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, 2002
--------------------
OR
Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the transition period from to
------ -------
SAN DIEGO GAS & ELECTRIC COMPANY
- ---------------------------------------------------------------------
(Exact name of registrant as specified in its charter)

CALIFORNIA 1-3779 95-1184800
- ---------------------------------------------------------------------
(State of incorporation (Commission (I.R.S. Employer
or organization) File Number) Identification No.

8326 CENTURY PARK COURT, SAN DIEGO, CALIFORNIA 92123
- ---------------------------------------------------------------------
(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code (619)696-2000
--------------
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Name of each exchange
Title of each class on which registered
- ------------------- ---------------------
Preference Stock (Cumulative) American
Without Par Value (except $1.70 and $1.7625 Series)
Cumulative Preferred Stock, $20 Par Value
(except 4.60% Series)

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None

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 and (2) has been subject to
such filing requirements for the past 90 days.
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. [ X ]

Exhibit Index on page 89. Glossary on page 94.

Aggregate market value of the voting preferred stock held by non-
affiliates of the registrant as of January 31, 2003 was $21.7 million.

Registrant's common stock outstanding as of January 31, 2003 was wholly
owned by Enova Corporation.

DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Information Statement prepared for the May 2003 annual
meeting of shareholders are incorporated by reference into Part III.

TABLE OF CONTENTS

PART I
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . .3
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . 19
Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . . 20
Item 4. Submission of Matters to a Vote of Security Holders. . 20

PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . . 20
Item 6. Selected Financial Data. . . . . . . . . . . . . . . . 21
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . 21
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk . . . . . . . . . . . . . . . . . 39
Item 8. Financial Statements and Supplementary Data. . . . . . 40
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . 83

PART III
Item 10. Directors and Executive Officers of the Registrant . . 84
Item 11. Executive Compensation . . . . . . . . . . . . . . . . 84
Item 12. Security Ownership of Certain Beneficial Owners
and Management. . . . . . . . . . . . . . . . . . . 85
Item 13. Certain Relationships and Related Transactions . . . . 85
Item 14. Controls and Procedures. . . . . . . . . . . . . . . . 85

PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . . 86

Independent Auditors' Consent . . . . . . . . . . . . . . . . . 87

Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . 88

Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . 89

Glossary. . . . . . . . . . . . . . . . . . . . . . . . . . . . 94

Certifications. . . . . . . . . . . . . . . . . . . . . . . . . 96

2
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

[ ] 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 1-3779

SAN DIEGO GAS & ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
California 95-1184800
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)

8326 Century Park Court, San Diego, California 92123
(Address of principal executive offices)
(Zip Code)

(619) 696-2000
(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
Preference Stock (Cumulative)
Without Par Value (except $1.70 and
$1.7625 Series)
Cumulative Preferred Stock, $20 Par Value
(except 4.60% Series) American

American
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.
Yes No X

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes 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.
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.
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):
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).
Yes No X

Exhibit Index on page 82. Glossary on page 89.
Aggregate market value of the voting stock held by non-affiliates of the registrant as of June 30, 2005 was $24.6 million.
Registrant's common stock outstanding as of January 31, 2006 was wholly owned by Enova Corporation.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Information Statement prepared for the May 2006 annual meeting of shareholders are incorporated by reference into Part III.
TABLE OF CONTENTS Page
PART I
Item 1. Business and Risk Factors 4
Item 2. Properties 15
Item 3. Legal Proceedings 15
Item 4. Submission of Matters to a Vote of Security Holders 16
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters 16
Item 6. Selected Financial Data 16
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 17
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 29
Item 8. Financial Statements and Supplementary Data 30
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures 76
Item 9A. Controls and Procedures 76
PART III
Item 10. Directors and Executive Officers of the Registrant 77
Item 11. Executive Compensation 77
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 77
Item 13. Certain Relationships and Related Transactions 77
Item 14. Principal Accountant Fees and Services 78
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K 78
Consent of Independent Registered Public Accounting Firm 80
Signatures 81
Exhibit Index 82
Glossary 89

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report contains statements that are not historical fact and constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. The words "estimates," "believes," "expects," "anticipates," "plans," "intends," "may," "could," "would" and "should" or similar expressions, or discussions of strategy or of plans are intended to identify forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future results may differ materially from those expressed in these forward-looking statements.
Forward-looking statements are necessarily based upon various assumptions involving judgments with respect to the future and other risks, including, among others, local, regional national and internationalnational economic, competitive, political, legislative and regulatory conditions and developments; actions by the California Public Utilities Commission, (CPUC), the California State Legislature, the California Department of Water Resources, (DWR), and the Federal Energy Regulatory Commission (FERC);and other regulatory bodies in the United States; capital marketmarkets conditions, inflation rates, interest rates and exchange rates; energy and trading markets, including the timing and extent of changes in commodity prices; the availability of natural gas; weather conditions and conservation efforts; war and terrorist attacks; business, regulatory, environmental and legal decisions;decisions and requirements; the pacestatus of deregulation of retail natural gas and electricity delivery; the timing and success of business development efforts; the resolution of litigati on; and other uncertainties, all of which are difficult to predict and many of which are beyond the control of the company. Readers are cautioned not to rely unduly on any forward-
lookingforward-looking statements and are urged to review and consider carefully the risks, uncertainties and other factors which affect the company's business described in this report and other reports filed by the company from time to time with the Securities and Exchange Commission.

PART I
ITEM 1. BUSINESS AND RISK FACTORS
Description of Business
A description of San Diego Gas & Electric Company (SDG&E or the company) is given in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein.
SDG&E's common stock is wholly owned by Enova Corporation, which is a wholly owned subsidiary of Sempra Energy, a California-based Fortune 500 holding company. The financial statements herein are the Consolidated Financial Statements of SDG&E and its sole subsidiary, SDG&E Funding LLC. Sempra Energy also indirectly owns the common stock of Southern California Gas Company (SoCalGas). SDG&E and SoCalGas are collectively referred to herein as "the California Utilities."

3
Company Website
The company's website address is http://www.sdge.com/ and its parent
company'sSempra Energy's website address is http://www.sempra.com/investor.htm.www.sempra.com. The company makes available free of charge via a hyperlink on its website
to its parent company's website its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission.

GOVERNMENT REGULATION

Local Regulation
Risk Factors
The following risk factors and all other information contained in this report should be considered carefully when evaluating SDG&E. These risk factors could affect the actual results of SDG&E has electric franchisesand cause such results to differ materially from those expressed in any forward-looking statements of, or made by or on behalf of, SDG&E. Other risks and uncertainties, in addition to those that are described below, may also impair its business operations. If any of the following risks occurs, SDG&E'sbusiness, cash flows, results of operations and financial condition could be seriously harmed. These risk factors should be read in conjunction with the three counties and the 26 cities
in its electric service territory, and natural gas franchises with the
one county and the 23 cities in its natural gas service territory.
These franchises allowother detailed information concerning SDG&E to locate facilities for the transmission
and distribution of electricity and/or natural gasset forth in the streetsnotes to Consolidated Financial Statements and other public places. in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein..
SDG&E is subject to extensive regulation by state, federal and local legislation and regulatory authorities, which may adversely affect the operations, performance and growth of its business
The franchises do not have fixed terms, except forCalifornia Public Utilities Commission (CPUC), which consists of five commissioners appointed by the electric and natural gas franchises with the cities of Chula Vista
(2003), Encinitas (2012), San Diego (2021) and Coronado (2028); and the
natural gas franchises with the city of Escondido (2036) and the county
of San Diego (2030).

California Utility Regulation

The StateGovernor of California Legislature,for staggered six-year terms, regulates SDG&E's rates (except electric transmission rates, which are regulated by the Federal Energy Regulatory Commission (FERC)) and conditions of service, sales of securities, rates of return, rates of depreciation, uniform systems of accounts, examination of records and long-term resource procurement. The CPUC conducts various reviews of utility performance (which may include reasonableness and prudency reviews) and affiliate relationships and conducts audits and investigations into various matters which may, from time to time, passes laws
that regulateresult in disallowances and penalties adversely affecting earnings and cash flows. Various proceedings involving the CPUC and relating to SDG&E's operations. For example,rates, costs, incentive mechanisms, performance-based regulation and compliance with affiliate and holding company rules are discussed in 1996 the legislature
passed an electric industry deregulation bill,notes to Consolida ted Financial Statements and in subsequent years
passed additional bills aimed at addressing problems"Management's Discussion and Analysis of Financial Condition and Results of Operations" herein.
Periodically,SDG&E's rates are approved by the CPUC based on forecasts of capital and operating costs. If the company's actual capital and operating costs were to exceed the amount included in its base rates approved by the CPUC, it would adversely affect earnings and cash flows.
To promote efficient operations and improved productivity and to move away from reasonableness reviews and disallowances, the CPUC adopted Performance-Based Regulation (PBR) for the California Utilities. Under PBR, regulators require future income potential to be tied to achieving or exceeding specific performance and operating income goals, rather than relying solely on expanding utility plant to increase earnings. The three areas that are eligible for PBR rewards are: operational incentives based on measurements of safety, reliability and customer satisfaction; energy efficiency rewards based on the effectiveness of the programs; and natural gas procurement rewards. Although SDG&E has received PBR rewards in the deregulatedpast, there can be no assurance that it will receive rewards in the future, or that they would be of comparable amounts. Additionally, if the company fails to achieve certain minimum performance levels established under the PBR mechanisms, it may be assessed financial disallowances or penalt ies which could negatively affect earnings and cash flows.
The FERC regulates electric industry.transmission rates, the transmission and wholesale sales of electricity in interstate commerce, transmission access and other similar matters involving SDG&E.
The company may be adversely affected by new regulations, decisions, orders or interpretations of the CPUC, FERC or other regulatory bodies. New legislation, regulations, decisions, orders or interpretations could change how the company operates, could affect its ability to recover various costs through rates or adjustment mechanisms, or could require the company to incur additional expenses.
SDG&E may incur substantial costs and liabilities as a result of its ownership of nuclear facilities.
SDG&E owns a 20% interest in the San Onofre Nuclear Generating Station (SONGS), a 2,150 megawatt nuclear generating facility near San Clemente, California. The Nuclear Regulatory Commission (NRC) has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. SDG&E's ownership interest in SONGS subjects it to the risks of nuclear generation, which include:
the potential harmful effects on the environment and human health resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials;
limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations; and
uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.
The California Utilities' future results of operations and financial condition may be materially adversely affected by the outcome of pending litigation against them.
The California energy crisis of 2000-2001 has generated numerous lawsuits, governmental investigations and regulatory proceedings involving many energy companies, including Sempra Energy and the California Utilities. In addition,January 2006, Sempra Energy and the legislature enacted a lawCalifornia Utilities reached agreement to settle several of these lawsuits including, subject to court and other approvals, the principal class action antitrust lawsuits in 1999
addressingwhich they are defendants. The companies remain defendants in several additional lawsuits arising out of the energy crisis, including lawsuits commenced in the fourth quarter of 2005 by the California Attorney General. The company is also responding to an ongoing CPUC proceeding related to the increase in natural gas industry restructuring.

prices at the California-Arizona border in 2000-2001. Sempra Energy and the California Utilities have expended and continue to expend substantial amounts defending these lawsuits and in connection with related investigations and regulatory proceedings. Sempra Ener gy and the California Utilities have established reserves for the agreed and unresolved issues. However, given the uncertainties involved in resolving litigation, Sempra Energy's and the California Utilities' results of operations and financial condition may be materially adversely affected.
These proceedings are discussed in the notes to Consolidated Financial Statements and in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein.
The company's cash flows, ability to pay dividends and ability to meet its debt obligations largely depend on the performance of its utility operations.
The company's utility operations are the major source of liquidity. The company's ability to pay dividends on its preferred stock is largely dependent on the sufficiency of utility earnings and cash flows in excess of operational needs.
Natural disasters, catastrophic accidents or acts of terrorism could materially adversely affect the company's business, earnings and cash flows.
Like other major industrial facilities, the company's electric transmission facilities and natural gas pipelines may be damaged by natural disasters, catastrophic accidents or acts of terrorism. Any such incidents could result in severe business disruptions, significant decreases in revenues or significant additional costs to the company, which could have a material adverse effect on the company's earnings and cash flows. Given the nature and location of these facilities, any such incidents also could cause fires, leaks, explosions, spills or other significant damage to natural resources or property belonging to third parties, or personal injuries, which could lead to significant claims against the company. Insurance coverage may become unavailable for certain of these risks and the insurance proceeds received for any loss of or damage to any of its facilities, or for any loss of or damage to natural resources or property or personal injuries caused by its operations, may be insufficient to cover the company'slosses or liabilities without materially adversely affecting the company's financial condition, earnings and cash flows.
GOVERNMENT REGULATION
California Utility Regulation
The CPUC, which consists of five commissioners appointed by the Governor of California for staggered six-year terms, regulates SDG&E's rates and conditions of service, sales of securities, rate of return, rates of depreciation, uniform systems of accounts, examination of records, and long-term resource procurement. The CPUC conducts various reviews of utility performance and conducts investigations into various matters, such as deregulation, competition and the environment, to determine its future policies. The CPUC also regulates the relationship of utilitiesthe California Utilities with their holding companiesSempra Energy and is currently conducting
an investigation intoinvestigating this relationship.

relationship, as discussed further in Note 10 of the notes to Consolidated Financial Statements herein.
The California Energy Commission (CEC) has discretion over electric demand forecasts for the state and for specific service territories. Based upon these forecasts, the CEC determines the need for additional energy sources and for conservation programs. The CEC sponsors alternative-energy research and development projects, promotes energy conservation programs and maintains a state-wide plan of action in case of energy shortages. In addition, the CEC certifies power-plant sites and related facilities within California.

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The CEC conducts a 20-year forecast of supply availability and prices for every market sector consuming natural gas in California. This forecast includes resource evaluation, pipeline capacity needs, natural gas demand and wellhead prices, and costs of transportation and distribution. This analysis is used to support long-term investment decisions.

California Power Authority

The California Consumer Power and Financing Authority is responsible
for ensuring reliable electricity at reasonable prices. It does so by
diversifying its electricity portfolio to include increased renewable
energy, permanent conservation efforts and cleaner-burning projects.

United States Utility Regulation
The FERC regulates the interstate sale and transportation of natural gas, the transmission and wholesale sales of electricity in interstate commerce, transmission access, the uniform systems of accounts, rates of depreciation and electric rates involving sales for resale. Both the FERC and the CPUC are currently investigating prices charged to the California investor-owned utilities (IOUs) by various suppliers of natural gas and electricity. Further discussion is provided in Notes 9, 10and 11 of the notes to Consolidated Financial Statements herein.
The Nuclear Regulatory Commission (NRC)NRC oversees the licensing, construction and operation of nuclear facilities. NRC regulations require extensive review of the safety, radiological and environmental aspects of these facilities. Periodically, the NRC requires that newly developed data and techniques be used to re-analyze the design of a nuclear power plant and, as a result, requires plant modifications as a condition of continued operation in some cases.
Local Regulation
SDG&E has electric franchises with the two counties and the 26 cities in its electric service territory, and natural gas franchises with the one county and the 18 cities in its natural gas service territory. These franchises allow SDG&E to locate, operate and maintain facilities for the transmission and distribution of electricity and/or natural gas in streets and other public places. Most of the franchises have indeterminate lives, except for the electric and natural gas franchises with the cities of Encinitas (2012), San Diego (2020), Coronado (2028) and Chula Vista (2035), and the natural gas franchises with the city of Escondido (2035) and the county of San Diego (2029).
Licenses and Permits
SDG&E obtains a number ofnumerous permits, authorizations and licenses in connection with the transmission and distribution of natural gas and electricity. In addition, SDG&E obtains a number of permits,
authorizations and licenses in connection with the transmission and
distribution of electricity. BothThey require periodic renewal, which results in continuing regulation by the granting agency.
Other regulatory matters are described in Notes 109 and 1110 of the notes to Consolidated Financial Statements herein.

SOURCES OF REVENUE

Information on this topic is provided in Note 1 of the notes to
Consolidated Financial Statements herein.

ELECTRIC
NATURAL GAS UTILITY OPERATIONS
Resource Planning In 1996, California enacted legislation restructuring California's
investor-owned electric utility industry. and Natural Gas Procurement and Transportation
The legislationcompany is engaged in the purchase and distribution of natural gas. The company's resource planning, power procurement, contractual commitments and related decisions of the CPUC were intended to stimulate competitionregulatory matters are discussed below and reduce
rates.

Supply/demand imbalances and a number of factors resulted in abnormally
high wholesale electric prices beginning in mid-2000, which caused
SDG&E's monthly customer bills to be substantially higher than normal.
These conditions and the resultant abnormally high electric-commodity
prices continued into 2001 resulting in growth of the undercollection
of SDG&E's electricity costs.

In response to these high commodity prices, the California legislature
adopted legislation intended to stabilize the California electric
utility industry and reduce wholesale electric commodity prices. This
resulted in several legislative and regulatory responses, including
California Assembly Bill (AB) 265, enacted in September 2000 and in
effect through December 31, 2002. AB 265 imposed a ceiling of 6.5
cents/kilowatt hour (kWh) on the cost of the electric commodity that
SDG&E could pass on to its small-usage customers on a current basis,
effective retroactive to June 1, 2000. Further actions included the
DWR's purchasing through December 31, 2002 the net short position of
SDG&E (the power needed by SDG&E's customers, other than that provided
by SDG&E's nuclear generating facilities or its previously existing
purchase power contracts). In addition, implementation of some of the
provisions of the Memorandum of Understanding (MOU) entered into by
representatives of California Governor Davis, the DWR, Sempra Energy
and SDG&E resulted in the cessation of growth in the AB 265
undercollection.

