2)
 $68 $85 $ $60 $93 
2003:                
Allowance for uncollectible accounts(1)(2)
 $59 $42 $ $33 $68 
        __________________________________
        (1)Allowance for uncollectible accounts is deducted from "Accounts receivable Customers, net."

        (2)Allowance for uncollectible accounts does not include NEGT.

        (3)Deductions consist principally of write-offs, net of collections of receivables previously written off.
     
Additions
       
Description
 
Balance at Beginning of Period
  
Charged to Costs and Expenses
  
Charged to Other Accounts
  
Deductions(3)
  
Balance at End of Period
 
(in millions)               
Valuation and qualifying accounts deducted from assets:               
2007:               
Allowance for uncollectible accounts(1)(2) $50  $20  $-  $12  $58 
2006:                    
Allowance for uncollectible accounts(1)(2) $77  $2  $-  $29  $50 
2005:                    
Allowance for uncollectible accounts(1)(2) $93  $21  $-  $37  $77 
                     
                     
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable Customers, net.” 
(2) Allowance for uncollectible accounts does not include NEGT. 
(3) Deductions consist principally of write-offs, net of collections of receivables previously written off. 


55



PACIFIC GAS AND ELECTRIC COMPANYPacific Gas and Electric Company

SCHEDULE II—II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2005, 20042007, 2006, and 20032005

    
Additions
     
Description 
 
Balance
at Beginning of Period
 
Charged to Costs and
Expenses
 
Charged to Other Accounts
 
Deductions(2)
 
Balance
at End of Period
 
  
(in millions)
 
Valuation and qualifying accounts deducted from assets: 
           
2005                
Allowance for uncollectible accounts(1)
 $93 $21 $ $37 $77 
2004:                
Allowance for uncollectible accounts(1)
 $68 $85 $ $60 $93 
2003:                
Allowance for uncollectible accounts(1)
 $59 $42 $ $33 $68 
        __________________________
        (1)Allowance for uncollectible accounts is deducted from "Accounts receivable Customers, net."
     
Additions
       
Description
 
Balance at Beginning of Period
  
Charged to Costs and Expenses
  
Charged to Other Accounts
  
Deductions(2)
  
Balance at End of Period
 
(in millions)               
Valuation and qualifying accounts deducted from assets:               
2007:               
Allowance for uncollectible accounts(1) $50  $20  $-  $12  $58 
2006:                    
Allowance for uncollectible accounts(1) $77  $2  $-  $29  $50 
2005:                    
Allowance for uncollectible accounts(1) $93  $21  $-  $37  $77 
                     
                     
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable Customers, net.” 
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off. 

        (2)Deductions consist principally of write-offs, net of collections of receivables previously written off.

