10-K 1 form10k.htm PG&E CORP. AND PACIFIC GAS AND ELECTRIC COMPANY FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2005 Unassociated Document
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
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
1-12609
PG&E CORPORATION
California
94-3234914
1-2348
PACIFIC GAS AND ELECTRIC COMPANY
California
94-0742640
 
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, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one).:
PG&E Corporation
Large accelerated filer x
Accelerated filer ¨
Non-accelerated filer ¨
Pacific Gas and Electric Company
Large accelerated filer ¨
Accelerated filer ¨
Non-accelerated filer x
 
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, the last business day of the second fiscal quarter:
PG&E Corporation Common Stock
$13,975 million
Pacific Gas and Electric Company Common Stock
Wholly owned by PG&E Corporation
Common Stock outstanding as of February 10, 2006:
  
PG&E Corporation:
345,319,971 (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 2005 Annual Report to Shareholders
Part 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 2006
Part III (Items 10, 11, 12, 13 and 14)
Annual Meetings of Shareholders
  




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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





Corporate Structure and Business

PG&E Corporation, incorporated in California in 1995, is an energy-based holding company that conducts its business through Pacific Gas and Electric Company, or the 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 5 million electricity distribution customers and approximately 4.2 million natural gas distribution customers at December 31, 2005. The Utility had approximately $33.8 billion of assets at December 31, 2005, and generated revenues of approximately $11.7 billion in 2005. 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, and the Federal Energy Regulatory Commission, or the 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. 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.com, and the Utility's website, www.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, PG&E Corporation and its subsidiaries had approximately 19,800 employees, including approximately 19,500 employees of the Utility. Of the Utility's employees, approximately 12,800 are covered by collective bargaining agreements with three labor unions: the International Brotherhood of Electrical Workers, Local 1245, AFL-CIO, or IBEW; the Engineers and Scientists of California, IFPTE Local 20, AFL-CIO and CLC, or ESC; and the Service Employees International Union, Local 24/7, or 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, 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. These statements are based on current expectations and projections about future events, and assumptions regarding these events and management's knowledge of facts at the date of this report. These forward-looking statements are identified by words such as "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:

1

Operating Environment

·
How the Utility manages its responsibility to procure electric capacity and energy for its customers;
·
The adequacy and price of natural gas supplies, and the ability of the Utility to manage and respond to the volatility of the natural gas market for its customers;
·
Weather, storms, earthquakes, fires, floods, 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 to the Utility's assets or generating facilities, cause damage to the operations or assets of third parties on which the Utility relies, or subject the Utility to third party claims for damage or injury;
·
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;
·
Whether the Utility is required to cease operations temporarily or permanently at its Diablo Canyon nuclear power plant because the Utility is unable to increase its on-site spent nuclear fuel storage capacity, find another depositary for spent fuel, or timely complete the replacement of the steam generators, or because of mechanical breakdown, lack of nuclear fuel, environmental constraints, or for some other reason and the risk that the Utility may be required to purchase electricity from more expensive sources; and
·
Whether the Utility is able to recognize the anticipated cost benefits and savings expected to result from its efforts to improve customer service through implementation of specific initiatives to streamline business processes and deploy new technology.

Legislative Actions and Regulatory Proceedings

·
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.

The Utility's distribution network interconnects to the Utility's electricity transmission system at 671 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 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.

Total 2005 Electricity Delivered: 81,626 GWh

Agricultural and Other Customers
6%
Industrial Customers
18%
Residential Customers
36%
Commercial Customers
40%


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:

Owned generation (nuclear, fossil fuel-fired and hydroelectric facilities)
40%
DWR
27%
Qualifying Facilities/Renewables
22%
Irrigation Districts
5%
Other Power Purchases
6%

The Utility is required to dispatch all of 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 load 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 regarding the Utility's Hunters Point fossil fuel-fired plant, which has been designated as a "must run" facility by 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 1985 and the operating license for this unit expires in September 2021. Unit 2 began commercial operation in March 1986 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%.

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 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 replacement of the steam generators 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
                  
   Refueling
April
  
-
  
February
  
October
  
-
   Duration (days)
45
  
-
  
80
  
35
  
-
   Startup
June
  
-
  
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 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. 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

6

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 into 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:

·  
After assumption, the Utility's issuer rating by Moody's Investors Service, or Moody's, will be no less than A2 and the Utility's long-term issuer credit rating by Standard & Poor's, or S&P, will be no less than A;

·  
The CPUC first makes a finding that the DWR power purchase contracts to be assumed are just and reasonable; and

·  
The CPUC has acted to ensure that the Utility will receive full and timely recovery in its retail electricity rates of all costs associated with the DWR power purchase contracts to be assumed without further review.

The Settlement Agreement does not limit the CPUC's discretion to review the prudence of the Utility's administration and dispatch of the assumed DWR power purchase contracts consistent with applicable law.

7


Qualifying Facility Power Purchase Agreements

The Utility is required by CPUC decisions to purchase energy and capacity from independent power producers that are qualifying facilities under the Public Utility Regulatory Policies Act of 1978, or PURPA. To implement 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 require 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 implement 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 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) to sell electricity to a QF if certain conditions are met. The statute would permit 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 obligation to purchase for certain areas under the control of a regional transmission organization, 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 intends 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 its QF purchase obligations under this case-by-case approach. 

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, regardless of whether or not any hydroelectric power is supplied, and variable payments for operation and maintenance costs incurred 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.
 

8


Electricity Purchases to Satisfy the Net Open Position 

In 2005, the Utility continued buying 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 own generation facilities and existing electricity contracts. During 2005, more than 9,000 GWh of energy was bought or sold 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. The CPUC also has suggested that the 20% goal be met by 2010 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 renewable energy purchases to approximately 800-900 GWh. During 2005, the Utility entered into several new renewable power purchase contracts that will help the Utility meet its goals.

For more information regarding the Utility's power purchase contracts, see Note 17: Commitments and Contingencies— Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2005 Annual Report.


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.

In connection with electricity industry restructuring, the California investor-owned electric utilities relinquished control, but not ownership, of their transmission facilities to the California Independent System Operator, or the ISO, in 1998. The FERC has jurisdiction over these transmission facilities, and the revenue requirements and rates for transmission service are set by the FERC. The ISO, which is regulated by the FERC, controls the operation of the transmission system 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.

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.



