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