56



EXHIBIT INDEX

Exhibit Index
Exhibit
Number
Exhibit Description
2.1Order of the U.S. Bankruptcy Court for the Northern District of California dated December 22, 2003, Confirming Plan of Reorganization of Pacific Gas and Electric Company, including Plan of Reorganization, dated July 31, 2003 as modified by modifications dated November 6, 2003 and December 19, 2003 (Exhibit B to Confirmation Order and Exhibits B and C to the Plan of Reorganization omitted) (incorporated by reference to Pacific Gas and Electric Company's Registration Statement on Form S-3 No. 333-109994, Exhibit 2.1)
2.2Order of the U.S. Bankruptcy Court for the Northern District of California dated February 27, 2004 Approving Technical Corrections to Plan of Reorganization of Pacific Gas and Electric Company and Supplementing Confirmation Order to Incorporate such Corrections (incorporated by reference to Pacific Gas and Electric Company's Registration Statement on Form S-3 No. 333-109994, Exhibit 2.2)
3.1Restated Articles of Incorporation of PG&E Corporation effective as of May 29, 2002 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609), Exhibit 3.1)
3.2Certificate of Determination for PG&E Corporation Series A Preferred Stock filed December 22, 2000 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 3.2)
3.3Bylaws of PG&E Corporation amended as of January 1, 2006September 19, 2007 (incorporated by reference to PG&E Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007) (File No. 1-12609), Exhibit 3.1)
3.4Text of the amendment to the Bylaws of PG&E Corporation effective May 14, 2008
3.5Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 12, 2004 (incorporated by reference to Pacific Gas and Electric Company's Form 8-K filed April 12, 2004 (File No. 1-2348), Exhibit 3)
3.53.6Bylaws of Pacific Gas and Electric Company amended as of January 1, 20062008
3.7Text of the amendment to the Bylaws of Pacific Gas and Electric Company effective May 14, 2008
4.1Indenture, dated as of April 22, 2005, supplementing, amending and restating the Indenture of Mortgage, dated as of March 11, 2004, as supplemented by a First Supplemental Indenture, dated as of March 23, 2004, and a Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and The Bank of New York Trust Company, N.A. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q filed May 4, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 4.1)
4.2First Supplemental Indenture dated as of March 13, 2007 relating to the issuance of $700,000,000 principal amount of 5.80% Senior Notes due March 1, 2037 (incorporated by reference from Pacific Gas and Electric Company’s Current Report on Form 8-K dated March 14, 2007 (File No. 1-2348), Exhibit 4.1)
4.3Second Supplemental Indenture dated as of December 4, 2007 relating to the issuance of $500,000,000 principal amount of 5.625% Senior Notes due November 30, 2017(incorporated by reference from Pacific Gas and Electric Company’s Current Report on Form 8-K dated March 14, 2007 (file No. 1-2348), Exhibit 4.1)
4.4Indenture related to PG&E Corporation's 7.5% Convertible Subordinated Notes due June 2007, dated as of June 25, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.1).
4.34.5Supplemental Indenture related to PG&E Corporation's 9.50% Convertible Subordinated Notes due June 2010, dated as of October 18, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.1)
4.4Warrant Agreement, dated as of October 18, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.2)
10.1Amended and Restated Unsecured Revolving Credit Agreement dated as of April 8, 2005, among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JP Morgan Chase Bank, N.A., as syndication agent and a lender, Barclays Bank PLC, BNP Paribas and Deutsche Bank Securities Inc., as documentation agents and lenders, ABN Amro Bank N.V., Lehman Brothers Bank, FSB, Mellon Bank, N.A., Royal Bank of Canada, The Bank of New York, The Bank of Nova Scotia, UBS Loan Finance LLC, and Union Bank of California, N.A., as senior managing agents, and KBC Bank, NV, Morgan Stanley Bank and William Street Commitment Corporation, as lenders (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q filed May 4, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 10.3)
10.2First Amendment, dated as of November 30, 2005, to the Credit Agreemententered into among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JPMorgan Chase Bank, N.A.Securities Inc., as syndication agent, and a lender, Barclays Bank PLCPlc and BNP Paribas, as documentation agents and lenders, Deutsche Bank Securities Inc., as documentation agent, and the following other lenders: Deutsche Bank AG New York Branch, ABN Amro Bank N.V., Lehman Brothers Bank, FSB, Mellon Bank, N.A., Royal Bank of Canada, The Bank of New York, UBS Loan Finance LLC, Union Bank of California, N.A., KBC Bank, N.V., Morgan Stanley Bank and William Street Commitment Corporation.
10.3Credit Agreement,lenders, dated as of December 10, 2004, among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities, as syndication agent, ABN Amro Bank, N.V., Goldman Sachs Credit Partners L.P., and Union Bank of California, N.A., as documentation agents and lenders, and the following other lenders: Barclays Bank PLC, Citicorp USA, Inc., Deutsche Bank AG New York Branch, JP Morgan Chase Bank, N.A., Lehman Brothers Bank, FSB, Morgan Stanley Bank, Royal Bank of Canada, The Bank of Nova Scotia, and The Bank of New YorkFebruary 26, 2007 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed December 15, 200410-Q for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 1-2348), Exhibit 99)10.2)
57