10


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 Customers
28%
Transport-only Customers (noncore)
60%
Commercial Customers
12%


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):
                 
Residential
3,929,117
  
3,812,914
  
3,744,011
  
3,738,524
  
3,705,141
Commercial
216,749
  
215,547
  
208,857
  
206,953
  
205,681
Industrial
962
  
2,178
  
1,988
  
1,819
  
1,764
Other gas utilities
6
  
6
  
6
  
5
  
6
Total
4,146,834
  
4,030,645
  
3,954,862
  
3,947,301
  
3,912,592
Gas supply (MMcf):
                 
Purchased from suppliers in:
                 
Canada
204,884
  
205,180
  
196,278
  
210,716
  
209,630
California
(18,951)
  
(9,108)
  
(7,421)
  
19,533
  
20,352
Other states
103,237
  
103,801
  
102,941
  
67,878
  
76,589
Total purchased
289,170
  
299,873
  
291,798
  
298,127
  
306,571
Net (to storage) from storage
(3,659)
  
(532)
  
1,359
  
(218)
  
(27,027)
Total
285,511
  
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 sales
271,199
  
280,054
  
278,850
  
281,516
  
270,556
Bundled gas sales (MMcf):
                 
Residential
194,108
  
201,601
  
198,580
  
202,141
  
197,184
Commercial
77,056
  
78,080
  
79,891
  
78,812
  
72,528
Industrial
35
  
373
  
379
  
563
  
831
Other gas utilities
—
  
—
  
—
  
—
  
13
Total
271,199
  
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
Commercial
885
  
712
  
697
  
499
  
783
Industrial
—
  
—
  
1
  
3
  
16
Other gas utilities
—
  
—
  
1
  
1
  
—
Miscellaneous
(22)
  
(29)
  
(31)
  
127
  
(93)
Regulatory balancing accounts
340
  
316
  
68
  
11
  
(253)
Bundled gas revenues
3,539
  
2,943
  
2,572
  
2,020
  
2,761
Transportation service only revenue
238
  
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
Commercial
11.48
  
9.12
  
8.73
  
6.33
  
10.80
Industrial
0.61
  
(0.56)
  
2.48
  
4.35
  
19.15
Average billed transportation only revenue per Mcf
0.42
  
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.
11

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.

12

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 where 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 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.


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. 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 also issued its own comprehensive energy market design proposal to effect changes to the structure and operation of the California electricity market. The first phase of the ISO’s new market design has been approved by the FERC and was implemented by the ISO in the fourth quarter of 2004. On February 14, 2006, the ISO filed its proposed tariff language with the FERC to implement the balance of its market design proposal. Assuming FERC approval, the balance of the ISO’s new market design could be implemented as early as November 2007.

13


In July 2003, in order 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 generator and transmission infrastructure, the FERC issued final rules on the interconnection of generators larger than 20 MW with 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 codify the FERC's preexisting policy regarding financing of transmission system upgrades needed in order to interconnect a new generator. Under this policy, the generator must finance such upgrade facilities in the first instance, but then is 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 Utility in its overall transmission rates.

In 1998, California implemented AB 1890, which mandated the restructuring of the California electricity industry and established a market framework for electricity generation in which generators and other electricity providers were permitted to charge market-based prices for wholesale electricity. AB 1890 also gave customers the choice of continuing to buy electricity from the California investor-owned electric utilities or, beginning in April 1998, entering into contracts to purchase electricity from alternate energy service providers (i.e., becoming direct access customers). The CPUC suspended the right of retail end-user customers to become direct access customers on September 20, 2001. 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.

California AB 117 permits cities and counties to purchase and sell electricity for their local residents and businesses once they have registered as community choice aggregators. Under AB 117, the Utility would continue to provide distribution, metering and billing services to the community choice aggregators' customers and 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. 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. AB 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 of community choice aggregation.


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 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.

The Utility’s pipeline operations are subject to the jurisdiction of the CPUC. In 1998, the Utility implemented the Gas Accord settlement agreement, a CPUC-approved settlement agreement reached among the Utility and many interested parties under which the natural gas transportation and storage services the Utility provides were separated for ratemaking purposes from the Utility's distribution services. The Gas Accord changed 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.

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

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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, along with Fort Chicago Energy Partners, L.P. and Northwest Pipeline Corporation, have agreed to jointly pursue the development of a new 250-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 Jordan Cove liquefied natural gas, or LNG, terminal in Coos Bay, Oregon, being developed by Fort Chicago 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 Pacific Connector project would connect the proposed Jordan Cove LNG terminal to Northwest Pipeline Corporation’s pipeline system near Roseburg, Oregon, and to the Utility's backbone gas transmission system near Malin, Oregon. The Pacific Connector 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 intends to seek market commitments for the proposed pipeline project and to begin environmental assessments along the proposed route in April 2006. The group plans to file an application to seek the FERC's approval for the new pipeline by January 2007. Subject to regulatory approval, the proposed LNG terminal and pipeline are anticipated to begin commercial operation in 2010.


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, PG&E Corporation and its subsidiaries were exempt from most of PUHCA’s requirements.
 
In August 2005, a comprehensive federal energy bill named 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. 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 PUHCA is expected to trigger a period of consolidation among public utilities, as well as

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acquisitions of public utilities by other businesses. As a result, 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 Corporation 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 1996 and 1999 related to finance, human resources, records and bookkeeping, and the transfer of customer information. In 2004, the California Court 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 obligations 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&E Corporation and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules and orders.

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.

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. Before rates can be set, the CPUC and the FERC must determine the amount of “revenue requirements” the Utility is authorized to collect from its customers to recover the Utility’s operating and capital costs. The CPUC determines the Utility’s revenue requirements associated with electricity and gas distribution operations, electricity generation, and natural gas transportation and storage. 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.

Revenue requirements are designed to allow a utility an opportunity to recover its reasonable costs of providing utility services, including a return of, and a fair rate of return on, its investment in utility facilities, or 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, the Utility may be unable to earn its authorized rate of return.

General Rate Cases

The Utility's primary revenue requirement proceeding is the general rate case, or GRC, filed with the CPUC. In the GRC, the CPUC authorizes the Utility to collect from customers an amount known as base revenues to recover base business and operational costs related to the Utility's electricity and natural gas distribution and electricity generation operations. The GRC typically sets annual revenue requirement levels for a three-year rate period. The CPUC authorizes these revenue requirements in GRC proceedings 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 Office of Ratepayer Advocate, or ORA, and The Utility Reform Network, or TURN. On December 2, 2005, the Utility filed its 2007 GRC application with the CPUC. For more information, see “Regulatory Matters—2007 General Rate Case” in the MD&A in the 2005 Annual Report.

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 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.

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 that 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 debt 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 a capital structure for the Utility consisting of 46% long-term debt, 2% preferred stock and 52% equity. The CPUC set the 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% for long-term debt, 5.87% for preferred stock and 11.35% for equity, resulting in an overall rate of return on rate base of 8.79%. 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. 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, the CPUC has authorized the Utility to collect revenue requirements of approximately $250 million from electricity customers to fund these electricity public purpose programs and to collect revenue requirements of approximately $40 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 public interest research and development program and the renewable energy program on a statewide basis. In 2005, the Utility transferred $102 million to the CEC for these two programs.

On September 22, 2005, the CPUC authorized 2006 through 2008 energy efficiency portfolio plans and program funding levels, not including funding for evaluation, measurement and verification activities, or EM&V, for 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 to 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 advantage of the diverse mix of energy efficiency programs.