Additional information concerning direct access, the MOU and electric-
industry restructuring in general is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Notes 10 11 and 1211 of the notes to Consolidated Financial Statements herein.

Electric Resources

In connection with California's electric-industry restructuring,
beginning March 31, 1998, the California IOUs were obligated to bid
their power supply, including owned generation and purchased-power
contracts, into the PX. The IOUs also were obligated to purchase from
the PX the power that they sell to their customers. In 1999, SDG&E
completed divestiture of its owned generation other than nuclear. An
Independent System Operator (ISO) schedules power transactions and
access to the transmission system. As discussed in Note 10 of the notes
to Consolidated Financial Statements, due to the conditions in the
California electric utility industry, the PX suspended its trading
operations on January 31, 2001.

As discussed above, the California Legislature passed laws (e.g.,
Assembly Bill X1 in February 2001), authorizing the DWR to enter into
long-term contracts to purchase the portion of power used by SDG&E

customers that is not provided by SDG&E's existing supply through
December 31, 2002. SDG&E's residual net short requirements have been
met by the DWR since February 7, 2001.

In August 2002, SDG&E was granted authority by the CPUC to once again
procure electric power to meet the load requirements of its customers,
effective January 1, 2003. The California Legislature also passed
several laws (e.g., AB 57, Senate Bill (SB) 1078 and SB 1038) which
required that (a) purchases made by SDG&E beginning January 1, 2003 not
be subject to hindsight regulatory review, except for contract
administration functions and (b) SDG&E procure at least one percent of
its annual retail energy supply from renewable producers. Each IOU is
directed to procure from renewable sources at least one percent of its
2003 total energy sales and add at least one percent of energy sales
each year thereafter, such that a 20-percent renewable resources
portfolio is achieved by the year 2017.

On September 20, 2002, SDG&E issued a Request for Offer seeking to
purchase a variety of energy products from both renewable and non-
renewable entities. SDG&E did not enter into any contracts with non-
renewable entities but did enter into contracts with 11 renewable
suppliers (for 15 projects) for 237 megawatts (mW) of non-firm power
starting in 2003. On December 5, 2002, the CPUC issued its resolution
approving SDG&E's renewable contract purchases and on December 19,
2003, the CPUC approved SDG&E's 2003 procurement plan. SDG&E has
contracted to procure approximately four percent of its 2003 total
energy sales from renewable sources and, pursuant to the December 2002
CPUC resolution, may credit toward future years' compliance any excess
over its one-percent requirement.

The CPUC also allocated to SDG&E seven of the contracts signed by the
DWR during the energy crisis in 2001. The contracts represent 2,754 mW
of capacity available to SDG&E in a combination of must-take and
dispatchable resources. SDG&E will be responsible for scheduling and
dispatching these contracts (where applicable) as well as some contract
administration duties.

Based on generating plants in service and purchased-power contracts
currently in place, as of January 31, 2003, the mW of electric power
available to SDG&E are as follows:

Source mW
--------------------------------------------------
San Onofre Nuclear Generating Station (SONGS) 430*
Long-term contracts with other utilities 84
DWR allocated contracts 2,754
Contracts with others 592
-----
Total 3,860
=====
* Net of internal usage

SONGS: SDG&E owns 20 percent of the three nuclear units at SONGS
(located south of San Clemente, California). The cities of Riverside
and Anaheim own a total of 5 percent of Units 2 and 3. Southern
California Edison (Edison) owns the remaining interests and operates
the units.

Unit 1 was removed from service in November 1992 when the CPUC issued a
decision to permanently shut down the unit. At that time SDG&E began
the recovery of its remaining capital investment, with full recovery
completed in April 1996. The unit's spent nuclear fuel has been removed
from the reactor and is stored on-site. In March 1993, the NRC issued a
Possession-Only License for Unit 1, and the unit was placed in a long-
term storage condition in May 1994. In June 1999, the CPUC granted
authority to begin decommissioning Unit 1 and this work is now in
progress.

Units 2 and 3 began commercial operation in August 1983 and April 1984,
respectively. SDG&E's share of the capacity is 214 mW of Unit 2 and 216
mW of Unit 3.

During 2002, SDG&E spent $8 million on capital additions and
modifications of Units 2 and 3, and expects to spend $10 million in
2003.

SDG&E deposits funds in external trusts to provide for the
decommissioning of all three units.

Additional information concerning the SONGS units, nuclear
decommissioning and industry restructuring is provided below and in
"Environmental Matters" herein, and in "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and in Notes
4, 10 and 12 of the notes to Consolidated Financial Statements herein.

Purchased Power: The following table lists contracts with SDG&E's
various suppliers:

Expiration Megawatt
Supplier Date Commitment Source
- ------------------------------------------------------------------
Long-Term Contracts with Other Utilities:

Portland General
Electric (PGE) December 2013 84 Coal
-----
Total 84
=====
Other Contracts:

DWR Allocated Contracts

Williams Energy
Marketing & Trading December 2010 1,875 Gas

Sunrise Power Co. LLC June 2012 560 Gas

Other DWR contracts Various terminations 319 Gas and wind
from 2003 to 2013
-----
2,754
=====
Qualifying Facilities (QFs) --

Applied Energy Inc. November 2019 107 Cogeneration

Yuma Cogeneration May 2024 57 Cogeneration

Goal Line Limited
Partnership February 2025 50 Cogeneration

Other QFs (73) Various terminations 16 Cogeneration
-----
230
Others --
Renewable (15) 5-15 year terms 237 Biomass, bio-gas
starting 2003 and wind

Various (3) December 2003 125 System supply
-----
Total 592
=====

Under the contract with PGE, SDG&E pays a capacity charge plus a charge
based on the amount of energy received. Charges under this contract are
based on PGE's costs, including lease payments, fuel expenses,
operating and maintenance expenses, transmission expenses,
administrative and general expenses, and state and local taxes. Costs
under the contracts with QFs are based on SDG&E's avoided cost. Charges
under the remaining contracts, which include renewal contracts signed
in the fourth quarter of 2002, bilateral contracts executed in 2000 and

2001, and the DWR contracts allocated to SDG&E by the CPUC, are for
firm and as-available energy and are based on the amount of energy
received. The prices under these contracts are at the market value at
the time the contracts were negotiated.

Additional information concerning SDG&E's purchased-power contracts is
provided below, and in "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and Note 12 of the notes
to Consolidated Financial Statements herein.

Power Pools

SDG&E is a participant in the Western Systems Power Pool, which
includes an electric-power and transmission-rate agreement with
utilities and power agencies located throughout the United States and
Canada. More than 250 investor-owned and municipal utilities, state and
federal power agencies, energy brokers, and power marketers share power
and information in order to increase efficiency and competition in the
bulk power market. Participants are able to make power transactions on
standardized terms that have been pre-approved by FERC.

Transmission Arrangements

Pacific Intertie (Intertie): The Intertie, consisting of AC and DC
transmission lines, connects the Northwest with SDG&E, Pacific Gas &
Electric (PG&E), Edison and others under an agreement that expires in
July 2007. SDG&E's share of the Intertie is 266 mW.

Southwest Powerlink: SDG&E's 500-kilovolt Southwest Powerlink
transmission line, which is shared with Arizona Public Service Company
and Imperial Irrigation District, extends from Palo Verde, Arizona to
San Diego. SDG&E's share of the line is 970 mW, although it can be
less, depending on specific system conditions.

Mexico Interconnection: Mexico's Baja California Norte system is
connected to SDG&E's system via two 230-kilovolt interconnections with
firm capability of 408 mW in the north to south direction and 800 mW in
the south to north direction.

Due to electric-industry restructuring (see "Transmission Access"
below), the operating rights of SDG&E on these lines have been
transferred to the ISO.

Transmission Access

The FERC has established rules to implement the transmission-access
provisions of the National Energy Policy Act of 1992. These rules
specify FERC-required procedures for others' requests for transmission
service. In October 1997, the FERC approved the California IOUs'
transfer of control of their transmission facilities to the ISO. On
March 31, 1998, operation and control of the transmission lines was
transferred to the ISO. Additional information regarding the ISO and
transmission access is provided below and in "Management's Discussion
and Analysis of Financial Condition and Results of Operations" herein.

Fuel and Purchased-Power Costs

The following table shows the percentage of each electricity source
used by SDG&E and compares the kilowatt hour cost of nuclear fuel with
the total cost of purchased power:

Percent of kWh Cents per kWh
- ---------------------------------------------------------------
2002 2001 2000 2002 2001 2000
----- ----- ----- ---- ---- ----
Nuclear fuel 23.0 30.1 14.9 0.4 0.5 0.5
Purchased power
and ISO/PX 77.0 69.9 85.1 7.4 9.4 9.7
------ ------ ------
Total 100.0% 100.0% 100.0%
====== ====== ======

The cost of purchased power includes capacity costs as well as the
costs of fuel. The cost of nuclear fuel does not include SDG&E's
capacity costs.

Nuclear Fuel Supply

The nuclear-fuel cycle includes services performed by others under
various contracts through 2008, including mining and milling of uranium
concentrate, conversion of uranium concentrate to uranium hexafluoride,
enrichment services, and fabrication of fuel assemblies.

Spent fuel from SONGS is being stored on site, where storage capacity
will be adequate at least through 2005. Modifications in fuel storage
technology can be implemented to provide on-site storage capacity for
operation through 2022, the expiration date of the NRC operating
license. Pursuant to the Nuclear Waste Policy Act of 1982, SDG&E
entered into a contract with the U.S. Department of Energy (DOE) for
spent-fuel disposal. Under the agreement, the DOE is responsible for
the ultimate disposal of spent fuel. SDG&E pays a disposal fee of $1.00
per megawatt-hour of net nuclear generation, or approximately $3
million per year. The DOE projects it will not begin accepting spent
fuel until 2010 at the earliest.

To the extent not currently provided by contract, the availability and
the cost of the various components of the nuclear-fuel cycle for
SDG&E's nuclear facilities cannot be estimated at this time.

Additional information concerning nuclear-fuel costs is provided in
Note 12 of the notes to Consolidated Financial Statements herein.

NATURAL GAS OPERATIONS

SDG&E purchases and distributes natural gas to 789,000 end-use
customers throughout the western portion of the County of San Diego.
SDG&E also transports natural gas to approximately 300 customers who
procure the natural gas from other sources.

Supplies of Natural Gas

SDG&E buys natural gas under several short-term and long-term
contracts. Short-term purchases are from various Southwest United
States and Canadian suppliers and are primarily based on monthly spot-
market prices. SDG&E transports natural gas under long-term firm
pipeline capacity agreements that provide for annual reservation
charges, which are recovered in rates. SDG&E has long-term natural gas
transportation contracts with various interstate pipelines which expire
on various dates between 2003 and 2023. SDG&E has a long-term purchase
agreement with a Canadian supplier that expires in August 2003, and in
which the delivered cost is tied to the California border spot-market
price. SDG&E purchases natural gas on a spot basis to fill its
additional long-term pipeline capacity. SDG&E intends to continue using
the long-term pipeline capacity in other ways as well, including the
transport of other natural gas for its own use and the release of a
portion of this capacity to third parties.

Most of the natural gas purchased and delivered by the company is
produced outside of California. These supplies are delivered to the
pipeline owned by SoCalGas at the California border by interstate
pipeline companies, primarily El Paso Natural Gas Company and
Transwestern Natural Gas Company. These interstate companies provide
transportation services for supplies purchased from other sources by
the company or its transportation customers. The rates that interstate
pipeline companies may charge for natural gas and transportation
services are regulated by the FERC. All of SDG&E's natural gas is
delivered through SoCalGas pipelines under a short-term transportation
agreement. In addition, under a separate agreement expiring in March
2003, SoCalGas provides SDG&E 4.5 billion cubic feet of storage
capacity. An agreement is expected to be completed with SoCalGas that
will extend storage services through March 2004.

The following table shows the sources of natural gas deliveries from
1998 through 2002.

Years Ended December 31
------------------------------------------
2002 2001 2000 1999 1998
- -----------------------------------------------------------------------------------

Gas purchases (billions of
cubic feet) 54 53 58 75 118

Customer-owned and
exchange receipts 90 104 85 47 19

Storage withdrawal
(injection) - net 2 (2) 1 4 (3)

Company use and
unaccounted for (6) -- (5) -- (2)
------- ------- ------- ------- ------
Net deliveries 140 155 139 126 132
======= ======= ======= ======= ======
Cost of gas purchased*
(millions of dollars) $ 182 $ 482 $ 277 $ 205 $ 327
------- ------- ------- ------- ------
Average Commodity Cost of Purchases
(dollars per thousand cubic feet) $3.37 $9.09 $4.77 $2.73 $2.77
======= ======= ======= ======= =======
* Includes interstate pipeline demand charges

Market-sensitive natural gas supplies (supplies purchased on the spot
market as well as under longer-term contracts, ranging from one month
to two years, based on spot prices) accounted for nearly all of total
natural gas volumes purchased by the company. The annual average price
of natural gas at the California/Arizona border was $3.14/million
British thermal units (mmbtu) in 2002, compared with $7.27/mmbtu in
2001 and $6.25/mmbtu in 2000. Supply/demand imbalances and a number of
other factors associated with California's energy crisis from late 2000
through early 2001 resulted in higher natural gas prices during that
period. Prices for natural gas decreased in the later part of 2001 and
increased toward the end of 2002. As of December 31, 2002, the average
spot cash price at the California/Arizona border was $4.47/mmbtu. The
cost of gas purchased may vary and can exceed the annual average price.

During 2002, the company delivered 140 billion cubic feet (bcf) of
natural gas. Approximately 64 percent of these deliveries were
customer-owned natural gas for which the company provided
transportation services. The remaining natural gas deliveries were
purchased by the company and resold to customers.

Customers
For regulatory purposes, customers are separated into core and noncore customers. Core customers are primarily residential and small commercial and industrial customers, without alternative fuel capability. Noncore customers consist primarily of utility electric generating (UEG) plants, wholesale purchasers, andgeneration, large commercial and industrial customers. As of December 31, 2002, SDG&E had 789,000 core
customers (760,000 residential and 29,000 small commercial and
industrial) and 100 noncore customers.

13
Most core customers purchase natural gas directly from the company. Core customers are permitted to aggregate their natural gas requirement and for up to 10 percent of the company's core market, to purchase
natural gas directly from brokers or producers. The CPUC tentatively
authorized the removal of the 10 percent limit, but this has yet to be
implemented. SDG&Ecompany continues to be obligated to purchase reliable supplies of natural gas to serve the requirements of its core customers. In early 2002, the California Utilities filed an application
with the CPUC to combine their core procurement portfolios. On August
22, 2002, the CPUC issued an interim decision denying the request,
pending completion
Natural Gas Procurement and Transportation
Most of the CPUC's ongoing investigation of market power
issues.

The CPUC ordered that utility procurement services offered to noncore
customers be phased out sometime in 2003. Noncore customers would have
the option to either become core customers, and continue to receive
utility procurement services, or remain noncore customers and purchase
their natural gas purchased and delivered by the company is produced outside of California, primarily in the southwestern U.S. and Canada. Thecompany purchases natural gas under short-term contracts, which are primarily based on monthly spot-market prices.
SDG&E has long-term natural gas transportation contracts with various interstate pipelines that expire on various dates between 2006 and 2023. SDG&E currently purchases natural gas on a spot basis from other sources, such as brokers or producers.
Noncore customers would also have to make arrangements to deliver their
purchases toCanada, the company's receipt points for delivery through the
company's transmission and distribution system. The proposed
implementation of the order has encountered significant oppositionRocky Mountain area and the CPUC is reconsideringSouthwestern U.S. to fill its decision.long-term pipeline capacity and purchases additional spot-market supplies delivered directly to California for its remaining requirements. SDG&E continues its ongoing assessment of its pipeline capacity portfolio, including the release of a portion of this capacity to third parties. In 2002, 89 percentaccordance with regulatory directives, SDG&E has reconfigured its pipeline capacity portfolio as of the CPUC-authorizedNovember 2005 to secure firm transportation rights from a diverse mix of U.S. and Canadian supply sources for its projected core customer natural gas marginrequirements. All of SDG&E's natural gas is delivered through SoCalGas' pipelines under a long-term transportation agreement. In addition, under separate agreements expiring in March 2008 , SoCalGas provides SDG&E up to nine billion cubic feet of storage capacity.
According to "Btu's Daily Gas Wire", the annual average spot price of natural gas at the California/Arizona border was allocated to$7.62 per million British thermal unit (mmbtu) in 2005 ($11.42 per mmbtu in December 2005), compared with $5.57 per mmbtu in 2004 and $5.13 per mmbtu in 2003.The company's weighted average cost (including transportation charges) per mmbtu of natural gas was $8.67 in 2005, $6.11in 2004 and $5.14in 2003.
Demand for Natural Gas
The company faces competition in the core customers, with 11 percent allocated toresidential and commercial customer markets based on the noncore customers.

Although revenues from transportation throughput is less thancustomers' preferences for natural gas sales, the company generally earns the same margin whether
the company buys the natural gas and sells it to the customer or
transports natural gas already owned by the customer.

Demand for Natural Gas

Natural gas is a principal energy source for residential, commercial,
industrial and UEG plant customers. Natural gas competes with
electricity for residential and commercial cooking, water heating,
space heating and clothes drying, andcompared with other energy products. In the non-core industrial market, some customers are capable of using alternate fuels, which can affect the demand for largenatural gas. The company's ability to maintain its industrial commercial and UEG uses. Growth in the natural gas marketsmarket share is largely dependent upon the health and expansion of the southern
California economy. The company added 14,000 and 12,000 new customer
meters in 2002 and 2001, respectively, representing growth rates of 1.8
percent and 1.6 percent, respectively. The company expects that its
growth rate for 2003 will approximate that of 2002.