10.410.2First Amendment, dated as of April 8, 2005, to theAmended and Restated Unsecured Revolving Credit Agreement dated as of December 10, 2004,entered into among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities Inc., as syndication agent, and a lender, ABN AmroAMRO Bank, N.V., Goldman Sachs Credit Partners L.P.Bank of America, N.A., and UnionBarclays Bank of California, N.A.,Plc, as documentation agents and lenders, and the following other lenders: Barclays Bank PLC, Citicorp USA, Inc., Deutsche Bank AG New York Branch, JP Morgan Chase Bank, N.A., Lehman Brothers Bank, FSB, Morgan Stanley Bank, Royal Bank of Canada, The Bank of Nova Scotia, KBC Bank N.V., and The Bank of New Yorklenders, dated February 26, 2007 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q filed May 4, 2005for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2)
10.5Master Confirmation dated November 16, 2005, for accelerated share repurchase arrangements between PG&E Corporation and Goldman, Sachs & Co.
10.610.3Settlement Agreement among California Public Utilities Commission, Pacific Gas and Electric Company and PG&E Corporation, dated as of December 19, 2003, together with appendices (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 8-K filed December 22, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 99)
10.7Firm Transportation Service Agreement between Pacific Gas and Electric Company and Pacific Gas Transmission Company dated October 26, 1993, Rate Schedule FTS-1, and general terms and conditions (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 10.4)
10.8Operating Agreement between Pacific Gas and Electric Company and Pacific Gas Transmission Company dated July 9, 1996 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 10.5)
10.9PG&E Trans-User Agreement between Pacific Gas and Electric Company and PG&E Gas Transmission, Northwest Corporation dated November 15, 1999 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 10.6)
10.1010.4Transmission Control Agreement among the California Independent System Operator (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, effective as of March 31, 1998, as amended (CAISO, FERC Electric Tariff No. 7) (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.8)
10.1110.5Operating Agreement, as amended on November 12, 2004, effective as of December 22, 2004, between the State of California Department of Water Resources and Pacific Gas and Electric Company (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.9)
*10.1210.6PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001, and frozen after December 31, 2004 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.10)
*10.1310.7PG&E Corporation Supplemental Retirement Savings Plan effective as of January 1, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.11)
*10.14Description of Compensation Arrangement between PG&E Corporation and Peter Darbee (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.3)
*10.1510.8Letter regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective July 1, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.4)
*10.1610.9Letter regarding Compensation ArrangementRestricted Stock Award Agreement between PG&E Corporation and Peter A. Darbee dated January 3, 2007 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 12348), Exhibit 10.3)
*10.10Retention Agreement between PG&E Corporation and Thomas B. King dated November 4, 1998 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended DecemberAugust 31, 2000 (File No. 1-12609), Exhibit 10.6)
*10.17Letter regarding Compensation Arrangement between PG&E Corporation and Thomas B. King dated June 18, 20032006 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended JuneSeptember 30, 20032006 (File No. 1-12609), Exhibit 10.3)10.2)
*10.1810.11Letter regarding Compensation Arrangement between Pacific Gas and Electric Company and William T. Morrow dated June 20, 2006 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (File No. 1-12609), Exhibit 10.1)
*10.12Restricted Stock Award Agreement between PG&E Corporation and William T. Morrow dated January 29, 2007 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609), Exhibit 10.4)
*10.13Performance Share Agreement between PG&E Corporation and William T. Morrow dated November 6, 2007
*10.14Restricted Stock Award Agreement between PG&E Corporation and William T. Morrow dated November 6, 2007