On January 12, 2006, the CPUC authorized increased funding to provide customer incentives and set additional policies to develop solar resources in California over the next 11 years, 2006 through 2017. This program, called the California Solar Initiative, or CSI, was designed with the objective of bringing 3,000 MW of solar power on-line by 2017. The CPUC’s decision consolidates existing and anticipated solar incentives 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, the CPUC authorized the California investor-owned utilities to collect an additional $2.8 billion over the 2006 through 2017 period from their customers to fund customer incentives for the installation of retail solar energy projects to serve onsite load. The intent of the CSI is to 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, the 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.


As a consequence of the California energy crisis and the resulting inability of the California investor-owned utilities 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 purchase 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 purchase 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 have been allocated to the utilities.

The DWR pays for its costs of purchasing electricity from a revenue requirement collected from electricity customers of the three California investor-owned electric utilities through what is known as a power charge. The Utility's customers also must pay what is known as a 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 the Utility acts as a billing and collection agent for the DWR, amounts collected for the DWR and any adjustments are not included in the Utility's revenues.


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:
     
 
Ø
procure the maximum amount of renewable generation resources, and be prepared to defend any selection of fossil-fuel generation resources over renewable resources,
     
 
Ø
employ 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
     
 
Ø
employ 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 revenues and its wholesale and retail transmission rates are subject to authorization by the FERC. The Utility has two 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. These 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 rate cases and are included by the CPUC in the Utility's retail electricity rates and collected from retail electricity customers receiving bundled service under the federal filed rate doctrine.

Transmission Owner Rate Cases

Under the FERC's regulatory regime, the Utility is able to file a new base transmission rate case under the Utility's transmission owner tariff whenever the Utility deems it necessary to increase its rates within certain guidelines set forth by the FERC. The Utility is typically able to charge new rates, subject to refund, before the outcome of the FERC ratemaking review process.

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.

The Utility derives the majority of the Utility's transmission revenue from base transmission rates.

Transmission Control Agreement

The Utility has entered into a Transmission Control Agreement, or TCA, with the ISO and other participating transmission owners (including Southern California Edison, or SCE, San Diego Gas & Electric Company, and several California municipal utilities) under which the transmission owners have assigned operational control of their electricity transmission systems to the ISO. The Utility is required to give the ISO two years’ notice and receive approval from the FERC if it wishes to withdraw from the TCA.

Reliability Must Run Agreements

The ISO also has entered into reliability must run, or RMR, agreements with various power plant owners, including 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 users of the ISO-controlled electricity transmission grid. The ISO's transmission access charge methodology approved by the FERC in December 2004 provides for transition over a 10-year period to a uniform statewide high-voltage transmission rate, based on the revenue requirements of all participating transmission owners associated with facilities operated at 200 kV and above. The transmission access charge methodology may result in a cost shift from transmission owners whose costs for existing transmission are higher than that embedded in the uniform rate, to transmission owners with lower embedded costs for existing 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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The Gas Accord

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, the CPUC approved a multi-party settlement agreement to retain the Gas Accord market structure, and resolve the rates, and terms and conditions of service for the Utility's natural gas transportation and storage system for the three-year period of 2005 through 2007. The Utility continues to be at risk of not recovering its natural gas transportation and storage costs 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.

Biennial Cost Allocation Proceeding

Certain of the Utility's natural gas distribution costs and balancing account balances are allocated to customers in the 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 CPIM is used to determine the reasonableness of the Utility's costs of purchasing natural gas for its customers. Under the CPIM, the Utility's natural gas purchase costs (including Canadian and interstate capacity and volumetric transportation charges) for a 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% and 102% of the benchmark, are considered reasonable and are fully recoverable 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-fourths of the savings when the costs are below 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 associated 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 awards are not included in earnings until approved by the CPUC.
 
In response to rising natural gas prices, on October 6, 2005, the CPUC granted the Utility authority to purchase hedges 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 portions 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 under the CPIM for the 2004-2005 CPIM year.

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.

Interstate and Canadian Natural Gas Transportation and Storage

The Utility's interstate and Canadian natural gas transportation agreements with third 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.



The following discussion includes certain forward-looking information relating to estimated expenditures for environmental protection measures and the possible future impact of environmental compliance. The information below reflects current estimates that 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 discharge of pollutants into air, water and soil;

·  
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

·  
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 up or decommission waste disposal areas at the Utility's current or former facilities and at third-party sites where the Utility may have disposed of wastes.

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 (e.g., for cleaning up the Utility's facilities and sites where the Utility has sent hazardous substances) from customers. This mechanism allows the Utility to include 90% of the 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 are assigned to the Utility's customers. The balance of any insurance recoveries, (90%) are 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 be 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 are retained by the Utility; 90% of any such recoveries are assigned to the Utility's customers.   

Hazardous waste remediation costs are rising and likely to be significant into the foreseeable future. Based on the Utility's past experience, it believes 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 generation plants and natural gas pipeline operations are subject to numerous air pollution control laws, including the federal Clean Air Act and similar 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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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, 2004 and 2005, various multi-pollutant initiatives were introduced in the U.S. Senate and House of Representatives. These initiatives proposed limits on the emissions of nitrogen oxide, sulfur dioxide, mercury and carbon dioxide, and some would allow the use of trading mechanisms to achieve or maintain compliance with the proposed rules. Although these initiatives were not enacted into law, similar legislation is expected to be introduced 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. 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 which the Utility expects to recover through rates.

In addition, current federal and state regulatory initiatives relating to emissions of carbon dioxide and other greenhouse gases, particulates and other toxic pollutants could increase 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, 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 to recover these costs and capital expenditures in rates.


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" cooling water system that is regulated under a National Pollutant Discharge Elimination System, or NPDES, permit issued by the Central Coast Regional Water Quality Control Board, or Central Coast Board. This permit allows the Diablo Canyon power plant to discharge the cooling water at an average 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 January 2005, the Central Coast Board published a draft report prepared by a team of scientists recommending several measures to mitigate the effect of the cooling water system. 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 EPA published regulations under Section 316(b) of the Clean Water Act for cooling water intake structures. The regulations affect existing electricity generation facilities using over 50 million gallons per day, typically including some form of "once-through" cooling. The Utility's Diablo Canyon, Hunters Point and Humboldt Bay power plants are among an estimated 539 generation facilities nationwide that are affected by this rulemaking. The 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. The regulations allow site-specific compliance

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determinations if a facility's cost of compliance is significantly greater than either the benefits achieved or the compliance costs considered by the EPA. The Utility is developing compliance strategies for each plant.

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 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 ensure 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 it 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 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.


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 near the Utility's facilities or operations. The Utility is seeking to secure "habitat conservation 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, and the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, or 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. 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 substance 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.