During 2002, 90 percent of residentialon energy customers used natural
gas for water heating, 73 percent for space heating, 54 percent for
cooking and 38 percent for clothes drying.

Demand for natural gas by noncore customers is very sensitive to the
price of competing fuels. Although the number of noncore customers in
2002 was only 100 they accounted for approximately 6 percent of the
authorized natural gas revenues and 63 percent of total natural gas
volumes. External factors such as weather, the price of electricity,
electric deregulation, the use of hydroelectric power, competing

pipelines and general economic conditions can result in significant
shifts in demand and market price.prices. The demand for natural gas by large
UEG customerselectric generators is influenced by a number of factors. In the short-term, natural gas use by electric generators is impacted by the availability of alternative sources of generation. The availability of hydroelectricity is highly dependent on precipitation in the western United States. In addition, natural gas use is impacted by the performance of other generation sources in the western United States, including nuclear and coal, and other natural gas facilities outside the service area. Natural gas use is also greatly affectedimpacted by changes in end-use electricity demand. For example, nat ural gas use generally increases during summer heat waves. Over the pricelong-term, natural gas used to generate electricity will be influenced by additional factors such as the location of new power plant construction and availabilitythe development of renewable resources. More generation capacity currently is being constructed outside Southern California than within the California Utilities' service area. This new generation will likely displace the output of older, less efficient local generation, reducing the use of natural gas for local electric power generated in other areas.

generation.
Effective March 31, 1998, electric industry restructuring gave
California electric utilitiesprovided out-of-state producers the option of purchasing energy for their
customers from out-of-state producers.to provide power to California utility customers. As a result, natural gas demand for electric generation within southernSouthern California competes with electric power generated throughout the western United States. Although electric industry restructuring has no direct impact on the company's natural gas operations, future volumes of natural gas transported for electric generating plant customers may be significantly affected to the extent that regulatory changes divert electricityelectric generation from the company's service area.

Other

The Pipeline Safety Improvement Act of 2002, which became public law on
December 17, 2002, requires that baseline inspections be completed over
a ten-year period, with 50 percent
Growth in the natural gas markets is largely dependent upon the health and expansion of the inspections complete atSouthern California economy and prices of other energy products. External factors such as weather, the endprice of fiveelectricity, electric deregulation, the use of hydroelectric power, development of renewable resources, development of new natural gas supply sources and general economic conditions can result in significant shifts in demand and market price. The company added 12,000 new customer meters in each of 2005 and 2004, representing growth rates of 1.5 percent in both years. Related to these inspectionsThe company expects that its growth rate for 2006 will approximate 2005's.
The natural gas distribution business is seasonal in nature and potential
retrofits,revenues generally are greater during the winter months. As is prevalent in the industry, the company estimates that it will have $0.5 million in
operating and maintenance expense each year.

Additional information concerninginjects natural gas into storage during the summer months (usually April through October) for withdrawal from storage during the winter months (usually November through March) when customer demand is higher.
ELECTRIC UTILITY OPERATIONS
Customers
At December 31, 2005, the company had 1.3 million meters consisting of 1,188,000 residential, 141,000 commercial, 480 industrial, 1,990 street and other aspectshighway lighting, and 6,700 direct access. The company's service area covers 4,100 square miles. The company added 20,000 new customer meters in 2005 and 22,000 in 2004, representing growth rates of natural gas operations is provided under1.5% and 1.7%, respectively.
Resource Planning and Power Procurement
SDG&E's resource planning, power procurement and related regulatory matters are discussed below, in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Notes 119, 10 and 1211 of the notes to Consolidated Financial Statements herein.

RATES AND REGULATION

Electric Industry Restructuring

A flawed electric-industry restructuring plan, electricity
supply/demand imbalances,Resources
Based on CPUC-approved purchased-power contracts currently in place with SDG&E's various suppliers and legislativeSDG&E's 20-percent share of a generating plant, as of December 31, 2005, the supply of electric power available to SDG&E is as follows:
Supplier Source Expiration
date Megawatts
(MW)
PURCHASED POWER CONTRACTS:
DWR ** -allocated contracts:
Williams Energy Marketing & Trading Natural gas 2007 to 2010 1,906 *
Sunrise Power Co. LLC Natural gas 2012 574
Other Natural gas / wind 2006 to 2013 227
Total 2,707
Other contracts with Qualifying Facilities (QFs):
Applied Energy Inc. Cogeneration 2019 102
Yuma Cogeneration Cogeneration 2024 50
Goal Line Limited Partnership Cogeneration 2025 50
Other (16 contracts) Cogeneration 2009 and thereafter 61
Total 263
Other contracts with renewable sources:
Oasis Power Partners Wind 2019 60
AES Delano Bio-mass 2007 49
PPM Energy Wind 2018 25
WTE / FPL Wind 2019 17
Other (6 contracts) Bio-gas 2007-2014 24
Total 175
Other long-term contracts:
Portland General Electric (PGE) Coal 2013 89
Total contracted 3,234
GENERATION:
SONGS 430
Miramar 47
Total Generation 477
TOTAL CONTRACTED AND GENERATION 3,711
* Effective January 1, 2007, 1,200 megawatts were reallocated to Southern California Edison (Edison) by the CPUC, as described in Note 9 of the notes to Consolidated Financial Statements.
** Department of Water Resources
Under the contract with PGE, SDG&E pays a capacity charge plus a charge based on the amount of energy received and/or PGE's non-fuel costs. Costs under the contracts with QFs are based on SDG&E's avoided cost. Charges under the remaining contracts are for firm and regulatory responses have
significantly impactedas-available energy and are based on the company's operations. amount of energy received. The prices under these contracts are at the market value at the time the contracts were negotiated.
SONGS
SDG&E owns 20 percent of SONGS, which is located south of San Clemente, California. SONGS consists of three nuclear generating units. The cities of Riverside and Anaheim own a total of 5 percent of Units 2 and 3. Edison owns the remaining interests and is the operator of SONGS.
Unit 1 was removed from service in November 1992 when the CPUC issued a decision to permanently shut it down. Decommissioning of Unit 1 is now in progress and its spent nuclear fuel is being stored on site.
Units 2 and 3 began commercial operation in August 1983 and April 1984, respectively. SDG&E's share of the capacity is 214 MW of Unit 2 and 216 MW of Unit 3.
SDG&E had fully recovered its SONGS capital investment through December 31, 2003.
Additional information on electric-industry restructuringconcerning the SONGS units and nuclear decommissioning is provided above under "Electric
Operations,"below, in "Environmental Matters" herein, and in "Management's Discussion and Analysis of Financial Condition and Results of Operations,"Operations" and in Notes 3, 9 and 11 of the notes to Consolidated Financial Statements herein.
Nuclear Fuel Supply
The nuclear fuel supply cycle includes materials and services (uranium oxide, conversion of uranium oxide to uranium hexafluoride, uranium enrichment services, and fabrication of fuel assemblies) performed by others under various contracts which extend through 2008. The availability and the cost of the various components of the nuclear-fuel cycle for SDG&E's nuclear facilities in subsequent years cannot be estimated at this time.
Spent fuel from SONGS is being stored on site in the independent spent fuel storage installation, where storage capacity is expected to be adequate through 2022, the expiration date of the units' NRC operating license. Pursuant to the Nuclear Waste Policy Act of 1982, SDG&E entered into a contract with the U.S. Department of Energy (DOE) for spent-fuel disposal. Under the agreement, the DOE is responsible for the ultimate disposal of spent fuel from SONGS. SDG&E pays the DOE a disposal fee of $1.00 per megawatt-hour of net nuclear generation, or $3 million per year. The DOE projects that it will not begin accepting spent fuel until 2010 at the earliest.
Additional information concerning nuclear-fuel costs and the storage and movement of spent fuel is provided in Notes 9 and 11, respectively, of the notes to Consolidated Financial Statements herein.
Power Pools
SDG&E is a participant in the Western Systems Power Pool, which includes an electric-power and transmission-rate agreement with utilities and power agencies located throughout the United States and Canada. More than 270 investor-owned and municipal utilities, state and federal power agencies, energy brokers, and power marketers share power and information in order to increase efficiency and competition in the bulk power market. Participants are able to make power transactions on standardized terms that have been pre-approved by the FERC.
Transmission Arrangements
The Pacific Intertie, consisting of AC and DC transmission lines, connects the Northwest with SDG&E, Pacific Gas & Electric (PG&E), Edison and others under an agreement that expires in July 2007. SDG&E's share of the Pacific Intertie is 266 MW.
Power originating from sources utilizing the Pacific Intertie, as well as power from other sources, can be imported into SDG&E's system via the Edison-SDG&E interconnection at the SONGS switchyard. Five 230-kilovolt transmission lines into SDG&E's system from that interconnection comprise the "South of SONGS" path, which is normally rated at 2200 MW.
SDG&E's 500-kilovolt Southwest Powerlink transmission line, which is shared with Arizona Public Service Company and Imperial Irrigation District, extends from Palo Verde, Arizona to San Diego. SDG&E's share of the line is 970 MW, although it can be less under certain system conditions.
Mexico's Baja California Norte system is connected to SDG&E's system via two 230-kilovolt interconnections with firm capability of 408 MW in the north to south direction and 800 MW in the south to north direction.
SDG&E is in the planning stages for the Sunrise Powerlink, a new 500-kilovolt transmission line between the existing Imperial Valley Substation and a new Central Substation to be located within the SDG&E system. The proposed rating of the Sunrise Powerlink is 1,000 MW or higher. The project is subject to CPUC approval and is estimated to cost at least $1 billion. The planned in-service date is June 2010.
Transmission Access
The National Energy Policy Act governs procedures for others' requests for transmission service. The FERC approved the California IOUs' transfer of operation and control of their transmission facilities to the Independent System Operator (ISO) in 1998. Additional information regarding the FERC, ISO and transmission issues is provided in Note 10 of the notes to Consolidated Financial Statements herein.

Natural Gas Industry Restructuring

The natural gas industry in California experienced an initial phase of
restructuring during
RATES AND REGULATION
Information concerning rates and regulations applicable to the 1980s. In December 2001 the CPUC issued a
decision adopting provisions affecting the structure of the natural gas
industry in California, some of which could introduce additional
volatility into the earnings of SDG&E and other market participants.
During 2002 the California Utilities filed a proposed implementation
schedule and revised tariffs and rules required for implementation.
However, protests of these compliance filings were filed, and the CPUC
has not yet authorized implementation of most of the provisions of its
decision. Additional information on natural gas industry restructuringcompany is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 11Notes 1, 9 and 10 of the notes to Consolidated Financial Statements herein.

Balancing Accounts

In general, earnings fluctuations from changes in the costs of natural
gas and consumption levels for the majority of natural gas are
eliminated through balancing accounts authorized by the CPUC. As a
result of California's electric restructuring law, overcollections
recorded in the electric balancing accounts were applied to transition
cost recovery, and fluctuations in certain costs and consumption levels
can now affect earnings from electric operations. In addition,
fluctuations in certain costs and consumption levels affect earnings
from the California Utilities' natural gas operations. Additional
information on balancing accounts is provided in "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" and in Note 1 of the notes to Consolidated Financial
Statements herein.

Biennial Cost Allocation Proceeding (BCAP)

Rates to recover the changes in the cost of natural gas transportation
services are determined in the BCAP. Additional information on the BCAP
is provided in Note 11 of the notes to Consolidated Financial
Statements herein.

Cost of Capital

The authorized cost of capital is determined by an automatic adjustment
mechanism based on changes in certain capital market indices.
Additional information on SDG&E's cost of capital is provided in
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" and in Note 11 of the notes to Consolidated
Financial Statements herein.

Performance-Based Regulation (PBR)

To promote efficient operations and improved productivity and to move
away from reasonableness reviews and disallowances, the CPUC adopted
PBR for SDG&E effective in 1994. PBR has resulted in modification to
the general rate case and certain other regulatory proceedings for
SDG&E. Under PBR, regulators require future income potential to be tied
to achieving or exceeding specific performance and productivity goals,
rather than relying solely on expanding utility plant to increase
earnings. The three areas that are eligible for PBR rewards are
operational incentives based on measurements of safety, reliability and
customer satisfaction; demand-side management (DSM) rewards based on
the effectiveness of the programs; and natural gas procurement rewards.
Rewards resulting from PBR are not included in the company's earnings
before they are approved by the CPUC. Additional information on SDG&E's
PBR mechanism is provided in "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and in Note 11 of the
notes to Consolidated Financial Statements herein.

16
ENVIRONMENTAL MATTERS
Discussions about environmental issues affecting the company are included in Note 1211 of the notes to Consolidated Financial Statements herein. The following additional information should be read in conjunction with those discussions.
Hazardous Substances
In 1994, the CPUC approved the Hazardous Waste Collaborative Memorandum account, allowing California's IOUs to recover their hazardous waste cleanup costs, including those related to Superfund sites or similar sites requiring cleanup. Cleanup costs at sites related to electric
generation were specifically excluded from the collaborative by the
CPUC. Recovery of 90 percent of hazardous waste cleanup costs and related third-party litigation costs, and 70 percent of the related insurance-litigation expenses is permitted. In addition, the company has the opportunity to retain a percentage of any insurance recoveries to offset the 10 percent of costs not recovered in rates.

During the early 1900s, SDG&E and its predecessors manufactured gas
from coal or oil. The manufacturing sites often have become
contaminated with the hazardous residual by-products of the process.
SDG&E identified three former manufactured-gas plant sites, remediation
of which was completed at two of the sites in 1998 and 2000. Closure
letters have been received for the two sites.
At December 31, 2002
estimated remaining remediation liability on2005, the third site is $1.5
million.

SDG&E soldcompany had accrued its fossil-fuel generating facilities in 1999. As a part of
its due diligence for the sale, SDG&E conducted a thorough
environmental assessment of the facilities. Pursuant to the sale
agreements for such facilities, SDG&E and the buyers have apportioned
responsibility for such environmental conditions generally based on
contamination existing at the time of transfer and the cleanup level
necessary for the continued use of the sites as industrial sites. While
the sites are relatively clean, the assessments identified some
instances of significant contamination, principally resulting from
hydrocarbon releases, for which SDG&E has a cleanup obligation under
the agreement. Estimated costs to perform the necessary remediation are
$11 million. These costs were offset against the sales price for the
facilities, together with other appropriate costs, and the remaining
net proceeds were included in the calculation of customer rates.
Remediation of the plants commenced in early 2001. During 2002, cleanup
was completed at several minor sites at a cost of $0.4 million. In late
2002, additional assessments were started at the primary sites, where
cleanup in expected to commence by the end of 2003 and be completed by
2005.

SDG&E lawfully disposes of wastes at permitted facilities owned and
operated by other entities. Operations at these facilities may result
in actual or threatened risks to the environment or public health.
Under California law, businesses that arrange for legal disposal of
wastes at a permitted facility from which wastes are later released, or
threaten to be released, can be held financially responsible for
corrective actions at the facility.

At December 31, 2002, the company's estimated remaining investigation and remediation liability related to hazardous waste sites, including the manufactured gas sites, was $3numerous locations that had been manufactured-gas plants, of $7.2 million, of which 90 percent is authorized to be recovered through the Hazardous Waste Collaborative mechanism. This estimated cost excludes remediation costs of $10.3 million associated with SDG&E's former fossil-fuel power plants. The company believes that any costs not ultimately recovered through rates, insurance or other means will not have a material adverse effect on the company's consolidated results of operations or financial position.
Estimated liabilities for environmental remediation are recorded when amounts are probable and estimable. Amounts authorized to be recovered in rates under the Hazardous Waste Collaborative mechanism are recorded as a regulatory asset.
Electric and Magnetic Fields (EMFs)
Although scientists continue to research the possibility that exposure to EMFs causes adverse health effects, science has not demonstrated a cause-and-effect relationship between exposure to the type of EMFs emitted by power lines and other electrical facilities and adverse health effects. Some laboratory studies suggest that such exposure creates biological effects, but those effects have not been shown to be harmful. The studies that have most concerned the public are epidemiological studies, some of which have reported a weak correlation between childhood leukemia and the proximity of homes to certain power lines and equipment and
childhood leukemia.equipment. Other epidemiological studies found no correlation between estimated exposure and any disease. Scientists cannot explain why some studies using estimates of past exposure report correlations between estimated EMF levels and disease, while others do not.
To respond to public concerns, the CPUC haspreviously directed California IOUs to adopt a low-cost EMF-reduction policy that requires reasonable design changes to achieve noticeable reduction of EMF levels that are anticipated from new projects. However, consistent with the major
scientific reviews of the available research literature, theThe CPUC has indicated thatrecently reviewed the resultant policy in an Order Instituting Ratemaking and found no health risk has been identified.

new scientific research to support a change to the existing policy, finding existing policy of prudent avoidance to be sufficient and reasonable.
Air and Water Quality

California's air quality standards are more restrictive than federal
standards. However, as a result of the sale of the company's fossil-
fuel generating facilities, the company's primary air-quality issue,
compliance with these standards now has less significance to the
company's operation.