*10.15Letter regarding Compensation Arrangement between PG&E Corporation and Rand L. Rosenberg dated October 19, 2005
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*10.19Severance Agreement and Release by and between Pacific Gas and Electric Company and Gordon R. Smith dated September 21, 2005 (incorporated by reference to Pacific Gas and Electric Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005 (File No. 1-2348), Exhibit 10.1)
*10.20Actions taken by the Nominating, Compensation and Governance Committee of the PG&E Corporation Board of Directors on October 19, 2005, regarding the 2006 Officer Compensation Program (incorporated by reference to PG&E Corporation’s Quarterly Report on Form 10-Q10-K for the quarteryear ended September 30, 2005December 31, 2005) (File No. 1-12609), Exhibit 10.2)10.18)
*10.2110.16Letter regarding Compensation Arrangement between PG&E Corporation and Hyun Park dated October 10, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2006) (File No. 1-12609), Exhibit 10.18)
*10.17
Letter regarding Compensation Agreement between PG&E Corporation and G. Robert Powell dated
August 8, 2005
*10.18PG&E Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, effective as of January 1, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.17)
*10.2210.19Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 20062008
*10.2310.20Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 20052007 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.18)10.20)
*10.24Schedule of 2006 Base Salary and Short-Term Incentive Plan Target Participation Rates for certain officers of PG&E Corporation and its subsidiaries
*10.25Schedule of 2006 award values under the PG&E Corporation 2006 Long-Term Incentive Plan for certain officers of PG&E Corporation and its subsidiaries
*10.2610.21Supplemental Executive Retirement Plan of the Pacific Gas and Electric Company amended effective as of December 31, 2004, and frozen as of January 1, 2005 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004) (File No. 1-2348), Exhibit 10.20)
*10.2710.22Supplemental Executive Retirement Plan of PG&E Corporation as amended effective as of January 1, 2006
*10.28.1Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Robert D. Glynn, Jr. dated December 20, 2002 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-K for the year ended December 31, 20022005) (File No. 1-12609), Exhibit 10.37.1)
*10.28.2Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Bruce R. Worthington dated December 20, 2002 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.37.2)
*10.28.3Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gregory M. Rueger dated December 20, 2002 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2002 (File No. 1-12609 and File No. 1-2348), Exhibit 10.37.3)10.27)
*10.28.4Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gordon R. Smith dated December 20, 2002 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2002 (File No. 1-12609 and File No. 1-2348), Exhibit 10.37.4)
*10.29.1Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Robert D. Glynn, Jr. dated April 18, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.2.1)
*10.29.2Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gordon R. Smith dated April 18, 2003 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2.2)
*10.29.3Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gregory M. Rueger dated April 18, 2003 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2.4)
*10.29.4Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Bruce R. Worthington dated April 18, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.2.5)
*10.3010.23Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16)
*10.3110.24Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16)
*10.3210.25
PG&E Corporation Non-Employee Director Stock Incentive Plan (a component of the PG&E Corporation Long-Term Incentive Program) as amended effective as of July 1, 2004 (reflecting amendments adopted by the PG&E Corporation Board of Directors on June 16, 2004 set forth in resolutions filed as Exhibit 10.3 to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004) (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.27)
59 

*10.3310.26Resolution of the PG&E Corporation Board of Directors dated June 16, 2004,December 20, 2006, adopting director compensation arrangement effective January 1, 2007 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q10-K for the quarteryear ended June 30, 2004December 31, 2006 (File No. 1-12609 and File No. 12348), Exhibit 10.1)10.29)
*10.3410.27
Resolution of the Pacific Gas and Electric Company Board of Directors dated June 16, 2004,December 20, 2006, adopting director compensation arrangement effective January 1, 2007 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q10-K for the quarteryear ended June 30, 2004December 31, 2006 (File No. 1-12609 and File No. 12348), Exhibit 10.2)
10.30)
*10.3510.28
Resolution of the PG&E Corporation Board of Directors dated February 20, 2008, adopting director compensation arrangement effective January 1, 2008
*10.29Resolution of the Pacific Gas and Electric Company Board of Directors dated February 20, 2008, adopting director compensation arrangement effective January 1, 2008
*10.30PG&E Corporation 2006 Long-Term Incentive Plan, effective as of January 1, 2006, as amended on February 15, 2006 (with respect to change in control provisions) and December 20, 2006 and October 17, 2007 (with respect to Section 7 governing nondiscretionary awards to non-employee directors)