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, the vast majority of PCBs existing 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 that may remain at some sites contain chemical compounds that now are classified as hazardous. The Utility owns all or a portion of 27 manufactured gas plant sites. The Utility has a program, in cooperation with environmental agencies, to evaluate and take appropriate action to mitigate any potential health or environmental hazards at these sites. The Utility spent approximately $2 million in 2005 and expects to spend approximately $5 million in 2006 on these projects. The Utility expects that expenses 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 territory are now owned by others. The Utility spent approximately $4.1 million settling third-party remediation claims by the current owners of former manufactured gas plant sites in 2005 and it is possible that the Utility may incur additional clean-up costs related to these sites in the future if hazardous substances for which the Utility has liability are found.

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 eight 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 studies and any necessary remedial measures by regulatory agencies. At the Casmalia disposal facility near Santa Maria, California, the Utility and several other generators of 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 mitigation 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.

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, 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. 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 million at December 31, 2005 and approximately $327 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. 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's undiscounted future costs could increase to as much as $680 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 of approximately $680 million does not include an estimate for the cost of remediation at known sites owned or operated in the past by the Utility's predecessor corporations for which the Utility has not been able to determine whether a liability exists.


Under the Nuclear Waste Policy Act of 1982, or Nuclear Waste Act, the DOE is responsible for the transportation, and permanent storage and disposal of spent nuclear fuel and high-level radioactive waste. Under the Nuclear Waste Act, utilities are required to provide interim storage facilities until permanent storage facilities are provided by 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 the spent nuclear fuel and high-level radioactive waste from the Utility's nuclear power facilities beginning not later than January 1998. The DOE has been unable to meet its contractual commitment to begin accepting spent fuel. First, there was a delay in identifying a storage site. Then, after 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's contract with the DOE, if the DOE completes a storage facility by 2010, the earliest Diablo Canyon's spent fuel would be accepted for storage or disposal would be 2018.

On January 22, 2004, the Utility filed separate complaints in 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 interveners appealed the NRC's decision to the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit. The Ninth Circuit heard oral argument on the appeal in October 2005, and a decision is pending. PG&E Corporation and the Utility cannot predict the outcome of this appeal.

In April 2004, San Luis Obispo County (the California county where Diablo Canyon 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 requires 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 and will be subject to a one-year study process. Construction of the on-site dry cask storage facility began in the third quarter 2005 and 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 NRC authorized the Utility to install a temporary storage rack in each unit's existing 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. 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.

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In July 1988, the NRC gave the Utility final approval to store radioactive waste from the Utility's retired nuclear generating facility, Humboldt Bay Unit 3, at the plant until 2015 before ultimately decommissioning the unit. The Utility has agreed to remove all spent fuel when the federal disposal site is available. In 1988, the Utility completed the first step in the decommissioning 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.

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, 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 storage 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 eventual decommissioning of Diablo Canyon Unit 1 is scheduled to begin in 2021 and to be completed in 2040. Decommissioning of Diablo Canyon Unit 2 is scheduled to begin in 2025 and to be completed in 2041, and decommissioning of Humboldt Bay Unit 3 is scheduled to begin in 2009 and to be completed in 2015.

As presented in 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's estimated nuclear decommissioning obligation as recorded in accordance with GAAP and 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 labor costs into the fair value calculation.

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 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

30

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, see Note 13 of the Notes to the Consolidated Financial Statements in the 2005 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, 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, based primarily on its review of studies by others, evaluating the possible risks from EMFs, to the CPUC and the public. 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 is 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 mitigate 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

31

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. 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 alleged 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, the 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.


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 Factors” in the 2005 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.


Not applicable.


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 Utility Operations" and "Gas Utility Operations." In total, the Utility occupies 8.2 million square feet of real property, including 7.0 million square feet the Utility owns. Of the 8.2 million square feet of occupied real property, approximately 1.5 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 1.5 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

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 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 Settlement Agreement, the Utility formed an entity, the Pacific Forest Watershed Lands Stewardship Council, or the Council, to oversee the development and implementation of a Land Conservation Plan, or LCP, that will articulate the long-term management objectives for the 140,000 acres. The Council is guided by an 18-member Board of Directors that represent 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 one out of 18 members of the Board of Directors of the Council. The Council is charged to adopt and present the LCP to the Utility by April 2007. The Utility 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" cooling water system that is regulated under a NPDES permit issued by the Central Coast Regional Water Quality Control Board, or Central Coast 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 to 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 Coast 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 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 Utility believes that the ultimate outcome of this matter will not have a material adverse impact on the 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, 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. 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 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 at least

34

$5.2 billion from the Utility," and for unjust enrichment. The City and County of San Francisco, or 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 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" 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 notices of removal in the Bankruptcy Court to transfer the complaints to the Bankruptcy Court. Subsequently, the plaintiffs filed motions to remand their actions to state court. In June 2002, the Bankruptcy Court held that federal law preempted the California Attorney General’s allegations concerning PG&E Corporation’s participation in the Utility’s bankruptcy proceedings. 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 coordinated the California Attorney General’s case with the case filed by CCSF.  

On October 8, 2003, the District Court reversed, in part, the Bankruptcy Court’s June 2002 decision and ordered that the plaintiffs’ restitution claims under Section 17200 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’s Chapter 11 estate and are therefore properly within the Bankruptcy Court’s jurisdiction. The District Court also affirmed, 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 order to the Ninth Circuit.

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 the 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

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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.

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. 


The following 12 civil suits are pending against the Utility relating to alleged chromium contamination: (1) Aguayo v. Pacific Gas and Electric Company, filed March 15, 1995, 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 1,000 of the current plaintiffs filed claims in the Utility’s Chapter 11 proceeding requesting compensatory damages in an approximate aggregate amount of $500 million and others filed claims for an "unknown amount." These claims were not discharged when the Utility’s plan of reorganization became effective.

In general, plaintiffs and claimants allege that exposure 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 million to the settling plaintiffs. The Utility will deposit the settlement amount into escrow on April 21, 2006. The settling plaintiffs are required 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 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.
 

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The Utility has recorded a $314 million reserve in its financial statements with respect to the Chromium Litigation. PG&E Corporation and the Utility do not expect that the outcome with respect to the remaining unresolved claims will have a material adverse effect on their financial condition or results of operations.
 


Not applicable.