The transmission and distribution of natural gas require the operation of compressor stations, which are subject to increasingly stringent air-quality standards. Costs to comply with these standards are recovered in rates.
In connection with the issuance of operating permits, SDG&E and the other owners of SONGS previously reached agreement with the California Coastal Commission to mitigate the environmental damage to the marine environment attributed to the cooling-water discharge from SONGS Units 2 and 3. This mitigation program includes an enhanced fish-protection
system, a 150-acre artificial reef and restoration of 150 acres of

coastal wetlands. In addition, the owners must deposit $3.6 million
with the state for the enhancement of fish hatchery programs and pay
for monitoring and oversight of the mitigation projects. SDG&E's share of the cost is estimated to be $34.8 million. These mitigation projects
are expected to be completed by 2007. Through$34 million, of which $16 million had been incurred at December 31, 2003, SONGS
mitigation2005. Rate recovery of 50% of the remaining costs are recovered through the Incremental Cost Incentive
Pricing mechanism. Costs thereafter are anticipated to be recovered in
customer rates.

is uncertain.
OTHER MATTERS
Research, Development and Demonstration (RD&D)

For 2002,
Effective January 2005, a surcharge was established by the CPUC authorizedfor natural gas public interest RD&D. The natural gas public interest research program is administered by the CEC. For 2005, the funding level is subject to a statewide cap of $12 million. The statewide cap increases to $15 million in 2006. For 2005, SDG&E funding for the natural gas public purpose RD&D program was $1 million.
SDG&E continues to fund $1.2 million and $4.0the California Public Interest Energy Research (PIER) Program for electric research. For 2005, SDG&E's funding level was $6 million for its natural gas and electric RD&D programs, respectively,
which includes $3.9 million to the CEC for its PIER (Public Interest
Energy Research) Program. SDG&E co-funded several of these projects
with the CEC. SDG&E's annual RD&D costs have averaged $4.4 million over
the past three years.

program.
Employees of Registrant
As of December 31, 20022005, the company had 4,1304,505 employees, compared to 3,1064,405 at December 31, 2001. The increase is due to transferring certain
central functions for SDG&E and its affiliate, SoCalGas, from Sempra
Energy to SDG&E effective April 1, 2002.

2004.
Labor Relations
Certain employees at SDG&E are represented by the Local 465 International Brotherhood of Electrical Workers. The current contract runsis in effect through August 31, 2004.

2008.
ITEM 2. PROPERTIES
Electric Properties
SDG&E's generating capacityinterest in SONGS is described in "Electric Resources" herein. At December 31, 2002,2005, SDG&E's electric transmission and distribution facilities included substations, and overhead and underground lines. The electric facilities are located in San Diego, Imperial and Orange counties of California and in Arizona, and consist of 1,8021,835 miles of transmission lines and 21,09521,601 miles of distribution lines. Periodically, various areas of the service territory require expansion to accommodate customer growth.
In 2005, SDG&E purchased a 45-MW electric generation facility located in San Diego, California. In 2006, SDG&E will purchase the 550-MW Palomar power plant, located in Escondido, California, which is being constructed by Sempra Generation.
Natural Gas Properties
At December 31, 2002,2005, SDG&E's natural gas facilities, which are located in San Diego and Riverside counties of California, consisted of the Moreno and Rainbow compressor stations, 166 miles of high pressure transmission pipelines, 7,6178,100 miles of high and low pressure distribution mains, and 6,0796,197 miles of service lines.

19
Other Properties
SDG&E occupies an office complex in San Diego pursuant to an operating lease ending in 2007. The lease can be renewed for two five-year periods.

SDG&E
The company owns or leases other warehouses, offices, operating and maintenance centers, shops, service facilities and equipment necessary in the conduct of its business.
ITEM 3. LEGAL PROCEEDINGS
Except for the matters described in Note 1211 of the notes to Consolidated Financial Statements or referred to elsewhere in this Annual Report, neither the company nor its subsidiary areis party to, nor is their property the subject of, any material pending legal proceedings other than routine litigation incidentalproceedings.
Sempra Energy and SDG&E are defendants in a lawsuit filed by the County of San Diego seeking civil penalties for alleged violations of environmental standards applicable to their
businesses.

the abatement, handling and disposal of asbestos-containing materials during the demolition of a natural gas storage facility in 2001. In a federal criminal indictment, SDG&E and two employees have also been charged with having violated these standards and with conspiracy and making false statements to governmental authorities in connection with these matters. Sempra Energy and SDG&E believe that the maximum fines and penalties that could reasonably be assessed against them with respect to these matters would not exceed $750,000. The company believes that the claims and charges are without merit and is vigorously contesting them.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
All of the issued and outstanding common stock of SDG&E is owned by Enova Corporation, a wholly owned subsidiary of Sempra Energy. The information required by Item 5 concerning dividends declareddividend declarations is included in the "Statements of Consolidated Changes in Shareholders' Equity" set forth in Item 8 of thisthe 2005 Annual Report to Shareholders herein.

20
ITEM 6. SELECTED FINANCIAL DATA
(Dollars in millions) At December 31, or for the years then ended
- -----------------------------------------------------------------------------------
2002 2001 2000 1999 1998
------ ------ ------ ------ ------

Income Statement Data:
Operating revenues $ 1,696 $ 2,362 $ 2,671 $ 2,207 $ 2,249
Operating income $ 262 $ 221 $ 235 $ 281 $ 286
Dividends on preferred stock $ 6 $ 6 $ 6 $ 6 $ 6
Earnings applicable to
common shares $ 203 $ 177 $ 145 $ 193 $ 185

Balance Sheet Data:
Total assets $ 5,123 $ 5,399 $ 4,734 $ 4,366 $ 4,257
Long-term debt $ 1,153 $ 1,229 $ 1,281 $ 1,418 $ 1,548
Short-term debt (a) $ 66 $ 93 $ 66 $ 66 $ 72
Preferred stock subject to
mandatory redemption $ 25 $ 25 $ 25 $ 25 $ 25
Shareholders' equity $ 1,223 $ 1,165 $ 1,138 $ 1,393 $ 1,203

(a) Includes long-term debt due within one year.
(Dollars in millions, except per share amounts) At December 31, or for the years then ended
2005 2004 2003 2002 2001
Income Statement Data:
Operating revenues $ 2,512 $ 2,274 $ 2,308 $ 1,725 $ 2,359
Operating income $ 283 $ 256 $ 388 $ 256 $ 241
Dividends on preferred stock $ 5 $ 5 $ 6 $ 6 $ 6
Earnings applicable to common shares $ 262 $ 208 $ 334 $ 203 $ 177
Balance Sheet Data:
Total assets $ 7,492 $ 6,834 $ 6,461 $ 6,285 $ 6,542
Long-term debt $ 1,455 $ 1,022 $ 1,087 $ 1,153 $ 1,229
Short-term debt (a) $ 66 $ 66 $ 66 $ 66 $ 93
Preferred stock subject to mandatory redemption (b) $ -- $ -- $ -- $ 25 $ 25
Shareholders' equity $ 1,562 $ 1,376 $ 1,343 $ 1,223 $ 1,165
(a) Includes long-term debt due within one year.
(b) At December 31, 2005 and 2004, $16 million and $19 million, respectively, were included in Deferred Credits and Other Liabilities, and $3 million and $2 million, respectively, were included in Other Current Liabilities on the Consolidated Balance Sheets.
Since San Diego Gas & Electric CompanySDG&E is a wholly owned subsidiary of Enova Corporation, per share data is not provided.

This data should be read in conjunction with the Consolidated Financial Statements and the notes to Consolidated Financial Statements contained herein.

ITEM
Item 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
This section of the 2005 Annual Report includes management's discussion and analysis of operating results from 20002003 through 2002,2005, and provides information about the capital resources, liquidity and financial performance of San Diego Gas & Electric Company (SDG&E or the company). ""This section also focuses on the major factors expected to influence future operating results and discusses investment and financing activities and plans. It should be read in conjunction with the Consolidated Financial Statements included herein.

in this Annual Report.
The company is an operating public utility engaged in the electric business, serving 3.4 million consumers, and in the natural gas businesses, which provides services tobusiness, serving 3.1 million customers.consumers. It distributes electric energy, purchased from others or generated from its 20 percent interest in a nuclear facility, through 1.3 million electric meters in San Diego County and an adjacent portion of southern Orange County, California. It also purchases and distributes natural gas through 789,000825,000 meters in San Diego County and 21
transports electricity and natural gas for others. SDG&E's service areaterritory encompasses 4,100 square miles, covering 26 cities.miles. SDG&E's only subsidiary is SDG&E Funding LLC, which was formed to facilitate the issuance of SDG&E's rate reduction bonds described in Note 32 of the notes to Consolidated Financial Statements. Business CombinationSDG&E is a substantially wholly owned indirect subsidiary of Sempra Energy (the Parent) was formed to serve as a holding company for
Pacific Enterprises (PE), the parent corporation ofEnergy. SDG&E and its sister utility, Southern California Gas Company (SoCalGas), which distributes natural gas throughou t most of Southern California and Enova Corporation (Enova), the parent
corporationa portion of SDG&E, in a tax-free business combination that became
effective on June 26, 1998.

central California, are collectively referred to herein as "the California Utilities."
RESULTS OF OPERATIONS

To understand the operations and financial results
The following table shows net income for each of the last five years.
(Dollars in millions)
2005 $ 267
2004 $ 213
2003 $ 340
2002 $ 209
2001 $ 183
Comparison of Earnings
To assist the reader in understanding the trend of earnings, the following table summarizes the major unusual factors affecting net income and operating income in 2005, 2004 and 2003. The numbers in parentheses are the page numbers where each 2005 item is discussed therein.
Net Income Operating Income
(Dollars in millions) 2005 2004 2003 2005 2004 2003
Reported amounts $ 267 $ 213 $ 340 $ 283 $ 256 $ 388
Unusual items:
Resolution of prior years' income tax issues (21) (60 ) (12 ) (79 ) (60 ) (12 ) (79 )
Increase in California energy crisis litigation reserves (66) 28 11 11 28 11 11
South Bay charitable contribution deduction (21) (23 ) -- -- (21 ) -- --
DSM¹ awards (62) (22 ) -- -- (21 ) -- --
Other regulatory matters (66) (23 ) (21 ) -- (20 ) (15 ) --
Power contract settlement -- -- (65 ) -- -- (65 )
SONGS2 incentive pricing (ended 12/31/03) -- -- (53 ) -- -- (53 )
$ 167 $ 191 $ 154 $ 189 $ 240 $ 202
1Demand side management (DSM)
² San Onofre Nuclear Generating Station (SONGS)
The company itissubject to federal, state and local governmental agencies. The primary regulatory agency is important to understand the ratemaking procedures to which the
company is subject.

SDG&E is regulated primarily by the California Public Utilities Commission (CPUC). It is, which regulates utility rates and operations. The Federal Energy Regulatory Commission (FERC) regulates interstate transportation of natural gas and electricity and various related matters. The Nuclear Regulatory Commission regulates nuclear generating plants. Municipalities and other local authorities regulate the responsibilitylocation of the CPUCutility assets, including natural gas pipelines and electric lines.
Electric Revenue and Cost of Electric Fuel and Purchased Power.Electric revenues increased by $125 million (7%) to regulate
investor-owned utilities (IOUs)$1.8 billion in a manner that serves the best
interests of their customers while providing the IOUs the opportunity
to earn a reasonable return on investment.

In 1996, California enacted legislation restructuring California's
electric industry. The legislation and related decisions of the CPUC
were intended to stimulate competition and reduce electric rates. As
part of the framework for a competitive electric-generation market, the
legislation established the California Power Exchange (PX)2005, and the Independent System Operator (ISO).cost of electric fuel and purchased power increased by $48 million (8%) to $624 million in 2005. The PX served asincrease in revenue was due to $41 million of higher revenues for recoverable expenses, which are fully offset in other operating expenses, a wholesaleDSM award settlement in 2005 of $28 million and $23 million related to the 2005 Internal Revenue Service (IRS) decision relating to the sale of SDG&E's former South Bay power poolplant. In addition, revenues and costs increased $48 million due to higher purchased power costs.
Electric revenues decreased by $123 million (7%) to $1.7 billion in 2004 compared to 2003, and the ISO scheduledcost of electric fuel and purchased power transactions and accessincreased by $35 million (6%) to $576 million in 2004 compared to 2003. The decrease in revenues was due to the electric transmission system. Supply/demand imbalancesrecognition of $116 million related to the approved settlement that allocated between SDG&E's customers and a number of
other factors resulted in abnormally high electric commodity costs
beginning in mid-2000 and continuing into 2001. Due to subsequent
industry restructuring developments,shareholders the PX suspended its trading
operations in January 2001. As a result of the passage of Assembly
Bill (AB) X1 in February 2001, the California Department of Water and
Resources (DWR) began toprofits from certain intermediate-term purchase power contracts in the third quarter of 2003, and higher 2003 earnings of $25 million from generators and marketers
to supply a portion of the power requirements of the state's population
that is served by IOUs. Through December 31, 2002, the DWR was
purchasing SDG&E's full net short position (the power needed by SDG&E's
customers other than that provided by SDG&E's nuclear generating
facilities or its previously existing purchased power contracts).
Starting on January 1, 2003, SDG&E and the other IOUs resumed their
electric commodity procurement function based on a CPUC decision issuedPerformance-Based Regulation (PBR) awards. Performance awards are discussed in October 2002.

The natural gas industry experienced an initial phase of restructuring
during the 1980s by deregulating natural gas sales to noncore
customers. In December 2001, the CPUC issued a decision related to
natural gas industry restructuring, adopting several provisions that
the company believes will make natural gas service more reliable, more
efficient and better tailored to the desires of customers. The CPUC
anticipated implementation during 2002; however, implementation has
been delayed.

In connection with restructuring of the electric and natural gas
industries, the company received approval from the CPUC for
Performance-Based Ratemaking (PBR). Under PBR, income potential is tied
to achieving or exceeding specific performance and productivity
measures, such as service, safety, reliability, demand side management
and customer growth, rather than solely to expanding utility plant.

See additional discussion of these situations under "Factors
Influencing Future Performance" and in NotesNote 10 and 11 of the notes to Consolidated Financial Statements. In addition, electric revenues and costs increased $35 million due to higher electric commodity costs and volumes.
Natural Gas Revenue and Cost of Natural Gas.Natural gas revenues increased by $113 million (19%) to $709 million in 2005, and the cost of natural gas increased by $109 million (31%) to $456 million in2005. The increases in 2005 were due to higher natural gas prices, which are passed on to customers, offset by a small decrease in volume. In addition,natural gas revenuesincreased due to $7 million in DSM awards in 2005. The company's weighted average cost per million British thermal units (mmbtu) of natural gas was $8.67in 2005, $6.11in 2004 and $5.14in 2003.
Although the current regulatory framework provides that the cost of natural gas purchased for customers and the variations in that cost are passed through to the customers on a substantially concurrent basis, SDG&E's natural gas procurement PBR mechanism provides an incentive mechanism by measuring SDG&E's procurement of natural gas against a benchmark price comprised of monthly natural gas indices, resulting in shareholder rewards for costs achieved below the benchmark and shareholder penalties when costs exceed the benchmark. Further discussion is provided in Notes 1 and 10 of the notes to Consolidated Financial Statements.
Natural gas revenues increased by $89 million (18%) to $596 million in 2004 compared to 2003, and the cost of natural gas increased by $73 million (27%) to $347 million in 2004 compared to 2003. The increase in 2004 was primarily attributable to natural gas price increases.
The tables below summarize the components of electric and natural gas volumes and revenues by customer class.

ELECTRIC TRANSMISSION AND DISTRIBUTION
(Dollars in millions, volumes in million kWhs)class for the years ended December 31

2002 2001 2000
-----------------------------------------------------------------------
Volumes Revenue Volumes Revenue Volumes Revenue
-----------------------------------------------------------------------

Residential 6,266 $ 649 6,011 $ 775 6,304 $ 730
Commercial 6,053 633 6,107 753 6,123 747
Industrial 1,893 161 2,792 325 2,614 310
Direct access 3,448 117 2,464 84 3,308 99
Street and highway lighting 88 9 89 10 74 7
Off-system sales 5 -- 413 88 899 59
----------------------------------------------------------------------
17,753 1,569 17,876 2,035 19,322 1,952
Balancing and other (295) (359) 232
-----------------------------------------------------------------------
Total 17,753 $1,274 17,876 $1,676 19,322 $2,184
-----------------------------------------------------------------------

Although commodity-related revenues from the DWR's purchasingyears ended December 31, 2005, 2004 and 2003.
Electric Distribution and Transmission
(Volumes in millions of the
company's net short position are not includedkWhs, dollars in revenue, the
associated volumes and distribution revenue are included herein.

NATURAL GAS SALES, TRANSPORTATION & EXCHANGE
(Dollars in millions, volumes in billion cubic feet)
for the years ended December 31

Natural Gas Sales Transportation & Exchange Total
----------------------------------------------------------------------
Volumes Revenue Volumes Revenue Volumes Revenue
----------------------------------------------------------------------

2002:
Residential 33 $ 246 -- $ 1 33 $ 247
Commercial and industrial 17 98 5 15 22 113
Electric generation plants -- -- 85 16 85 16
---------------------------------------------------------------
50 $ 344 90 $ 32 140 376
Balancing accounts and other 46
--------
Total $ 422
- ---------------------------------------------------------------------------------------------
2001:
Residential 34 $ 461 -- $ -- 34 $ 461
Commercial and industrial 18 233 4 18 22 251
Electric generation plants -- -- 99 23 99 23
---------------------------------------------------------------
52 $ 694 103 $ 41 155 735
Balancing accounts and other (49)
--------
Total $ 686
- ---------------------------------------------------------------------------------------------
2000:
Residential 33 $ 279 -- $ 1 33 $ 280
Commercial and industrial 21 139 22 16 43 155
Electric generation plants -- -- 63 24 63 24
---------------------------------------------------------------
54 $ 418 85 $ 41 139 459
Balancing accounts and other 28
--------
Total $ 487
- ---------------------------------------------------------------------------------------------

2002 Compared to 2001
Electric Revenue and Cost of Electric Fuel and Purchased Power.
Electric revenues decreased to $1.3 billion in 2002 from $1.7 billion
in 2001, and the cost of electric fuel and purchased power decreased to
$0.3 billion in 2002 from $0.8 billion in 2001. These decreases were
primarily due to the DWR's purchases of SDG&E's net short position for
a full year in 2002, the effect of lower electric commodity costs and
decreased off-system sales. Under the current regulatory framework,
changes in commodity costs normally do not affect net income. Themillions)
2005 2004 2003
Volumes Revenue Volumes Revenue Volumes Revenue
Residential 7,075 $ 738 7,038 $ 692 6,702 $ 731
Commercial 6,674 654 6,592 644 6,263 674
Industrial 2,159 142 2,084 134 1,987 162
Direct access 3,213 114 3,441 105 3,322 87
Street and highway lighting 93 11 97 11 91 11
Off-system sales -- -- -- -- 8 --
19,214 1,659 19,252 1,586 18,373 1,665
Balancing accounts and other 144 92 136
Total $ 1,803 $ 1,678 $ 1,801
Although commodity costs associated with the DWR's purchases and the
corresponding salelong-term contracts allocated to SDG&E's customers&E from the Department of Water Resources (DWR) (and the revenues to recover those costs) are not included in the Statements of Consolidated Income, as SDG&E was merely transmitting the
electricity from the DWR to the customers. Similarly, in 2001, PX/ISO
power revenues have been netted against purchased-power expense to
avoid double counting as SDG&E sold power to the PX/ISO and then
purchased power therefrom.