*10.3610.31PG&E Corporation Long-Term Incentive Program (including the PG&E Corporation Stock Option Plan and Performance Unit Plan), as amended May 16, 2001, (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10)
*10.3710.32Form of Restricted Stock Award Agreement for 2003 grants made under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.46)
*10.3810.33Form of Restricted Stock Award Agreement for 2004 grants made under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2003 (File No. 1-12609), Exhibit 10.37)
*10.3910.34Form of Restricted Stock Agreement for 2005 grants under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.3)
*10.4010.35Form of Restricted Stock Agreement for 2006 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 9, 2006, Exhibit 99.1)
*10.4110.36Form of Restricted Stock Agreement for 2007 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the PG&E Corporation 2006 Long-Term Incentive Plan made on February 15, 2006) (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.39)
*10.37Form of Non-Qualified Stock Option Agreement under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.1)
*10.4210.38Form of Performance Share Award Agreement for 2004 grants under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2003 (File No. 1-12609), Exhibit 10.38)
*10.4310.39Form of Performance Share Agreement for 2005 grants under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.2)
*10.4410.40Form of Performance Share Agreement for 2006 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 9, 2006, Exhibit 99.2)
*10.4510.41Form of Performance Share Agreement for 2007 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the PG&E Corporation 2006 Long-Term Incentive Plan made on February 15, 2006) (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.44)
*10.42PG&E Corporation Executive Stock Ownership Program Guidelines dated as of February 19, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609) Exhibit 10. 2)10.2)
*10.4610.43PG&E Corporation Executive Stock Ownership Program Guidelines as amended February 15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.46)
*10.4710.44PG&E Corporation Officer Severance Policy, as amended effective as of January 1, 2005 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.37)
*10.4810.45PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.48)

*10.4910.46PG&E Corporation Golden Parachute Restriction Policy effective as of February 15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.49)
*10.5010.47PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.1)
*10.5110.48PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998, as updated effective January 1, 2005 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.39)
*10.5210.49Resolution of the Board of Directors of PG&E Corporation regarding indemnification of officers and directors dated December 18, 1996 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.40)
 60

*10.5310.50Resolution of the Board of Directors of Pacific Gas and Electric Company regarding indemnification of officers and directors dated July 19, 1995 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-2348), Exhibit 10.41)
11Computation of Earnings Per Common Share
12.1Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
12.2Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
13
The following portions of the 20052007 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company are included: "Selected“Selected Financial Data," "Management's” “Management's Discussion and Analysis of Financial Condition and Results of Operations," financial statements of PG&E Corporation entitled "Consolidated“Consolidated Statements of Income," "Consolidated” “Consolidated Balance Sheets," "Consolidated” “Consolidated Statements of Cash Flows," and "Consolidated“Consolidated Statements of Shareholders' Equity," financial statements of Pacific Gas and Electric Company entitled "Consolidated“Consolidated Statements of Income," "Consolidated” “Consolidated Balance Sheets," "Consolidated” “Consolidated Statements of Cash Flows," and "Consolidated“Consolidated Statements of Shareholders' Equity," "Notes” “Notes to the Consolidated Financial Statements," and "Quarterly“Quarterly Consolidated Financial Data (Unaudited)," "Management's” “Management's Report on Internal Control Over Financial Reporting," "Report” “Report of Independent Registered Public Accounting Firm," and "Report“Report of Independent Registered Public Accounting Firm."
21Subsidiaries of the Registrant
23Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP)
24.1Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K
24.2Powers of Attorney
31.1Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
31.2Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
**32.1Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
**32.2Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002
*Management contract or compensatory agreement.


**Pursuant to Item 601(b) (32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.
61