The names, ages and positions of PG&E Corporation "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, at February 1, 2006, are as follows:


Name
  
Age
  
Position
         
P. A. Darbee
  
53
  
Chairman of the Board, Chief Executive Officer and President
L. H. Everett
  
55
  
Senior Vice President, Communications and Public Affairs
K.M. Harvey
  
47
  
Senior Vice President and Chief Risk and Audit Officer
R. M. Jackson
  
48
  
Senior Vice President, Human Resources
C. P. Johns
  
45
  
Senior Vice President, Chief Financial Officer and Treasurer
T. B. King
  
44
  
Senior Vice President; President and Chief Executive Officer, Pacific Gas and Electric Company
R. L. Rosenberg
  
52
  
Senior Vice President, Corporate Strategy and Development
B. R. Worthington
  
56
  
Senior Vice President and General Counsel

All officers of PG&E Corporation serve at the pleasure of the Board of Directors. During the past five years, 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. A. Darbee
  
Chairman of the Board, Chief Executive Officer and President
  
January 1, 2006 to present
   
Chairman of the Board, Pacific Gas and Electric Company
  
January 1, 2006 to present
   
President and Chief Executive Officer
  
January 1, 2005 to December 31, 2005
   
Senior Vice President and Chief Financial Officer
  
July 9, 2001 to December 31, 2004
   
Senior Vice President, Chief Financial Officer, and Treasurer
  
September 20, 1999 to July 8, 2001
         
L. H. Everett
  
Senior Vice President, Communications and Public Affairs
  
January 9, 2006 to present
   
Senior Vice President and Assistant to the Chief Executive Officer
  
January 1, 2005 to January 8, 2006
   
Senior Vice President and Assistant to the Chairman
  
August 2, 2004 to December 31, 2004
   
Vice President and Assistant to the Chairman
  
June 1, 2001 to August 1, 2004
   
Vice President, Corporate Secretary, and Assistant to the Chairman
  
May 1, 2001 to May 31, 2001
   
Vice President and Corporate Secretary
  
July 1, 1997 to April 30, 2001
   
Vice President and Corporate Secretary, Pacific Gas and Electric Company
  
November 1, 1996 to May 31, 2001
         
K. 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 Company
  
January 1, 2000 to October 31, 2000
         
R. M. Jackson
  
Senior Vice President, Human Resources, PG&E Corporation and Pacific Gas and Electric Company
  
August 2, 2004 to present
   
Vice President, Human Resources, PG&E Corporation
  
June 1, 2004 to August 1, 2004
   
Vice President, Human Resources, Pacific Gas and Electric Company
  
June 1, 1999 to August 1, 2004
         
C. P. Johns
  
Senior Vice President, Chief Financial Officer and Treasurer
  
October 4, 2005 to present
   
Senior Vice President, Chief Financial Officer and Treasurer, Pacific Gas and Electric Company
  
October 1, 2005 to present
   
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 1, 1997 to September 18, 2001
         
T. B. King
  
Senior Vice President, PG&E Corporation
  
January 1, 2006 to present
   
President and Chief Executive Officer, Pacific Gas and Electric Company
  
January 1, 2006 to present
   
Executive Vice President and Chief Operating Officer, Pacific Gas and Electric Company
  
July 1, 2005 to December 31, 2005
   
Executive Vice President and Chief of Utility Operations, Pacific Gas and Electric Company
  
August 2, 2004 to June 30, 2005
   
Senior Vice President and Chief of Utility Operations, Pacific Gas and Electric Company
  
November 1, 2003 to August 1, 2004
   
Senior Vice President, PG&E Corporation
  
January 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 Corporation
  
August 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 Corporation
  
November 23, 1998 to September 10, 2002
         
R. 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. R. Worthington
  
Senior Vice President and General Counsel
  
June 1, 1997 to present
 

37

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


Name
  
Age
  
Position
         
P.A. Darbee
  
53
  
Chairman of the Board
T. B. King
  
44
  
President and Chief Executive Officer
T. E. Bottorff
  
52
  
Senior Vice President, Regulatory Relations
J. D. Butler
  
50
  
Senior Vice President, Energy Delivery
L.H. Everett
  
55
  
Senior Vice President, Communications and Public Affairs, PG&E Corporation
R.M. Jackson
  
48
  
Senior Vice President, Human Resources
C. P. Johns
  
45
  
Senior Vice President, Chief Financial Officer and Treasurer
J. S. Keenan
  
57
  
Senior Vice President, Generation and Chief Nuclear Officer
S. M. Ramsay
  
47
  
Vice President, Asset Management and Electric Transmission
F Wan
  
44
  
Vice President, Energy Procurement
B. R. Worthington
  
56
  
Senior Vice President and General Counsel, PG&E Corporation

All officers of the Utility serve at the pleasure of the Board of Directors. During the past five years through February 1, 2006, 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. A. Darbee
  
Chairman of the Board, Pacific Gas and Electric Company
  
January 1, 2006 to present
   
Chairman of the Board, Chief Executive Officer and President, PG&E Corporation
  
January 1, 2006 to present
   
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 to July 8, 2001
         
T. B. King
  
President and Chief Executive Officer
  
January 1, 2006 to present
   
Senior Vice President, PG&E Corporation
  
January 1, 2006 to present
   
Executive Vice President and Chief Operating Officer
  
July 1, 2005 to December 31, 2005
   
Executive Vice President and Chief of Utility Operations
  
August 2, 2004 to June 30, 2005
   
Senior Vice President and Chief of Utility Operations
  
November 1, 2003 to August 1, 2004
   
Senior Vice President, PG&E Corporation
  
January 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 Corporation
  
August 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 Corporation
  
November 23, 1998 to September 10, 2002
         
T. 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. Butler
  
Senior Vice President, Energy Delivery
  
January 9, 2006 to present
   
Senior Vice President, Transmission and Distribution
  
March 1, 2004 to January 8, 2006
   
Vice President, Operations, Maintenance and Construction
  
June 12, 2000 to February 29, 2004
         
L. H. Everett
  
Senior Vice President, Communications and Public Affairs, PG&E Corporation
  
January 9, 2006 to present
   
Senior Vice President and Assistant to the Chief Executive Officer, PG&E Corporation
  
January 1, 2005 to January 8, 2006
   
Senior Vice President and Assistant to the Chairman, PG&E Corporation
  
August 2, 2004 to December 31, 2004
   
Vice President and Assistant to the Chairman, PG&E Corporation
  
June 1, 2001 to August 1, 2004
   
Vice President, Corporate Secretary, and Assistant to the Chairman, PG&E Corporation
  
May 1, 2001 to May 31, 2001
   
Vice President and Corporate Secretary, PG&E Corporation
  
July 1, 1997 to April 30, 2001
   
Vice President and Corporate Secretary
  
November 1, 1996 to May 31, 2001
         
R. M. Jackson
  
Senior Vice President, Human Resources, Pacific Gas and Electric Company and PG&E Corporation
  
August 2, 2004 to present
   
Vice President, Human Resources, PG&E Corporation
  
June 1, 2004 to August 1, 2004
   
Vice President, Human Resources
  
June 1, 1999 to August 1, 2004
         
C. P. Johns
  
Senior Vice President, Chief Financial Officer and Treasurer
  
October 1, 2005 to present
   
Senior Vice President, Chief Financial Officer and Treasurer, PG&E Corporation
  
October 4, 2005 to present
   
Senior Vice President, Chief Financial Officer and Controller, PG&E Corporation
  
January 1, 2005 to October 3, 2005
   
Senior Vice President and Controller, PG&E Corporation
  
September 19, 2001 to December 31, 2004
   
Vice President and Controller, PG&E Corporation
  
July 1, 1997 to September 18, 2001
         
J. S. Keenan
  
Senior Vice President, Generation and Chief Nuclear Officer
  
December 19, 2005 to present
   
Vice President, Fossil Generation, Progress Energy
  
November 10, 2003 to December 18, 2005
   
Vice President, Brunswick Nuclear Plant, Progress Energy
  
May 1, 1998 to November 9, 2003
         
S. M. Ramsay
  
Vice 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.
  