For the fourth quarter, electric revenues increased to $324 million in
2002 from $284 million in 2001, and the cost of electric fuel and
purchased power decreased to $76 million in 2002 from $87 million in
2001. The increase in electric revenues was due primarily to higher
electric distribution and transmission revenue as well as additional

revenues from the Incremental Cost Incentive Pricing (ICIP) mechanism,
while the decrease in cost of electric fuel and purchased power was due
primarily to a decrease in average electric commodity costs. Refer to
Note 10 of the notes to Consolidated Financial Statements for further
discussion of ICIP and the San Onofre Nuclear Generating Station
(SONGS).

Natural Gas Revenue and Cost of Gas Distributed. Natural gas
revenues decreased to $422 million in 2002 from $686 million in 2001,
and the cost of natural gas distributed decreased to $205 million in
2002 from $457 million in 2001. These decreases were primarily due to
lower average natural gas commodity prices as well as lower volumes of
gas sales in 2002. The reduction in natural gas volumes in the electric
generation market is largely attributable to the loss of approximately
100 million cubic feet per day of throughput on the SDG&E system when
the North Baja pipeline began service in September 2002 and to the
lower level of electric generation demand.

Under the current regulatory framework, changes in core-market natural
gas prices (natural gas purchased for customers that are primarily
residential and small commercial and industrial customers, without
alternative fuel capability) or consumption levels do not affect net
income, since core customer rates generally recover the actual cost of
natural gas on a substantially concurrent basis and consumption levels
are fully balanced. See further discussiondiscussed in Note 1 of the notes to Consolidated Financial Statements.

Other Operating Expenses. Other operatingStatements, the associated volumes and distribution revenues are included in the above table.
Natural Gas Sales, Transportation and Exchange
(Volumes in billion cubic feet, dollars in millions)
Transportation
and Exchange
Natural Gas Sales Total
Volumes Revenue Volumes Revenue Volumes Revenue
2005:
Residential 31 $ 381 -- $ -- 31 $ 381
Commercial and industrial 17 174 4 5 21 179
Electric generation plants 1 3 59 39 60 42
49 $ 558 63 $ 44 112 602
Balancing accounts and other 107
Total $ 709
2004:
Residential 33 $ 332 -- $ -- 33 $ 332
Commercial and industrial 18 142 4 4 22 146
Electric generation plants -- 2 74 36 74 38
51 $ 476 78 $ 40 129 516
Balancing accounts and other 80
Total $ 596
2003:
Residential 32 $ 291 -- $ -- 32 $ 291
Commercial and industrial 17 127 4 5 21 132
Electric generation plants -- 3 62 30 62 33
49 $ 421 66 $ 35 115 456
Balancing accounts and other 51
Total $ 507
Litigation Expenses.Litigation expenses increased to
$531were $52 million, in 2002 from $491 million in 2001. For the fourth quarter,
other operating expenses increased to $164 million in 2002 from $147
million in 2001. These increases were primarily due to higher labor and
employee benefits costs and increases in other operating costs,
including operating costs that are associated with nuclear generating
facilities.

Other Income. Other income and deductions, which primarily
consist of interest income and/or expense from short-term investments
and regulatory balancing accounts, decreased to $24 million in 2002
from $54 million in 2001. For the fourth quarter, other income
decreased to $10 million in 2002 from $38 million in 2001. The
decreases were primarily due to the reduced interest income from short-
term investments, as well as the $19 million gain on sale of SDG&E's
Blythe, California propertyand $17 million for 2005, 2004 and 2003, respectively. The increase in 2001 (discussed below in "Cash Flows
From Investing Activities").

Interest Expense. Interest expense was $77 million and $92
million in 2002 and 2001, respectively. For the fourth quarter,
interest expense decreased to $18 million in 2002 from $22 million in
2001. The decrease in interest expense in 20022005 was primarily due to lower interest incurred asan increase in litigation reserves related to matters arising from the result of lower average debt and lower
interest rates in 2002. Interest rates on certain of the company's debt
can vary with credit ratings, as described in Notes 2 and 32000 - 2001 California energy crisis. Note 11 of the notes to Consolidated Financial Statements. In addition, seeStatements provides additional information concerning this matter.
Other Operating Expenses.Other operating expenses were $603 million, $574 million and $611 million in 2005, 2004 and 2003, respectively. The increase in 2005 was due to $37 million of higher recoverable expenses, $34 million of favorable resolution of regulatory matters in 2004 and increases in various other operational costs, offset by the $42 million net effect related to the 2005 recovery of line losses and grid management charges arising from the favorable settlement with the Independent System Operator (ISO, an independent operator of California's wholesale transmission grid). The decrease in 2004 from 2003 was due primarily to the favorable resolution of regulatory matters.
Other Income, Net. Other income, net, as discussed further
discussion of rate-reduction bonds in Note 3.

25
1 of the notes to Consolidated Financial Statements, consists primarily of interest income from short-term investments, income taxes on non-operating income, interest income/expense from regulatory balancing accounts and allowance for equity funds used during construction. Excluding the impact of income taxes on non-operating income, other income was $37 million, $36 million and $46 million in 2005, 2004 and 2003, respectively. The decrease in 2004 from 2003 was due to higher interest income in 2003 resulting from the favorable $37 million before-tax resolution of income-tax issues with the IRS, offset by a lesser amount of interest earned on income tax receivables during 2004.
Income Taxes. IncomeTaxes.Income tax expense was $91 million and $141$89 million for the years ended December 31, 20022005 and 2001, respectively.$148 million for each of 2004 and 2003. The corresponding effective income tax rates were 30.325 percent, 41 percent and 43.5 percent for the
same years.30 percent. The decrease in income tax2005 expense was primarily due to the fact that SDG&E receivedlower effective tax rate. The decrease in the effective rate was due primarily to a $25 million favorable resolution of income-
tax issues from prior years in 2002.

Net Income. Net income increased to $209 million in 2002 from
$183 million in 2001. The increase was primarily due to the $25$60 million favorable resolution of prior year income-taxyears' income tax issues in the second
quarter of 2002 and lower interest expense in 2002, partially offset by
the 2001 gain on the sale of SDG&E's Blythe property and lower interest
income in 2002. Net income increased to $54 million for the fourth
quarter of 2002,2005, compared to $46 million for the corresponding period
of 2001, primarily due to higher natural gas and electric distribution
and transmission revenues and income-tax adjustments in 2002, partially
offset by the 2001 Blythe gain.

2001 Compared to 2000
Electric Revenue and Cost of Electric Fuel and Purchased Power.
Electric revenues decreased to $1.7 billion in 2001 from $2.2 billion
in 2000, and the cost of electric fuel and purchased power decreased to
$0.8 billion in 2001 from $1.3 billion in 2000. For the fourth quarter,
electric revenues decreased to $284$12 million in 2001 from $717 million
in 2000, and the cost of electric fuel and purchased power decreased to
$87 million in 2001 from $485 million in 2000. These decreases were
primarily due to the DWR's purchasing of SDG&E's net short position
starting in February 2001, offset by a $30 million after-tax charge for
regulatory issues in 2000 related to a potential regulatory
disallowance for the acquisition of wholesale power in the newly
deregulated California market.
Natural Gas Revenue and Cost of Gas Distributed. Natural gas
revenues increased to $686 million in 2001 from $487 million in 2000,
and the cost of natural gas distributed increased to $457 million in
2001 from $273 million in 2000. These increases were primarily due to2004. The higher average prices for natural gas in 2001. For the fourth quarter,
natural gas revenues decreased to $105 million in 2001 from $178
million in 2000, and the cost of natural gas distributed decreased to
$55 million in 2001 from $119 million in 2000. These decreases were
attributable to the lower natural gas costs in the fourth quarter of
2001.
Other Operating Expenses. Other operating expenses increased to
$491 million in 2001 from $412 million in 2000. For the fourth quarter,
other operating expenses increased to $147 million in 2001 from $135
million in 2000. These increases were primarily due to increased wages
and employee benefits costs, as well as increases in the operating
costs that are associated with balancing accounts and, therefore, do
not affect net income.

Other Income. Other income and deductions, which primarily
consists of interest income and/or expense from short-term investments
and regulatory balancing accounts, was $54 million and $34 million in
2001 and 2000, respectively. For the fourth quarter, other income

increased to $38 million in 2001 from $10 million in 2000. The increase
from 2000 to 2001 was primarily due to the $19 million gain on sale of
SDG&E's Blythe, California property (discussed below in "Cash Flows
From Investing Activities") in 2001, partially offset by lower interest
income from affiliates due to loan repayments by Sempra Energy in 2000.

Interest Expense. Interest expense was $92 million and $118
million in 2001 and 2000, respectively. The decrease in interest
expense in 2001 was primarily due to refunds made to customers in 2000
for the rate-reduction bond liability, and lower interest incurred as
the result of the remarketing of variable-rate debt during the first
quarter of 2001.

Income Taxes. Income tax expense was $141 million and $144 million
for the years ended December 31, 2001 and 2000, respectively. The effective income tax rates were 43.5 percent and 48.8 percent for the
same years. The decreases in the tax expense and effective rate in 2001
were2004 compared to 2003 was due primarily to higher state tax depreciationthe comparatively low rate in 2000 and2003 resulting from the 2001$57 million favorable resolution of income-tax issues. In addition, income before taxes in 2003 included $37 million in interest income arising from the income tax issues.

settlement, resulting in an offsetting $15 million income tax expense.
Net Income. NetIncome.SDG&E recorded net income increased to $183of $267 million, $213 million and $340 million in 2001 from $151
million in 2000.2005, 2004 and 2003, respectively. The increase in 2005 was due primarily due to the gain on sale of
SDG&E's Blythe property and lower interest expense, as well as the $30
million after-tax charge for regulatory issues in 2000. These increases
were partially offset by lower interest income from affiliates. Net
income increased to $46 million for the fourth quarter of 2001,
compared to $39 million for the corresponding period in 2000. This
increase was primarily due to the saleresolution of the Blythe property.

CAPITAL RESOURCES AND LIQUIDITY

The company's operations arerecovery of line losses and grid management charges arising from the major sourcefavorable after-tax settlement of liquidity. Beginning
in the third quarter of 2000 and continuing into the first quarter of
2001, SDG&E's liquidity and its ability to make funds available to
Sempra Energy were adversely affected by the electric cost
undercollections resulting from a temporary ceiling on electric rates
legislatively imposed in response to high electric commodity costs.
Growth in these undercollections ceased as a result of an agreement$23 million with the DWR, under which the DWR was obligated to purchase electricity
for SDG&E's customers to fill SDG&E's full net short position
consisting of the power and ancillary services required by SDG&E's
customers that were not provided by SDG&E's nuclear generating
facilities or its previously existing purchased-power contracts. The
agreement with the DWR extended through December 31, 2002. Starting on
January 1, 2003, SDG&E and other California IOUs resumed their electric
commodity procurement function based on a CPUC decision issuedISO (as discussed further in
October 2002. In addition, AB 57 and implementing decisions by the CPUC
provide for periodic adjustments to rates that would reflect the costs
of power and are intended to ensure the timely recovery of any
undercollections.

Another issue with potential implications to capital resources and
liquidity is the ownership of certain power sale contracts. The company
believes that all profits associated with the contracts properly are
for the benefit of SDG&E shareholders rather than customers, whereas
the CPUC asserted that all the profits should accrue to the benefit of
customers. On December 19, 2002, in a 3-to-2 decision, the CPUC

approved a proposed settlement that divides the profits from these
contracts, $199 million for SDG&E customers and $173 million for SDG&E
shareholders. Of the $199 million in profits allocated to customers,
$175 million had already been credited to ratepayers in 2001. The
remaining $24 million was applied as a balancing account transfer that
reduced the AB 265 balancing account in December 2002. The profits
allocated to customers reduce SDG&E's AB 265 undercollection, but do
not adversely affect SDG&E's financial position, liquidity or results
of operations. The term of a commissioner who voted to approve the
settlement has expired, and a new commissioner has been appointed. On
January 29, 2003, the CPUC's Office of Ratepayer Advocates, the City of
San Diego and the Utility Consumers' Action Network, a consumer-
advocacy group, filed requests for a CPUC rehearing of the decision. On
February 13, 2003, the company filed its opposition to rehearing of the
decision. Parties requesting a rehearing and parties to any rehearing
may also appeal the CPUC's final decision to the California appellate
courts.

For additional discussion, see "Factors Influencing Future Performance-
Electric Industry Restructuring and Electric Rates" herein and Note 10 of the notes to Consolidated Financial Statements.

Statements), the recognition of DSM awards of $22 million after-tax, favorable resolution of income tax issues of $60 million, and the $23 million recovery of costs associated with the 2005 IRS decision relating to the sale of the South Bay power plant, offset by a $17 million increase in after-tax California energy crisis litigation expenses, the favorable after-tax impact of $21 million from the resolution of the 2004 Cost of Service proceeding, and $19 million from lower after-tax electric transmission and distribution margin and higher operational costs in 2005. In addition to the 2004 matte rs noted above, the decrease in 2004 from 2003 was primarily due to the favorable resolution of income tax issues in 2003, which positively affected 2003 earnings by $79 million, income of $65 million after-tax in 2003 related to the approved settlement of intermediate-term power purchase contracts that SDG&E had entered into during the early stages of California's electric utility industry restructuring; the 2003 Incremental Cost Incentive Pricing income (as discussed further in Note 9 of the notes to Consolidated Financial Statements) for SONGS ($53 million after-tax) and higher performance awards in 2003, offset by higher electric transmission and distribution margin in 2004.
CAPITAL RESOURCES AND LIQUIDITY
The company's utility operations generally are the major source of liquidity. In addition, working capital requirements can be met through the issuance of short-term and long-term debt. Cash requirements primarily consist of capital expenditures for utility plant.
At December 31, 2005, there was $236 million in unrestricted cash and $500 million in available unused, committed lines of credit. Management believes thatthese amounts and cash flows from operationsandsecurity issuances will be adequate to finance capital expenditures and meet liquidity requirements and other commitments. Forecasted capital expenditures for the next five years are discussed in"Future Capital Expenditures for Utility Plant."Management continues to regularly monitor the company's ability to adequately meetfinance the needs of its operating, investing and financing and investing
activities.

activities in a manner consistent with its intention to maintain strong, investment-quality credit ratings.
CASH FLOWS FROM OPERATING ACTIVITIES
Net cash provided by operating activities totaled $757$338 million, $557$435 million and $174$567 million for 2002, 20012005, 2004 and 2000,2003, respectively.
The 2005 change in net cash provided by operating activities was primarily due to a $246 million change in income taxes mainly due to an increase in income tax payments in 2005, offset by a $66 million decrease in other assets, a $62 million increase in other liabilities, a $57 million reduction of interest receivable and a $54 million increase in net income in 2005.
The decrease in cash flows from operations in 20022004 compared to 20012003 was primarily attributable to SDG&E's collectiona lower net income in 2004.
The company made pension plan and other postretirement benefit plan contributions of a portion of prior purchased-
power costs (the remaining balance of which decreased to $392$21 million at December 31, 2001, $215and $7 million, at December 31, 2002respectively, during 2005, and $183$20 million on January 31, 2003, from a high in mid-2001 of $750 million),
the refunds to large customers in 2001 resulting from AB 43X and the
increase in accounts payable. The increase was partially offset by the
decrease in deferred income taxes and investment tax credits and the
decrease in regulatory balancing accounts. See further discussion on
the 2001 impact of regulatory balancing accounts activity below.

The increase in cash flows from operating activities in 2001 compared
to 2000 was primarily due to lower refunds paid to customers in 2001
and the increase in overcollected regulatory balancing accounts,
partially offset by a decrease in accounts payable. The decrease in
accounts payable was due to decreases in the average prices for natural
gas and the DWR's purchasing of SDG&E's net short position for
electricity.

$8 million, respectively, during 2004.
CASH FLOWS FROM INVESTING ACTIVITIES
Net cash provided by (used in)used in investing activities totaled $(611)$458 million, $(310)$289 million and $288$305 million for 2002, 20012005, 2004 and 2000,2003, respectively. The increase in cash used in investing activities in 20022005 was due to a $50 million increase in capital expenditures in 2005 and a $122 million decrease in loans to affiliate in 2004. The decrease in cash used in investing activities in 2004 compared to 20012003 was primarily due to increasedgreater than normal capital expenditures and advances to Sempra Energy, which are payable on demand.

For 2001, cash flows used in investing activities primarily consisted2003 as a result of capital expenditures of $307 million for the upgrade and expansion
of utility plant. The decrease in cash flows from investing activities
in 2001 was attributable to loan repayments from Sempra Energy in 2000.
2003 Southern California wildfires.
In addition,December 2005, the increase in proceeds from sale of assets was duecompany submitted its initial request to the saleCPUC for a proposed new transmission power line between the San Diego region and the Imperial Valley. The proposed line, called the Sunrise Powerlink, would be capable of propertyproviding electricity to 650,000 homes and is estimated to cost between $1 billion and $1.4 billion. The company expects to submit a proposed route and an alternative route to the CPUC in Blythe, California, for $42 million.2006.
Future Capital Expenditures for Utility Plant

Capital expenditures were $400 million in 2002, compared to $307
million and $324 million in 2001 and 2000, respectively. Capital
expenditures in 2002 were up from 2001 due to additions and
improvements to the company's natural gas and electric distribution
systems. Capital expenditures for 2001 were only slightly down from
2000.

Future Construction Expenditures

Significant capital expenditures in 20032006 are expected to include $400
million$1.2 billion for additions to the company's natural gas and electric distribution and generation systems. These expenditures are expected to be financed by cash flows from operations, and securityasset sales andsecurity issuances.
Over the next five years, the company expects to make capital expenditures of approximately $2 billion.

$4 billion at a rate ranging from $500 million to $1.2 billion per year.
Construction programs are periodically reviewed and revised by the company in response to changes in regulation, economic conditions, competition, customer growth, inflation, customer rates, the cost of capital and environmental and regulatory requirements.

The company's levelrequirements, as discussed in Note 11 of constructionthe notes to Consolidated Financial Statements.
'The company intends to finance its capital expenditures in the next few years
may vary substantially, anda manner that will depend on the availability of
financing and business opportunities providing desirable rates of
return. The company's intention is to finance any sizeable expenditures
so as to maintain the company'sits strong investment-grade ratings and capital structure. Smaller
The amounts and timing of capital expenditures will be madeare subject to approvals by the useCPUC, the FERC and other regulatory bodies.
The possible SDG&E' involvement with completion of existing liquidity.

the Otay Mesa power plant is discussed in Note 9 of the notes to Consolidated Financial Statements.
CASH FLOWS FROM FINANCING ACTIVITIES
Net cash used incashprovided by (used in) financing activities totaled $309$347 million, $181$(285) million and $543$(273) million for 2002, 20012005, 2004 and 2000,2003, respectively.

Net
The 2005 increase in cash used forprovided by financing activities increasedwas due to the $500 million issuances of first mortgage bonds in 2002 from 2001 due
primarily2005 and a $130 million decrease in common dividends paid in 2005. The company issued $251 million of first mortgage bonds in 2004 and applied the proceeds to higher dividendrefund an identical amount of first mortgage bonds and related tax-exempt industrial development bonds of a shorter maturity in the same year.
Long-Term and Short-Term Debt
In May 2005, the company publicly offered and sold $250 million of 5.35% first mortgage bonds, maturing in 2035. In November 2005, the company publicly offered and sold $250 million of 5.30% first mortgage bonds, maturing in 2015.
Payments on long-term debt in 2005 were $66 million related to its rate-reduction bonds.
In June 2004, the company issued $251 million of first mortgage bonds and applied the proceeds in July to refund an identical amount of first mortgage bonds and related tax-exempt industrial development bonds of a shorter maturity. The bonds secure the repayment of tax-exempt industrial development bonds of an identical amount, maturity and interest rate issued by the City of Chula Vista, the proceeds of which were loaned to the company and which are repaid with payments on the first mortgage bonds. The bonds were initially issued as auction-rate securities, but the company entered into floating-for-fixed interest-rate swap agreements that effectively changed the bonds' interest rates to fixed rates in September 2004. The swaps are set to expire in 2009.
Payments on long-term debt in 2004 included $251 million of SDG&E's first mortgage bonds and $66 million of rate-reduction bonds.
Payments on long-term debt in 2003 were for $66 million of rate-reduction bonds.
Note 2 of the absencenotes to Consolidated Financial Statements provide information concerning lines of credit and further discussion of debt issuances
in 2002.

Net cash used in financing activities decreased in 2001 primarily due
to higheractivity.
Dividends
Common dividends paid to Sempra Energy were $75 million in 20002005, compared to $205 million in 2004 and the increase in
long-term debt issuances in 2001.

Long-Term and Short-Term Debt

In May 2002, SDG&E and SoCalGas replaced their individual revolving
lines of credit with a combined revolving credit agreement under which

each utility may individually borrow up to $300 million, subject to a
combined borrowing limit for both utilities of $500 million. Each
utility's revolving credit line expires on May 16, 2003, at which time
it may convert its then outstanding borrowings to a one-year term loan
subject to having obtained any requisite regulatory approvals relating
to long-term debt. Borrowings under the agreement, which are available
for general corporate purposes including back-up support for commercial
paper and variable-rate long-term debt, would bear interest at rates
varying with market rates and the borrowing utility's credit rating.
The agreement requires each utility to maintain a debt-to-total
capitalization ratio (as defined in the agreement) of not to exceed 60
percent. The rights, obligations and covenants of each utility under
the agreement are individual rather than joint with those of the other
utility, and a default by one utility would not constitute a default by
the other.

In 2002, repayments on long-term debt included repayments of $66
million of rate-reduction bonds and $28 million of 7.625% first-
mortgage bonds. In addition, in July 2002, SDG&E called $10 million of
its 8.5% first-mortgage bonds.

In 2001, repayments on long-term debt included $66 million of rate-
reduction bonds and $25 million of unsecured variable-rate bonds.
During December 2000, $60 million of variable-rate industrial
development bonds were put back by the holders and remarketed in
February 2001 at a fixed interest rate of 7 percent.

In 2000, repayments on long-term debt included $66 million of rate-
reduction bonds. $10 million of first-mortgage bonds were also repaid
in 2000.

Dividends

Dividends paid to Sempra Energy amounted to $200 million in 2002,
compared to $150 million in 20012003.
The payment and $400 million in 2000.

The paymentamount of future dividends and the amount thereof are within the discretion of the company's board of directors. The CPUC's regulation of SDG&E's capital&E'scapital structure limits the amounts that are available for loans and dividends to Sempra Energy from SDG&E. At December 31, 2002,
the company could have provided a total of $250 million to Sempra
Energy. At December 31, 2002,2005, no amounts were available from SDG&E had loans to Sempra Energy of $250
million.

&E.
Capitalization
Total capitalization, including the current portion of long-term debt and excluding the rate-reduction bonds (which are non-recourse to the company),at December 31, 20022005 was $2.1 billion. The debt-to-
capitalization$3 billion.The debt-to-capitalization ratio was 4247 percent at December 31, 2002. Significant
changes in capitalization during 2002 included long-term borrowings and
dividends.

Cash and Cash Equivalents

At December 31, 2002, the company had $159 million of cash and $300
million of revolving lines of credit. Management believes these amounts

and cash flows from operations and new debt issuances will be adequate
to finance capital expenditures and other commitments.

2005.
Commitments
The following is a summary of the company's principal contractual commitments at December 31, 2002 (dollars in millions). Liabilities
reflecting fixed price contracts and other derivatives are excluded as
they are primarily offset against regulatory assets and would be
recovered from customers through the ratemaking process.2005. Additional information concerning commitments is provided above and in Notes 4, 92, 5, 8 and 1211 of the notes to Consolidated Financial Statements.
By Period
----------------------------------------------------
2004 2006
and and
Description 2003 2005 2007 Thereafter Total
- --------------------------------------------------------------------------------

Long-term debt $ 66 $ 132 $ 132 $ 889 $1,219
Operating leases 16 26 16 17 75
Purchased-power contracts 257 455 437 2,285 3,434
Natural gas contracts 31 27 23 153 234
Preferred stock subject to
mandatory redemption -- 3 3 19 25
Construction commitments 3 -- -- 95 98
SONGS decommissioning 20 22 9 258 309
Environmental commitments 5 10 -- -- 15
---------------------------------------------------
Totals $ 398 $ 675 $ 620 $3,716 $5,409
===================================================

Credit Ratings

As of January 31, 2003, credit ratings for SDG&E were as follows:

S&P Moody's Fitch
- -----------------------------------------------------------
Secured Debt A+ A1 AA
Unsecured Debt A A2 AA-
Preferred Stock A- Baa1 A+
Commercial Paper A-1 P-1 F1+
-------------------------------
(Dollars in millions) 2006 2007 and 2008 2009 and 2010 Thereafter Total
Long-term debt $ 66 $ 66 $ -- $ 1,389 $ 1,521
Interest on debt (1) 78 145 152 1,687 2,062
Operating leases 19 29 17 19 84
Litigation reserve 25 50 -- -- 75
Purchased-power contracts 247 536 565 2,627 3,975
Natural gas contracts 22 28 20 112 182
Preferred stock subject to mandatory redemption 3 16 -- -- 19
Construction commitments 16 24 7 20 67
SONGS decommissioning 14 11 -- 314 339
Other asset retirement obligations 4 9 5 105 123
Pension and postretirement benefit obligations (2) 41 106 89 257 493
Environmental commitments 9 9 -- -- 18
Totals $ 544 $ 1,029 $ 855 $ 6,530 $ 8,958
(1) Based on forward rates in effect at December 31, 2005.
(2) Amounts are after reduction for the Medicare Part D subsidy and only include expected payments to the plans for the next 10 years.
The table excludes contracts between affiliates, intercompany debt, individual contracts that have annual cash requirements less than $1 million and employment contracts.
Credit Ratings
Credit ratings of the company remained at investment grade levels in 2005. As of January 31, 2003,2006, company credit ratings were still as follows:
Standard
& Poor's Moody's Investor
Services, Inc. Fitch
Secured debt A+ A1 AA
Unsecured debt A- A2 AA-
Preferred stock BBB+ Baa1 A+
Commercial paper A-1 P-1 F1+
As of January 31, 2006, the company has a stable outlook rating from all three credit rating agencies.

31
FACTORS INFLUENCING FUTURE PERFORMANCE

The factors influencing future performance are summarized below.

Electric Industry Restructuring and Electric Rates

Supply/demand imbalances and a number
Performance of other factors resulted in
abnormally high electric-commodity costs beginning in mid-2000 and
continuing into 2001. This caused SDG&E's customer bills to be
substantially higher than normal. In response, legislation enacted in
September 2000 imposed a ceiling of 6.5 cents/kilowatt hour (kWh)the company will depend primarily on the cost of electricity that SDG&E could pass on to its small-usage
customers on a current basis. SDG&E accumulated the amount that it paid
for electricity in excess of the ceiling rate in an interest-bearing
balancing account. This undercollection amounted to $447 million, $392
millionratemaking and $215 million at December 31, 2000, 2001regulatory process, electric and 2002,
respectively.

In February 2001, the DWR began to purchase power from generators and
marketers to supply a portion of the state's power requirements that is
served by IOUs. From early 2001 to December 31, 2002, the DWR purchased
SDG&E's full net short position (the power needed by SDG&E's customers,
other than that provided by SDG&E's nuclear generating facilities or
its previously existing purchase power contracts). In October 2002, the
CPUC issued a decision directing the resumption of the electric
commodity procurement function by IOUs by January 1, 2003.

An unresolved issue is the ownership of certain power sale profits
stemming from intermediate term purchase power contracts entered into
by SDG&E during the early stages of California's electric utilitynatural gas industry restructuring. On December 19, 2002, the CPUC rendered a 3-to-
2 decision approving the June 2002 proposed settlement previously
described in the company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 2002, that divides the profits from these
contracts, $199 million for SDG&E customers and $173 million for SDG&E
shareholders. Of the $199 million in profits allocated to customers,
$175 million had already been credited to ratepayers in 2001. The
remaining $24 million was applied as a balancing account transfer that
reduced the AB 265 balancing account in December 2002. The profits
allocated to customers reduce SDG&E's AB 265 undercollection, but do
not adversely affect SDG&E's financial position, liquidity or results
of operations. The term of a commissioner who voted to approve the
settlement has expired, and a new commissioner has been appointed. On
January 29, 2003, the CPUC's Office of Ratepayer Advocates, the City of
San Diegorestructuring, and the Utility Consumers' Action Network, a consumer-
advocacy group, filed requests for a CPUC rehearingchanging energy marketplace. Performance will also depend on the successful completion of the decision. On
February 13, 2003, the company filed its opposition to rehearing of the
decision. Parties requesting a rehearingconstruction programs, which are discussed in various places in this report. These factors are discussed in Notes 9 and parties to any rehearing
may also appeal the CPUC's final decision to the California appellate
courts.

Operating costs of SONGS Units 2 and 3 (including nuclear fuel and
related financing costs) and incremental capital expenditures are
recovered through the ICIP mechanism which allows SDG&E to receive
approximately 4.4 cents per kilowatt-hour for SONGS generation. Any
differences between the actual amounts of these costs and the incentive
price affect net income. For the year ended December 31, 2002, ICIP

contributed $50 million to SDG&E's net income. The CPUC has rejected an
administrative law judge's proposed decision to end ICIP prior to its
December 31, 2003 scheduled expiration date. However, the CPUC has also
denied the previously approved market-based pricing for SONGS beginning
in 2004 and instead provided for traditional rate-making treatment
under which the SONGS ratebase would begin at zero, essentially
eliminating earnings from SONGS until ratebase grows. The company has
applied for rehearing of this decision.

See additional discussion of this and related topics in Note 10 of the notes to Consolidated Financial Statements. Natural Gas Restructuring and Gas Rates

On December'
Litigation
Note 11 2001, the CPUC issued a decision adopting the following
provisions affecting the structure of the natural gas industry innotes to Consolidated Financial Statements describes litigation (primarily cases arising from the California someenergy crisis), the ultimate resolution of which could introduce additional volatility into
the earningshave a material adverse effect on future performance.
IndustryDevelopments
Notes 9 and 10 of the company and other market participants: a system for
shippersnotes to hold firm, tradable rights to capacity on SoCalGas' major
gas transmission lines; new balancing services, including separate core
and noncore balancing provisions; a reallocation among customer classes
of the cost of interstate pipeline capacity held by SoCalGas and an
unbundling of interstate capacity for natural gas marketers serving
core customers; and the elimination of noncore customers' option to
obtain natural gas procurement service from SDG&E and SoCalGas. During
2002 the California Utilities filed a proposed implementation schedule
and revised tariffs and rules required for implementation. However,
protests of these compliance filings were filed and the CPUC has not
yet authorized implementation of most of the provisions of its
decision. On December 30, 2002, the CPUC deferred acting on a plan to
implement its decision.

Allowed Rate of Return

Effective January 1, 2003, SDG&E's authorized rate of return on equity
is 10.9 percent (increased from 10.6 percent) for SDG&E's electric
distribution and natural gas businesses. This change results in a
revenue requirement increase of $2.4 million ($1.9 million electric and
$0.5 million natural gas) and increases SDG&E's overall rate of return
from 8.75 percent to 8.77 percent. These rates remain in effect through
2003. The company can earn more than the authorized rate by controlling
costs below approved levels or by achieving favorable results in
certain areas such as various incentive mechanisms. In addition,
earnings are affected by customer growth.

Cost of Service (COS) and Performance-Based Regulation

The COS and PBR cases for SDG&E were filed on December 20, 2002. The
filings outline projected expenses (excluding the commodity cost of
electricity or natural gas consumed by customers or expenses for
programs such as low-income assistance) and revenue requirements for
2004 and a formula for 2005 through 2008. SDG&E's cost of service study
proposes increases inConsolidated Financial Statements describe electric and natural gas base rate revenues of
$58.9 millionrestructuring and $21.6 million, respectively. The filings also
requested a continuancerates, and expansion of PBR in terms of earnings
sharingother pending proceedings and performance service standards that include both reward and
penalty provisions related to customer satisfaction, employee safety

and system reliability. The resulting new base rates are expected to be
effective on January 1, 2004. A CPUC decision is expected in late 2003.
SDG&E's profitability is dependent upon its ability to control costs
within base rates. SDG&E's PBR mechanism is in effect through December
31, 2003, at which time the mechanism will be updated. That update will
include, among other things, a reexamination of the company's
reasonable costs of operation to be allowed in rates. The October 10,
2001 decision also denied the company's request to continue equal
sharing between ratepayers and shareholders of the estimated savings
for the merger discussed in Note 1 and, instead, ordered that all of
the estimated 2003 merger savings go to ratepayers. This decision will
adversely affect the company's 2003 net income by $11 million.

Utility Integration

On September 20, 2001, the CPUC approved Sempra Energy's request to
integrate the management teams of SDG&E and SoCalGas. The decision
retains the separate identities of each utility and is not a merger.
Instead, utility integration is a reorganization that consolidates
senior management functions of the two utilities and returns to the
utilities the majority of shared support services previously provided
by Sempra Energy's centralized corporate center. Once implementation is
completed, the integration is expected to result in more efficient and
effective operations.

In a related development, an August 2002 CPUC interim decision denied a
request by SDG&E and SoCalGas to combine their natural gas procurement
activities at this time, pending completion of the CPUC's ongoing
investigation of market power issues.

MARKET RISK

investigations.
Market Risk
Market risk is the risk of erosion of the company's cash flows, net income, asset values and equity due to adverse changes in prices for various commodities, and in interest rates.

The company's policy is to use derivative physical and financial
instruments to reduce its exposure to fluctuations in interest rates,
and commodity prices. Transactions involving these financial
instruments are with major exchanges and other firms believed to be
credit worthy. The use of these instruments exposes the company to
market and credit risks which, at times, may be concentrated with
certain counterparties. There were no unusual concentrations at
December 31, 2002, that would indicate an unacceptable level of risk.
Credit risks associated with concentration are discussed below under
"Credit Risk."