January 2, 2001 to September 30, 2001
         
F. 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. Worthington
  
Senior Vice President and General Counsel, PG&E Corporation
  
June 1, 1997 to present


38



(a) As of February 1, 2006, there were 98,083 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 Consolidated Financial Data (Unaudited)" in the 2005 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's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Financial Resources—Dividends" of the 2005 Annual Report.

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 5,066,931 shares of 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 Company did not redeem or repurchase any shares of its various series of preferred stock outstanding.

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 Financial Data" in the 2005 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 results of operations and financial condition is set forth under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the 2005 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 2005 Annual Report under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations—Risk Management Activities," and under Notes 1 and 12 of the "Notes to the Consolidated Financial Statements" of the 2005 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 2005 Annual Report under the following headings for PG&E Corporation: "Consolidated Statements of Income," "Consolidated Balance Sheets," "Consolidated Statements of Cash Flows," and "Consolidated Statements of Shareholders' Equity;" under the following headings for Pacific Gas and Electric Company: "Consolidated Statements of Income," "Consolidated Balance Sheets," "Consolidated Statements of Cash Flows," and "Consolidated Statements of Shareholders' Equity;" and under the following headings for PG&E Corporation and Pacific Gas and Electric Company jointly: "Notes to the Consolidated Financial Statements," "Quarterly Consolidated Financial Data (Unaudited)," and "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.

39


Based on an evaluation of PG&E Corporation's and the Utility's disclosure controls and procedures as of December 31, 2005, 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 the companies file or submit under the Securities and Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms.

There were no changes in internal control over financial reporting that occurred during the quarter ended December 31, 2005 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 2005 Annual Report to Shareholders under the heading "Management's Report on Internal Control Over Financial Reporting" and "Report of Independent Registered Public Accounting Firm," which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.
 
 
 
In response to a shareholder proposal that was approved at PG&E Corporation’s 2005 annual meeting of shareholders on February 15, 2006, the Board of Directors of PG&E Corporation, or the Board, adopted a Golden Parachute Restriction Policy that became effective on February 15, 2006, subject to existing contractual obligations. This policy requires that the holders of a majority of the shares represented and voting approve executive severance payments provided in connection with a change in control 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 control and the termination or constructive termination of an officer covered by the PG&E Corporation Officer Severance Policy. It does not apply to 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 Committee 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 2006 Short-Term Incentive Plan, or STIP, under which officers of PG&E Corporation and the Utility are provided an opportunity to receive annual incentive cash payments. For these officers, corporate financial performance, as measured by corporate earnings from operations, will account for 70 percent of the award and Utility operational performance, as measured by 11 equally weighted financial, operating, and service measures, will account for 30 percent of the award. At its meeting on February 15, 2006, the Committee approved the specific performance scale that will be used to determine the extent to which the corporate financial objective, as measured by earnings from operations, has been met. The Committee used the same methodology to establish the performance scale for the corporate financial performance portion of the 2006 STIP as was used for the 2005 STIP. The corporate financial performance measure is based on PG&E Corporation's budgeted earnings from operations that were previously approved by the Board, 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 2006 performance targets for each of the 11 equally weighted financial, operating, and service measures that will be used to determine whether the portion of the STIP award 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 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.
 
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.
 

 
The Chief Executive Officer of PG&E Corporation has the discretion to recommend to the Committee an additional performance rating for an individual officer. This rating will be determined by such officer’s efforts 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 discretion as to the determination of final officer STIP awards.
 



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 Officers of the Registrants" at the end of Part I of this report. Other information responding to Item 10 is included under the heading "Item No. 1: Election of Directors of PG&E Corporation and Pacific Gas and Electric Company" and under the heading "Section 16(a) Beneficial Ownership Reporting Compliance" in the Joint Proxy Statement relating to the 2006 Annual Meetings of Shareholders, which information is hereby incorporated by reference.

Website Availability of Corporate Governance and Other Documents

The following documents are available both on PG&E Corporation's website www.pgecorp.com, and Pacific Gas and Electric Company's website, www.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. Shareholders also may obtain print copies of these documents by submitting a written request to Linda Y.H. Cheng, 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.

Item 11. Executive Compensation

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 Table," "Option/SAR Grants in 2005," "Aggregated Option/SAR Exercises in 2005 and Year-End Option/SAR Values," "Long-Term Incentive Program—Awards in 2005," "Retirement Benefits," and "Employment Contracts, Termination of Employment, and Change In Control Provisions" in the Joint Proxy Statement relating to the 2006 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 Ownership of Management" and under the heading "Principal Shareholders" in the Joint Proxy Statement relating to the 2006 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, 2005 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
  
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 Relationships and Related Transactions" in the Joint Proxy Statement relating to the 2006 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 Regarding the Independent Registered Public Accounting Firm of PG&E Corporation and Pacific Gas and Electric Company" in the Joint Proxy Statement relating to the 2006 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 2005 Annual Report and are incorporated by reference in this report:

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

Consolidated Balance Sheets at December 31, 2005, and 2004 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, and 2003, 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, 2005 and 2004 and for the Years Ended December 31, 2005, 2004, and 2003.

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, and 2003.

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:

Exhibit
Number
Exhibit Description
2.1
Order 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)
2.2
Order 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)
3.1
Restated 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)
3.2
Certificate 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)
3.3
Bylaws of PG&E Corporation amended as of January 1, 2006
3.4
Restated 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)
3.5
Bylaws of Pacific Gas and Electric Company amended as of January 1, 2006
4.1
Indenture, 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)
4.2
Indenture 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).
4.3
Supplemental 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)
4.4
Warrant 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)
10.1
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)
10.2
First Amendment, dated as of November 30, 2005, to the Credit Agreement among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JPMorgan Chase Bank, N.A., as syndication agent and a lender, Barclays Bank PLC 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.
10.3
Credit Agreement, 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 York (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed December 15, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 99)
 
45 
 
 
10.4
First Amendment, dated as of April 8, 2005, to the Credit Agreement dated as of December 10, 2004, among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities Inc., as syndication agent and a lender, 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, KBC Bank N.V., and The Bank of New York (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 10.2)
10.5
Master Confirmation dated November 16, 2005, for accelerated share repurchase arrangements between PG&E Corporation and Goldman, Sachs & Co.
10.6
Settlement 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)
10.7
Firm 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)
10.8
Operating 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)
10.9
PG&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)
10.10
Transmission 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)
10.11
Operating 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)
*10.12
PG&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
 