The company has adopted corporate-wide policies governing its market-market risk management and trading activities.activities of all affiliates. Assisted by the company's Energy Risk Management Group (ERMG)Department (RMD), the company's Energy Risk Management Oversight Committee (RMC) consisting of senior officers, establishes policy for and oversees company-wide energy risk management activities and monitors the results of trading and other activities to ensure compliance with the company's stated energy-riskenergy risk management policies and trading policies. Utility managementapplicable regulatory requirements. The RMD receives daily information on positions and the ERMG receives
information on a delayed basis detailing positions creatingregarding market positions that create credit, liquidity and 34

creditmarket risk for the company, consistent with affiliate rules. The ERMG
independentlyand monitors energy price risk management and measures and reports the market and credit risk associated with these positions. In addition,positions to the company's risk-
management committee monitors energy-price risk management and trading
activities independently from the groups responsible for creating or
actively managing these risks.

RMC.
Along with other tools, the company uses Value at Risk (VaR) to measure its exposure to market risk. VaR is an estimate of the potential loss on a position or portfolio of positions over a specified holding period, based on normal market conditions and within a given statistical confidence interval. The company has adopted the variance/covariance methodology in its calculation of VaR, and uses both the 95-percent and 99-percent confidence intervals. VaR is calculated independently by the ERMGRMD for the company. Historical and implied volatilities and correlations between instruments and positions are used in the calculation. As of December 31, 2002, the total VaR of the
company's natural gas positions was not material.
The company uses energy and natural gas derivatives to manage natural gas and energy price risk associated with servicing their load requirements. In addition, the
company makes limitedThe use of energy and natural gas derivatives for trading
purposes. These instruments can include forward contracts, futures,
swaps, options and other contracts. In the case of both price-riskis in compliance with risk management and trading activities,activity plans that have been filed and approved by the CPUC. Any costs or gains/losses associated with the use of energy and natural gas derivatives, which use is in compliance with CPUC approved plans, are considered to be commodity costs that are passed on to customers in a substantially concurrent basis.
Revenue recognition is discussed in Note 1 and the additional market risk information regarding derivative financial instruments is subject to certain limitations imposed by company policy
and regulatory requirements. See the continuing discussion below anddiscussed in Note 87 of the notes to Consolidated Financial Statements for further
information regarding the use of energy derivatives by the company.
Additional information is provided in Note 8 of the notes to
Consolidated Financial Statements.
The following discussion of the company's primary market-riskmarket risk exposures as of December 31, 20022005 includes a discussion of how these exposures are managed.

Commodity-Price
Commodity Price Risk
Market risk related to physical commodities is created by volatility in the prices and basis of natural gas and electricity. The company's market risk is impacted by changes in volatility and liquidity in the markets in which these commodities or related financial instruments are traded. The company is exposed, in varying degrees, to price risk, primarily in the natural gas and electricity markets. The company's policy is to manage this risk within a framework that considers the unique markets, and operating and regulatory environments

environments.
The company's market risk exposure is limited due to CPUC authorizedCPUC-authorized rate recovery of the costs of electric procurement and natural gas purchase, salepurchases and storage activity.sales. However, the company may, at times, be exposed to market risk as a result of activities under SDG&E's natural gas PBR and electric procurement activities,which is discussed in NotesinNote 10 and 11 of the notes to Consolidated Financial Statements. If commodity prices were to rise too rapidly, it is likely that volumes would decline. This would increase the per-unit fixed costs, which could lead to further volume declines. The company manages its risk within the parameters of the company's market-riskits market risk management and
trading framework. As of December 31, 2002,2005, the company's exposure to
market riskVaR was not material.

Interest-Ratematerial and the procurement activities are in compliance with the procurement plans filed with and approved by the CPUC.
Interest Rate Risk
The company is exposed to fluctuations in interest rates primarily as a result of its short-term and long-term debt. The company historically has funded operations through long-term debt issues withat fixed interest rates and
theseof interest rates are recovered in utility rates. With the
restructuring of the regulatory process, the CPUC has permitted greater
flexibility in the use of debt. As a result, some recentSome more-recent debt offerings have been selectedissued with short-term maturities to take advantage of
yield curves, or have used a combination of fixed-rate and floating-
rate debt.floating rates. Subject to regulatory constraints, interest-rate swaps may be used to adjust interest-rate exposures when appropriate, based upon
market conditions.

exposures.
At December 31, 2002,2005, the company had $1,062 million$1.5 billion of fixed-rate debt and $157 million ofno variable-rate debt. Interest on fixed-rate utility debt is fully recovered in rates on a historical cost basis and interest on variable-rate debt is provided for in rates on a forecasted basis. At December 31, 2002, SDG&E's2005, the company's fixed-rate debt had a one-year VaR of $200 million and SDG&E's variable-rate debt had a one-year VaR of
$0.1$171 million.
At December 31, 2002,2005, the company did not have any outstandingnotional amount of interest-rate swap transactions. See Notes 3 and 8 oftransactions totaled $251 million. Note 2of the notes to Consolidated Financial Statements forprovides further information regarding theseinterest-rate swap transactions.
In addition, the company is ultimately subject to the effect of interest
rate fluctuationinterest-rate fluctuations on the assets of its pension plan.

plans, other postretirement plans and the nuclear decommissioning trust. However the effects of these fluctuations are expected to be passed on to customers.
Credit Risk
Credit risk is the risk of loss that would be incurred as a result of nonperformance by counterparties of their contractual obligations. As with market risk, the company has adopted corporate-wide policies governing the management of credit risk. Credit risk management is under the oversight of the Energy Risk Management Oversight Committee,
assistedperformed by the ERMG and the company's credit department.department and overseen by the company's RMC. Using rigorous models, the company's credit department continuously
calculatesRMD and the company calculate current and potential credit risk to counterparties on a daily basis and monitor actual balances in comparison to ensure the risk stays within approved limits and reports this
information to the ERMG.limits. The company avoids concentration of counterparties whenever possible, and management believes its credit policies associated with regard
to counterparties significantly reduce overall credit risk. These policies include an evaluation of prospective counterparties' financial condition (including credit ratings), collateral requirements under certain circumstances, and the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.

counterparty, and other security such as lock-box liens and downgrade triggers. The company believes that adequate reserves have been provided for counterparty nonperformance.
The company monitors credit risk through a credit-approvalcredit approval process and the assignment and monitoring of credit limits. These credit limits are established based on risk and return considerations under terms customarily available in the industry.

The
As noted above under "Interest Rate Risk," the company periodically enters into interest-rate swap agreements to moderate exposure to interest-rate changes and to lower the overall cost of borrowing. The company would be exposed to interest-rate fluctuations on the underlying debt should other partiescounterparties to the agreement not perform. See the "Interest-Rate Risk" section above for
additional information regarding the company's use of interest-rate
swap agreements.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND KEY NON-CASH PERFORMANCE INDICATORS
Certain accounting policies are viewed by management as critical because their application is the most relevant, judgmental and/or material to the company's financial position and results of operations, and/or because they require the use of material judgments and estimates.
The company's most significant accounting policies are described in Note 1 of the notes to Consolidated Financial Statements. The most critical policies, all of which are mandatory under generally accepted accounting principles and the regulations of the Securities and Exchange Commission, are the following:
Statement of Financial Accounting Standards (SFAS) 5, "Accounting for Contingencies," establishes the amounts and timing of when the company provides for contingent losses. Details of the company's issues in this area are discussed in Note 11 of the notes to Consolidated Financial Statements.
SFAS 71, "Accounting for the Effects of Certain Types of Regulation," has a significant effect on the way the California Utilities record assets and liabilities, and the related revenues and expenses that would not otherwise be recorded absent the principles contained in SFAS 71.
SFAS 109, "Accounting for Income Taxes," governs the way the company provides for income taxes. Details of the company's issues in this area are discussed in Note 4 of the notes to Consolidated Financial Statements.
SFAS 133, "Accounting for Derivative Instruments and Hedging Activities" andActivities," SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities," SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," andEmerging Issues Task Force (EITF) Issue 02-3,"Issues Involved in Accounting for Derivative Contracts held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,"have a significant effect on the balance sheets of the California Utilitiescompany but have no significant effect on theirits income statements because of the principles contained in SFAS 71.In connection with the application of these and other accounting policies, the company makes estimates and judgments about various matters. The most significant of these involve:
The calculation of fair or realizable values.
The probable costs to be incurred in the resolution of litigation.
The collectibility of receivables, regulatory assets, deferred tax assets and other assets.
The likelihood of recoveryresolution of various deferredincome tax assets.

issues between the company and the various taxing authorities.Differences between estimates and actual amounts have had significant impacts in the past and are likely to do sohave significant impacts in the future.
As discussed elsewhere herein, the company uses exchange quotations or other third-party pricing to estimate fair values whenever possible. When no such data is available, it uses internally developed models and other techniques. The assumed collectibility of receivables considers the aging of the receivables, the credit-worthiness of customers and the enforceability of contracts, where applicable. The assumed collectibility of regulatory assets considers legal and regulatory decisions involving the specific items or similar items. The assumed collectibility of other assets considers the nature of the item, the enforceability of contracts where applicable, the creditworthinesscredit-worthiness of the other parties and other factors. Costs to fulfill marked-to-market contractsThe anticipated resolution of income tax issues considers past resolutions of the same or similar issue, the status of any income tax examination in progress and positions taken by taxing authorities with other taxpayers with similar issues. Actuarial assumptions are based on prior

experience.the advice of th e company's independent actuaries. The likelihood of deferred tax recovery is based on analyses of the deferred tax assets and the company's expectation of future financial and/or taxable income, based on its strategic planning.
Choices among alternative accounting policies that are material to the company's financial statements and information concerning significant estimates have been discussed with the audit committee of the board of directors.
Key non-cash performance indicators for the company include numbers of customers and quantities of natural gas and electricity sold. The information is provided in "Overview" and "Results of Operations."
NEW ACCOUNTING STANDARDS

New
Relevant pronouncements bythat have recently become effective and have had a significant effect on the company's financial statements are SFAS 143 and Financial Accounting Standards Board (FASB) that have recently become effective or are yet to be effective are SFAS
142 through SFAS 149 and Interpretations 45 and 46.Interpretation No. (FIN) 47. They are described in Note 1below.
SFAS 143,"Accounting for Asset Retirement Obligations" and FIN 47, "Accounting for Conditional Asset Retirement Obligations, an interpretation of the notes to Consolidated Financial Statements. SFAS 142
affects net income by replacing the amortization of goodwill with
periodic reviews thereof for impairment with charges against income
when impairment is found.FASB Statement No. 143": SFAS 143 requires accounting and disclosure
changes concerningentities to record the fair value of liabilities for legal obligations related to asset retirements in the period in which they are incurred. It also requires the company to reclassify amounts recovered in rates for future asset
retirements.removal costs not covered by a legal obligation from accumulated depreciation to a regulatory liability. Issued in March 2005, FIN 47 clarifies that the term conditional asset-retirement obligation as used in SFAS 144 supercedes SFAS 121143 refers to a legal obligation to perform an asset-retirement activity in dealing with other asset
impairment issues. SFAS 145 makes technical corrections to previous
statements. SFAS 146 deals with exit and disposal activities, replacing
EITF Issue 94-3. SFAS 147 deals with acquisitions of financial
institutions. SFAS 148 amends SFAS 123 and adds two additional
transition methods towhich the fair valuetiming and/or method of accounting for stock-
based compensation. SFAS 149 establishes standards for accounting for
financial instruments with characteristicssettlement are conditional on a future event that may or may not be within the control of liabilities and equity.
Interpretation 45 clarifies that a guarantor is requiredthe entity. FIN 47 requires companies to recognize a liability for the fair value of thea conditional asset-retirement obligation undertaken in issuing a
guarantee. Interpretation 46 addresses consolidation by business
enterprises of variable-interest entities (previously referred to as
"special-purpose entities" in most cases). Pronouncements that have or
potentially could have a material effect on future earnings are
described below.

SFAS 143, "Accounting for Asset Retirement Obligations": SFAS 143,
issued in July 2001, addresses financial accounting and reporting for
legal obligations associated with the retirement of tangible long-lived
assets. It requires entities to recordif the fair value of a liability
for an asset retirementthe obligation in the period in which it is
incurred. SFAS 143can be rea sonably estimated. FIN 47 is effective for the company beginning in 2003. See
further discussion in Note 1 of the notes to Consolidated Financial
Statements.

SFAS 149, "Accounting for Certain Financial Instruments with
Characteristics of Liabilities and Equity": On January 22, 2003, the
FASB directed its staff to prepare a draft of SFAS 149. The final draft
is expected to be issued in March 2003. The statement will establish
standards for accounting for financial instruments with characteristics
of liabilities, equity, or both. The FASB decided that SFAS 149 will
prohibit the presentation of certain items in the mezzanine section
(the portion of the balance sheet between liabilities and equity) of
the statement of financial position. As such, certain mandatorily
redeemable preferred stock, which is currently included in the
mezzanine section, may be classified as a liability once SFAS 149 goes

into effect. The proposed effective date of SFAS 149 is July 1, 2003
for the company.

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report contains statements that are not historical fact and
constitute forward-looking statements within the meaning of the Private
Securities Litigation Reform Act of 1995. The words "estimates,"
"believes," "expects," "anticipates," "plans," "intends," "may,"
"would" and "should" or similar expressions, or discussions of strategy
or of plans are intended to identify forward-looking statements.
Forward-looking statements are not guarantees of performance. They
involve risks, uncertainties and assumptions. Future results may differ
materially from those expressed in these forward-looking statements.

Forward-looking statements are necessarily based upon various
assumptions involving judgments with respect to the future and other
risks, including, among others, local, regional, national and
international economic, competitive, political, legislative and
regulatory conditions and developments; actions by the CPUC, the
California Legislature, the DWR and the FERC; capital market
conditions, inflation rates, interest rates and exchange rates; energy
and trading markets, including the timing and extent of changes in
commodity prices; weather conditions and conservation efforts; war and
terrorist attacks; business, regulatory and legal decisions; the pace
of deregulation of retail natural gas and electricity delivery; the
timing and success of business development efforts; and other
uncertainties, all of which are difficult to predict and many of which
are beyond the control of the company. Readers are cautioned not to
rely unduly on any forward-looking statements and are urged to review
and consider carefully the risks, uncertainties and other factors which
affect the company's business described in this report and other
reports filed by the company from time to time with the Securities and
Exchange Commission.

2005 annual report.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by Item 7A is set forth under "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations --- Market Risk."

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Company management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of company management, including the principal executive officer and principal financial officer, the company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework inInternal Control -- Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the company's evaluation under the framework inInternal Control -- Integrated Framework, management concluded that the company's internal control over financial reporting was effective as of December 31, 2005. Management's assessment of the effectiveness of internal control over financial reporting as of December 31, 2005 has been audited by Deloitte & Touche LLP, as stated in its report, which is included herein.

REPORT OF INDEPENDENT AUDITORS' REPORT

REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of San Diego Gas & Electric Company:
We have audited the accompanying consolidated balance sheets of San Diego Gas & Electric Company and subsidiary (the "Company") as of December 31, 20022005 and 2001,2004, and the related consolidated statements of consolidated
income, shareholders' equity and cash flows and changes in shareholders' equity for each of the three years in the period ended December 31, 2002.2005. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditingthe standards generally accepted inof the United States of America.Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of San Diego
Gas & Electricthe Company and subsidiary as of December 31, 20022005 and 2001,2004, and the results of theirits operations and theirits cash flows for each of the three years in the period ended December 31, 2002,2005, in conformity with accounting principles generally accepted in the United States of America.