 
*10.13
PG&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)
*10.14
Description 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)
*10.15
Letter regarding Compensation Arrangement between PG&E Corporation and Peter 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)
*10.16
Letter regarding Compensation Arrangement 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 December 31, 2000 (File No. 1-12609), Exhibit 10.6)
*10.17
Letter regarding Compensation Arrangement between PG&E Corporation and Thomas B. King dated June 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 10.3)
*10.18
Letter regarding Compensation Arrangement between PG&E Corporation and Rand L. Rosenberg dated October 19, 2005
*10.19
Severance 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)
*10.20
Actions 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-Q for the quarter ended September 30, 2005 (File No. 1-12609), Exhibit 10.2)
*10.21
PG&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)
*10.22
Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2006
*10.23
Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, 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 10.18)
*10.24
Schedule of 2006 Base Salary and Short-Term Incentive Plan Target Participation Rates for certain officers of PG&E Corporation and its subsidiaries
*10.25
Schedule of 2006 award values under the PG&E Corporation 2006 Long-Term Incentive Plan for certain officers of PG&E Corporation and its subsidiaries
*10.26
Supplemental 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)
*10.27
Supplemental Executive Retirement Plan of PG&E Corporation as amended effective as of January 1, 2006
*10.28.1
Agreement 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's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.37.1)
*10.28.2
Agreement 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)
*10.28.3
Agreement 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)
*10.28.4
Agreement 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)
*10.29.1
Agreement 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
 
 
*10.29.2
Agreement 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)
*10.29.3
Agreement 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)
*10.29.4
Agreement 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)
*10.30
Pacific 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)
*10.31
Postretirement 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)
*10.32
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)
*10.33
Resolution of the PG&E Corporation Board of Directors dated June 16, 2004, adopting director compensation arrangement (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, 2004 (File No. 1-12609 and File No. 12348), Exhibit 10.1)
*10.34
Resolution of the Pacific Gas and Electric Company Board of Directors dated June 16, 2004, adopting director compensation arrangement (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, 2004 (File No. 1-12609 and File No. 12348), Exhibit 10.2) 
*10.35
PG&E Corporation 2006 Long-Term Incentive Plan, effective as of January 1, 2006, as amended February 15, 2006 
*10.36
PG&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)
*10.37
Form 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)
*10.38
Form 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)
*10.39
Form 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)
*10.40
Form 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)
*10.41
Form 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)
*10.42
Form 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)
*10.43
Form 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)
*10.44
Form 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)
 
48 
 
 
*10.45
PG&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)
*10.46
PG&E Corporation Executive Stock Ownership Program Guidelines as amended February 15, 2006
*10.47
PG&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)
*10.48
PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2006
*10.49
PG&E Corporation Golden Parachute Restriction Policy effective as of February 15, 2006
*10.50
PG&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)
*10.51
PG&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)
*10.52
Resolution 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)
*10.53
Resolution 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)
11
Computation of Earnings Per Common Share
12.1
Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
12.2
Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
13
The following portions of the 2005 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company are included: "Selected Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations," financial statements of PG&E Corporation entitled "Consolidated Statements of Income," "Consolidated Balance Sheets," "Consolidated Statements of Cash Flows," and "Consolidated Statements of Shareholders' Equity," financial statements of Pacific Gas and Electric Company entitled "Consolidated Statements of Income," "Consolidated Balance Sheets," "Consolidated Statements of Cash Flows," and "Consolidated Statements of Shareholders' Equity," "Notes to the Consolidated Financial Statements," and "Quarterly Consolidated Financial Data (Unaudited)," "Management's Report on Internal Control Over Financial Reporting," "Report of Independent Registered Public Accounting Firm," and "Report of Independent Registered Public Accounting Firm."
21
Subsidiaries of the Registrant
23
Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP)
24.1
Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K
24.2
Powers of Attorney
31.1
Certifications 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
31.2
Certifications 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
**32.1
Certifications 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
**32.2
Certifications 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.


49

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, 2005 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)
By
(Registrant)
 
BRUCE R WORTHINGTON
(Bruce R. Worthington, Attorney-in-Fact)
Date:
February 17, 2006
Date:
February 17, 2006
       

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
Date
A.
Principal Executive Officers
    
 
*PETER A. DARBEE
Chairman of the Board, Chief Executive Officer and President (PG&E Corporation)
February 17, 2006
 
*THOMAS B. KING
President and Chief Executive Officer (Pacific Gas and Electric Company)
February 17, 2006
       
B.
Principal Financial Officers
    
 
*CHRISTOPHER P. JOHNS
Senior Vice President, Chief Financial Officer and Treasurer (PG&E Corporation and Pacific Gas and Electric Company )
February 17, 2006
       
C.
Principal Accounting Officers
    
 
*G. ROBERT POWELL
Vice President and Controller (PG&E Corporation and Pacific Gas and Electric Company)
February 17, 2006
       
D.
Directors
    
 
*DAVID R. ANDREWS
*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 Gas and Electric Company,
except as noted
February 17, 2006

*By
 
BRUCE R WORTHINGTON
(Bruce R. Worthington, 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”) and Pacific Gas and Electric Company and subsidiaries (the “Utility”) as of December 31, 2005 and 2004, and for each of the three years in the period ended December 31, 2005, management’s assessment of the effectiveness of the Company’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, and have issued our reports thereon dated February 15, 2006; such consolidated financial statements and reports are included in your 2005 Annual Report to Shareholders of the Company and the Utility and are incorporated herein by reference.  Our audits also included the condensed financial statement schedules of the Company and the Utility listed in Item 15 (a) 2.  These condensed financial statement schedules are the responsibility of the Company’s and the Utility’s management.  Our responsibility is to express an opinion based on our audits.  In our opinion, such condensed 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, 2006
 

51
 

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

   
Balance at December 31,
  
   
2005
  
2004
  
ASSETS
              
Cash and cash equivalents
  
$
250
  
$
183
  
Advances to affiliates
    
38
    
22
  
Other current assets
    
3
    
3
  
Total current assets
    
291
    
208
  
Equipment
    
15
    
15
  
Accumulated depreciation
    
(14
)
  
(13
)
Net equipment
    
1
    
2
  
Investments in subsidiaries
    
7,401
    
8,848
  
Other investments
    
71
    
31
  
Deferred income taxes
    
127
    
104
  
Other
    
15
    
14
  
Total Assets
  
$
7,906
  
$
9,207
  
LIABILITIES AND SHAREHOLDERS' EQUITY
              
Current Liabilities
             
Accounts payable—related parties
  
$
27
  
$
3
  
Accounts payable—other
    
17
    
15
  
Income taxes payable
    
28
    
83
  
Other
    
193
    
53
  
Total current liabilities
    
265
    
154
  
Noncurrent Liabilities:
             
Long-term debt
    
280
    
280
  
Other
    
143
    
140
  
Total noncurrent liabilities
    
423
    
420
  
Preferred stock
    
—
    
—
  
Common Shareholders' Equity
             
Common stock
    
5,827
    
6,518
  
Common stock held by subsidiary
    
(718
)
  
(718
)
Unearned compensation
    
(22
)
  
(26
)
Reinvested earnings
    
2,139
    
2,863
  
Accumulated other comprehensive loss
    
(8
)
  
(4
)
Total common shareholders' equity
    
7,218
    
8,633
  
Total Liabilities and Shareholders' Equity
  
$
7,906
  
$
9,207
  


52

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

   
Year Ended December 31,
  
   
2005
  
2004
  
2003
  
Administrative service revenue
  
$
97
  
$
85
  
$
101
  
Equity in earnings of subsidiaries
    
918
    
3,959
    
917
  
Operating expenses
    
(97
)
  
(110
)
  
(133
)
Interest income
    
9
    
15
    
20
  
Interest expense
    
(35
)
  
(132
)
  
(200
)
Other income (expense)
    
(17
)
  
(91
)
  
2
  
Income before income taxes
    
875
    
3,726
    
707
  
Income tax benefit
    
29
 
  
94
 
  
84
 
Income from continuing operations
    
904
    
3,820
    
791
  
Gain on disposal of NEGT
    
13
    
684
    
—
  
Discontinued operations
    
—
    
—
    
(365
)
Cumulative effect of changes in accounting principles
    
—
    
—
    
(6
)
Net income before intercompany eliminations
  
$
917
  
$
4,504
  
$
420
  
 
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
  

53
PG&E CORPORATION
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT — (Continued)
CONDENSED STATEMENTS OF CASH FLOWS
(in millions)


 
 
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
 
        __________________________________
     

(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, 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 CORPORATION

SCHEDULE II—CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2005, 2003 and 2004

       
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.


55


PACIFIC GAS AND ELECTRIC COMPANY

SCHEDULE II—CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2005, 2004 and 2003

       
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."

        (2) Deductions consist principally of write-offs, net of collections of receivables previously written off.
 
56

EXHIBIT INDEX

Exhibit
Number
Exhibit Description
2.1
Order 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)
2.2
Order 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)
3.1
Restated 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)
3.2
Certificate 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)
3.3
Bylaws of PG&E Corporation amended as of January 1, 2006
3.4
Restated 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)
3.5
Bylaws of Pacific Gas and Electric Company amended as of January 1, 2006
4.1
Indenture, 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)
4.2
Indenture 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).
4.3
Supplemental 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)
4.4
Warrant 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)
10.1
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)
10.2
First Amendment, dated as of November 30, 2005, to the Credit Agreement among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JPMorgan Chase Bank, N.A., as syndication agent and a lender, Barclays Bank PLC 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.
10.3
Credit Agreement, 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 York (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed December 15, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 99)
 
57
 
 
10.4
First Amendment, dated as of April 8, 2005, to the Credit Agreement dated as of December 10, 2004, among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities Inc., as syndication agent and a lender, 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, KBC Bank N.V., and The Bank of New York (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 10.2)
10.5
Master Confirmation dated November 16, 2005, for accelerated share repurchase arrangements between PG&E Corporation and Goldman, Sachs & Co.
10.6
Settlement 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)
10.7
Firm 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)
10.8
Operating 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)
10.9
PG&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)
10.10
Transmission 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)
10.11
Operating 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)
*10.12
PG&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)
*10.13
PG&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)
*10.14
Description 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)
*10.15
Letter regarding Compensation Arrangement between PG&E Corporation and Peter 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)
*10.16
Letter regarding Compensation Arrangement 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 December 31, 2000 (File No. 1-12609), Exhibit 10.6)
*10.17
Letter regarding Compensation Arrangement between PG&E Corporation and Thomas B. King dated June 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 10.3)
*10.18
Letter regarding Compensation Arrangement between PG&E Corporation and Rand L. Rosenberg dated October 19, 2005
 
 58
 
 
*10.19
Severance 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)
*10.20
Actions 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-Q for the quarter ended September 30, 2005 (File No. 1-12609), Exhibit 10.2)
*10.21
PG&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)
*10.22
Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2006
*10.23
Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, 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 10.18)
*10.24
Schedule of 2006 Base Salary and Short-Term Incentive Plan Target Participation Rates for certain officers of PG&E Corporation and its subsidiaries
*10.25
Schedule of 2006 award values under the PG&E Corporation 2006 Long-Term Incentive Plan for certain officers of PG&E Corporation and its subsidiaries
*10.26
Supplemental 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)
*10.27
Supplemental Executive Retirement Plan of PG&E Corporation as amended effective as of January 1, 2006
*10.28.1
Agreement 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's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.37.1)
*10.28.2
Agreement 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)
*10.28.3
Agreement 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)
*10.28.4
Agreement 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)
*10.29.1
Agreement 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)
*10.29.2
Agreement 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)
*10.29.3
Agreement 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)
*10.29.4
Agreement 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)
*10.30
Pacific 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)
*10.31
Postretirement 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)
*10.32
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 
 
 
*10.33
Resolution of the PG&E Corporation Board of Directors dated June 16, 2004, adopting director compensation arrangement (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, 2004 (File No. 1-12609 and File No. 12348), Exhibit 10.1)
*10.34
Resolution of the Pacific Gas and Electric Company Board of Directors dated June 16, 2004, adopting director compensation arrangement (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, 2004 (File No. 1-12609 and File No. 12348), Exhibit 10.2) 
*10.35
PG&E Corporation 2006 Long-Term Incentive Plan, effective as of January 1, 2006, as amended February 15, 2006 
*10.36
PG&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)
*10.37
Form 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)
*10.38
Form 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)
*10.39
Form 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)
*10.40
Form 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)
*10.41
Form 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)
*10.42
Form 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)
*10.43
Form 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)
*10.44
Form 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)
*10.45
PG&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)
*10.46
PG&E Corporation Executive Stock Ownership Program Guidelines as amended February 15, 2006
*10.47
PG&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)
*10.48
PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2006
*10.49
PG&E Corporation Golden Parachute Restriction Policy effective as of February 15, 2006
*10.50
PG&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)
*10.51
PG&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)
*10.52
Resolution 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
 
 
*10.53
Resolution 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)
11
Computation of Earnings Per Common Share
12.1
Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
12.2
Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
13
The following portions of the 2005 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company are included: "Selected Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations," financial statements of PG&E Corporation entitled "Consolidated Statements of Income," "Consolidated Balance Sheets," "Consolidated Statements of Cash Flows," and "Consolidated Statements of Shareholders' Equity," financial statements of Pacific Gas and Electric Company entitled "Consolidated Statements of Income," "Consolidated Balance Sheets," "Consolidated Statements of Cash Flows," and "Consolidated Statements of Shareholders' Equity," "Notes to the Consolidated Financial Statements," and "Quarterly Consolidated Financial Data (Unaudited)," "Management's Report on Internal Control Over Financial Reporting," "Report of Independent Registered Public Accounting Firm," and "Report of Independent Registered Public Accounting Firm."
21
Subsidiaries of the Registrant
23
Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP)
24.1
Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K
24.2
Powers of Attorney
31.1
Certifications 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
31.2
Certifications 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
**32.1
Certifications 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
**32.2
Certifications 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.
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