/s/
As described in Note 1 to the financial statements, the Company adopted Financial Accounting Standards Board Interpretation No. 47,Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143,effective December 31, 2005.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2005, based on the criteria established inInternal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 21, 2006 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP

San Diego, California
February 14, 2003

SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED INCOME
Dollars in millions

Years ended December 31,
2002 2001 2000
------ ------ ------

OPERATING REVENUES
Electric $1,274 $1,676 $2,184
Natural gas 422 686 487
------ ------ ------
Total operating revenues 1,696 2,362 2,671
------ ------ ------
OPERATING EXPENSES
Electric fuel and net purchased power 297 782 1,326
Cost of natural gas distributed 205 457 273
Other operating expenses 531 491 412
Depreciation and decommissioning 230 207 210
Income taxes 93 122 134
Franchise fees and other taxes 78 82 81
------ ------ ------
Total operating expenses 1,434 2,141 2,436
------ ------ ------
Operating Income 262 221 235
------ ------ ------
Other Income and (Deductions)
Interest income 10 21 51
Regulatory interest (7) 5 (8)
Allowance for equity funds used
during construction 15 5 6
Taxes on non-operating income 2 (19) (10)
Other - net 4 42 (5)
------ ------ ------
Total 24 54 34
------ ------ ------
Interest Charges
Long-term debt 75 84 81
Other 8 12 39
Allowance for borrowed funds
used during construction (6) (4) (2)
------ ------ ------
Total 77 92 118
------ ------ ------
Net Income 209 183 151
Preferred Dividend Requirements 6 6 6
------ ------ ------
Earnings Applicable to Common Shares $ 203 $ 177 $ 145
====== ====== ======

See notes to Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
Dollars in millions

December 31,
--------------------
2002 2001
------ ------

ASSETS
Utility plant - at original cost $5,408 $5,009
Accumulated depreciation and decommissioning (2,775) (2,642)
------ ------
Utility plant - net 2,633 2,367
------ ------
Nuclear decommissioning trusts 494 526
------ ------
Current assets:
Cash and cash equivalents 159 322
Accounts receivable - trade 163 160
Accounts receivable - other 18 27
Due from unconsolidated affiliates 292 28
Income taxes receivable -- 73
Regulatory assets arising from fixed-price contracts
and other derivatives 59 83
Other regulatory assets 75 75
Inventories 46 70
Other 11 4
------ ------
Total current assets 823 842
------ ------
Other assets:
Deferred taxes recoverable in rates 190 162
Regulatory assets arising from fixed-price contracts
and other derivatives 579 634
Other regulatory assets 342 842
Sundry 62 26
------ ------
Total other assets 1,173 1,664
------ ------
Total assets $5,123 $5,399
====== ======

See notes to Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
Dollars in millions

December 31,
-------------------
2002 2001
------ ------

CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock (255,000,000 shares authorized;
116,583,358 shares outstanding) $ 943 $ 857
Retained earnings 235 232
Accumulated other comprehensive income (loss) (34) (3)
------ ------
Total common equity 1,144 1,086
Preferred stock not subject to mandatory redemption 79 79
------ ------
Total shareholders' equity 1,223 1,165
Preferred stock subject to mandatory redemption 25 25
Long-term debt 1,153 1,229
------ ------
Total capitalization 2,401 2,419
------- ------
Current liabilities:
Accounts payable 159 139
Interest payable 12 12
Due to unconsolidated affiliates 3 --
Income taxes payable 41 --
Deferred income taxes 53 128
Regulatory balancing accounts - net 394 575
Fixed-price contracts and other derivatives 59 84
Current portion of long-term debt 66 93
Other 170 174
------ ------
Total current liabilities 957 1,205
------ ------
Deferred credits and other liabilities:
Customer advances for construction 54 42
Deferred income taxes 602 639
Deferred investment tax credits 42 45
Fixed-price contracts and other derivatives 579 634
Due to unconsolidated affiliates 16 5
Deferred credits and other liabilities 472 410
------ ------
Total deferred credits and other liabilities 1,765 1,775
------ ------
Contingencies and commitments (Note 12)

Total liabilities and shareholders' equity $5,123 $5,399
====== ======
See notes to Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED CASH FLOWS
Dollars in millions

Years Ended December 31,
2002 2001 2000
------- ------- -------

CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 209 $ 183 $ 151
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation and amortization 230 207 210
Customer refunds paid -- (127) (628)
Deferred income taxes and investment tax credits (114) (9) 300
Non-cash rate reduction bond expense 82 66 32
Gain on disposition of assets -- (22) --
Changes in other assets 123 (142) (152)
Changes in other liabilities 46 5 (18)
Changes in working capital components:
Accounts receivable 6 66 (55)
Due to/from affiliates - net (61) (3) (6)
Inventories 23 (20) --
Income taxes 114 163 (149)
Other current assets (6) 7 (3)
Accounts payable 21 (268) 252
Regulatory balancing accounts 89 426 213
Other current liabilities (5) 25 27
------- ------- -------
Net cash provided by operating activities 757 557 174
------- ------- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (400) (307) (324)
Loan to/from affiliate - net (199) (33) 593
Net proceeds from sale of assets -- 42 24
Contributions to decommissioning funds (5) (5) (5)
Other - net (7) (7) --
------- ------- -------
Net cash provided by (used in) investing
activities (611) (310) 288
------- ------- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends paid (206) (156) (406)
Payments on long-term debt (103) (118) (149)
Issuances of long-term debt -- 93 12
------- ------- -------
Net cash used in financing activities (309) (181) (543)
------- ------- -------
Increase (decrease) in cash and cash equivalents (163) 66 (81)
Cash and cash equivalents, January 1 322 256 337
------- ------- -------
Cash and cash equivalents, December 31 $ 159 $ 322 $ 256
======= ======= =======

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized $ 71 $ 83 $ 113
======= ======= =======
Income tax payments (refunds) - net $ 92 $ (11) $ (8)
======= ======= =======
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING
AND FINANCING ACTIVITIES
Property, plant and equipment contribution
from Sempra Energy $ 86 $ -- $ --
======= ======= =======
See notes to Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
For the years ended December 31, 2002, 2001 and 2000
(Dollars in millions)

Preferred Stock Accumulated
Not Subject Other Total
Comprehensive to Mandatory Common Retained Comprehensive Shareholders'
Income Redemption Stock Earnings Income(Loss) Equity
- ---------------------------------------------------------------------------------------------------------------

Balance at December 31, 1999 $ 79 $ 857 $ 460 $ (3) $1,393
Net income/comprehensive income $ 151 151 151
Common stock dividends declared ===== (400) (400)
Preferred dividends declared (6) (6)
- ---------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000 79 857 205 (3) 1,138
Net income/comprehensive income $ 183 183 183
Common stock dividends declared ===== (150) (150)
Preferred dividends declared (6) (6)
- ---------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001 79 857 232 (3) 1,165
Net income $ 209 209 209
Other comprehensive income
adjustment-pension (31) (31) (31)
-----
Comprehensive income $ 178
Preferred dividends declared ===== (6) (6)
Common stock dividends declared (200) (200)
Capital contribution 86 86
- ---------------------------------------------------------------------------------------------------------------
Balance at December 31, 2002 $ 79 $ 943 $ 235 $ (34) $1,223
===============================================================================================================

See notes to Consolidated Financial Statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SIGNIFICANT21, 2006

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING POLICIES

Business Combination

Sempra Energy was formed as a holding company for Enova Corporation
(Enova),FIRM
To the parent corporationBoard of Directors and Shareholders of San Diego Gas & Electric (SDG&E),Company:
We have audited management's assessment, included in the accompanying Management's Report on Internal Control over Financial Reporting, that San Diego Gas & Electric and Pacific Enterprises (PE),subsidiaries (the "Company") maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established inInternal Control--Integrated Frameworkissued by the parent corporationCommittee of SouthernSponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established inInternal Control--Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established inInternal Control--Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),the consolidated financial statements as of and for the year ended December 31, 2005 of the Company and our report dated February 21, 2006 expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding the Company's adoption of a new accounting standard.
/s/ DELOITTE & TOUCHE LLP

San Diego, California Gas Company (SoCalGas),
February 21, 2006

SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED INCOME
(Dollars in connection with a business
combination of Enovamillions)
Years ended December 31,
2005 2004 2003
Operating revenues
Electric $ 1,803 $ 1,678 $ 1,801
Natural gas 709 596 507
Total operating revenues 2,512 2,274 2,308
Operating expenses
Cost of electric fuel and purchased power 624 576 541
Cost of natural gas 456 347 274
Other operating expenses 603 574 611
Depreciation and amortization 264 259 242
Income taxes 110 137 127
Franchise fees and other taxes 119 113 114
Litigation expense 52 19 17
Gain on sale of assets (1 ) (1 ) (9 )
Impairment losses (adjustments) 2 (6 ) 3
Total operating expenses 2,229 2,018 1,920
Operating income 283 256 388
Other income, net (Note 1) 58 25 25
Interest charges
Long-term debt 65 61 67
Other 12 10 11
Allowance for borrowed funds used during construction (3 ) (3 ) (5 )
Total 74 68 73
Net income 267 213 340
Preferred dividend requirements 5 5 6
Earnings applicable to common shares $ 262 $ 208 $ 334
See notes to Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
December 31,
2005 December 31,
2004
ASSETS
Utility plant, at original cost $ 6,927 $ 6,345
Accumulated depreciation and amortization (1,956 ) (1,821 )
Utility plant, net 4,971 4,524
Nuclear decommissioning trusts 638 612
Current assets:
Cash and cash equivalents 236 9
Accounts receivable - trade 188 185
Accounts receivable - other 83 30
Interest receivable 17 55
Due from unconsolidated affiliates 32 30
Deferred income taxes 7 --
Regulatory assets arising from fixed-price contracts 76 55
and other derivatives
Other regulatory assets 91 77
Inventories 78 88
Other 39 31
Total current assets 847 560
Other assets:
Deferred taxes recoverable in rates 294 278
Regulatory assets arising from fixed-price contracts 398 448
and other derivatives
Other regulatory assets 276 341
Sundry 68 71
Total other assets 1,036 1,138
Total assets $ 7,492 $ 6,834
See notes to Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
December 31,
2005 December 31,
2004
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock (255 million shares authorized; $ 938 $ 938
117 million shares outstanding)
Retained earnings 559 372
Accumulated other comprehensive income (loss) (14 ) (13 )
Total common equity 1,483 1,297
Preferred stock not subject to mandatory redemption 79 79
Total shareholders' equity 1,562 1,376
Long-term debt 1,455 1,022
Total capitalization 3,017 2,398
Current liabilities:
Accounts payable 243 200
Due to unconsolidated affiliates 441 15
Income taxes payable 6 225
Deferred income taxes -- 15
Regulatory balancing accounts, net 179 331
Fixed-price contracts and other derivatives 76 55
Customer deposits 52 45
Current portion of long-term debt 66 66
Other 282 256
Total current liabilities 1,345 1,208
Deferred credits and other liabilities:
Due to unconsolidated affiliate -- 267
Customer advances for construction 39 45
Deferred income taxes 591 522
Deferred investment tax credits 34 37
Regulatory liabilities arising from removal obligations 1,216 1,246
Asset retirement obligations 444 318
Fixed-price contracts and other derivatives 398 448
Mandatorily redeemable preferred securities 16 19
Deferred credits and other 392 326
Total deferred credits and other liabilities 3,130 3,228
Commitments and contingencies (Note 11)
Total liabilities and shareholders' equity $ 7,492 $ 6,834
See notes to Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in millions)
Years ended December 31,
2005 2004 2003
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 267 $ 213 $ 340
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 264 259 242
Deferred income taxes and investment tax credits 37 -- (29 )
Non-cash rate reduction bond expense 68 75 68
Other (3 ) (7 ) (6 )
Changes in other assets 13 (53 ) (3 )
Changes in other liabilities 37 (25 ) (7 )
Changes in working capital components:
Accounts receivable (56 ) (24 ) (9 )
Interest receivable 39 (18 ) (37 )
Due to/from affiliates, net (1 ) 13 2
Inventories 10 (27 ) (14 )
Other current assets (16 ) (1 ) (23 )
Income taxes (231 ) 15 8
Accounts payable 28 6 34
Regulatory balancing accounts (152 ) (15 ) (56 )
Other current liabilities 34 24 57
Net cash provided by operating activities 338 435 567
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment (464 ) (414 ) (444 )
Purchases of nuclear decommissioning and other trusts (230 ) (244 ) (271 )
Proceeds from sales by nuclear decommissioning and other trusts 234 247 277
Net proceeds from sale of assets 1 -- 4
Decrease in loans to affiliate, net 1 122 129
Net cash used in investing activities (458 ) (289 ) (305 )
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid (75 ) (205 ) (200 )
Preferred dividends paid (5 ) (5 ) (6 )
Payments on long-term debt (66 ) (317 ) (66 )
Issuances of long-term debt 500 251 --
Redemption of preferred stock (3 ) (3 ) (1 )
Other (4 ) (6 ) --
Net cash provided by (used in) financing activities 347 (285 ) (273 )
Increase (decrease) in cash and cash equivalents 227 (139 ) (11 )
Cash and cash equivalents, January 1 9 148 159
Cash and cash equivalents, December 31 $ 236 $ 9 $ 148
See notes to Consolidated Financial Statements

SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in millions)
Years ended December 31,
2005 2004 2003
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION
Interest payments, net of amounts capitalized $ 66 $ 63 $ 68
Income tax payments, net of refunds $ 291 $ 129 $ 167
See notes to Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
Years ended December 31, 2005, 2004 and PE that was completed on June 26, 1998.

2003
(Dollars in millions)
Comprehensive Income Preferred Stock Not Subject to Mandatory Redemption Common Stock Retained Earnings Accumulated Other Comprehensive Income (Loss) Total Shareholders' Equity
Balance at December 31, 2002 $ 79 $ 943 $ 235 $ (34 ) $ 1,223
Net income $ 340 340 340
Other comprehensive income adjustment - pension (9 ) (9 ) (9 )
Comprehensive income $ 331
Preferred stock dividends declared (6 ) (6 )
Common stock dividends declared (200 ) (200 )
Capital contribution (5 ) (5 )
Balance at December 31, 2003 79 938 369 (43 ) 1,343
Net income $ 213 213 213
Other comprehensive income adjustment - pension 30 30 30
Comprehensive income $ 243
Preferred stock dividends declared (5 ) (5 )
Common stock dividends declared (205 ) (205 )
Balance at December 31, 2004 79 938 372 (13 ) 1,376
Net income $ 267 267 267
Other comprehensive income adjustment - pension (1 ) (1 ) (1 )
Comprehensive income $ 266
Preferred stock dividends declared (5 ) (5 )
Common stock dividends declared (75 ) (75 )
Balance at December 31, 2005 $ 79 $ 938 $ 559 $ (14 ) $ 1,562
See notes to Consolidated Financial Statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA
Principles of Consolidation
The Consolidated Financial Statements include the accounts of SDGSan Diego Gas & Electric Company (SDG&E or the company) and its sole subsidiary, SDG&E Funding LLC. All material intercompany accounts and transactions have been eliminated.
As a subsidiary of Sempra Energy, the company receives certain services therefrom, for which it is charged its allocable share of the cost of such services. Management believes that cost is reasonable, but probably less than if the company had to provide those services itself. In addition, in connection with charges related to litigation, the significant instances of which are discussed in Note 11, Sempra Energy management determines the allocation of the charges among its business units, including the company, based on the extent of their involvement with the subject of the litigation.
Use of Estimates in the Preparation of the Financial Statements
The preparation of financial statements in conformity with accounting principles generally accepted accounting principlesin the United States of America (GAAP) requires management to make estimates and assumptions that affect the reported amounts of revenues and expenses during the reporting period, and the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements. ActualAlthough management believes the estimates and assumptions are reasonable, actual amounts can differ significantly from those estimates.
Basis of Presentation
Certain prior-year amounts have been reclassified to conform to the current year's presentation.
Regulatory Matters
Effects of Regulation
The accounting policies of the company conform with generally accepted
accounting principlesGAAP for regulated enterprises and reflect the policies of the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC). SDG&E and its affiliate, Southern California Gas Company (SoCalGas), are collectively referred to herein as "the California Utilities."
The company prepares its financial statements in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) 71
"Accounting, Accounting for the Effects of Certain Types of Regulation", under which a regulated utility records a regulatory asset if it is probable that, through the ratemaking process, the utility will recover that asset from customers. Regulatory liabilities represent future
reductions in rates for amounts due to customers. To the extent that
portions of the utility operations cease to be subject to SFAS 71, or recovery is no longer probable as a result of changes in regulation or the utility's competitive position, the related regulatory assets and

liabilities would be written off. In addition, SFAS 144, "AccountingAccounting for the Impairment or Disposal of Long-Lived Assets" affects utility
plant and regulatory assets suchAssets, requires that a loss must be recognized whenever a regulator excludes all or part of an asset's costutility plant or regulatory assets from ratebase. The application of SFAS 144 continuesRegulatory liabilities represent reductions in future rates for amounts due to be evaluated in
connection with industry restructuring.customers. Information concerning regulatory assets and liabilities is describedprovided below in "Revenues","Revenues," "Regulatory Balancing Accounts,"Accounts" and "Regulatory Assets and Liabilities,Liabilit ies." and industry restructuring is described in Notes 10 and
11.

Regulatory Balancing Accounts
The amounts included in regulatory balancing accounts at December 31, 2002,2005, represent net payables (payables net of receivables) of $394
millionthatare returned to customers by reducing future rates.
Except for certain costs subject to balancing account treatment, fluctuations in most operating and $575 million at December 31, 2002 and 2001, respectively.
The undercollected electric commodity costs accumulated under Assembly
Bill (AB) 265 are anticipated to be recovered in rates (recovery is
expected to occur before the end of 2005) and are included in
"regulatory balancingmaintenance accounts - net" at December 31, 2002.affect utility earnings. Balancing accounts provide a mechanism for charging utility customers the amount actually incurred for certain costs, primarily commodity costs. As a result of California's electric-restructuring law,
fluctuations in certainThe CPUC has also approved balancing account treatment for variances between forecast and actual for SDG&E's volumes and commodity costs, and consumption levels that had been
balanced now affecteliminating the impact on earnings from electric operations. In addition,
fluctuations in certain costsany throughput and consumption levels affect earnings
for SDG&E's natural gas operations.revenue variances from adopted forecast levels. Additional information on regulatory matters is included in Notes 109 and 11.

10.
Regulatory Assets and Liabilities
In accordance with the accounting principles of SFAS 71, the company records regulatory assets (which represent probable future revenues
associated with certain costs that will be recovered from customers
through the rate-making process) and regulatory liabilities (which
represent probable future reductions in revenue associated with amounts
that are to be credited to customers through the rate-making process).
They are amortized over the periods in which the costs are recovered
from or refunded to customers in regulatory revenues.

as discussed above.
Regulatory assets (liabilities) as of December 31 consist ofrelate to the following:

(Dollars in millions) 2002 2001
- -----------------------------------------------------------------------

Fixed-price contracts and other derivatives $ 638 $ 715
Recapture of temporary discount* 326 409
Undercollected electric commodity costs** -- 392
Deferred taxes recoverable in rates 190 162
Unamortized loss on retirement of debt - net 49 52
Employee benefit costs 35 39
Other 5 26
------- -------
Total $1,243 $1,795
======= =======
47
following matters:
(Dollars in millions) 2005 2004
Fixed-price contracts and other derivatives $ 473 $ 500
Recapture of temporary rate reduction* 116 183
Deferred taxes recoverable in rates 294 278
Unamortized loss on retirement of debt, net 42 46
Employee benefit costs 174 160
Removal obligations** (1,216 ) (1,246 )
Other 36 29
Total $ (81 ) $ (50 )
* In connection with electric industry restructuring, which is described in Note 10,9, SDG&E temporarily reduced rates to its small-usage customers. That reduction is being recovered in rates through 2004.
** The undercollected electric commodity costs accumulated under Assembly Bill
265 are anticipated2007.
** This is related to be recoveredSFAS 143,Accounting for Asset Retirement Obligations, which is discussed below in rates before the end of 2005 and are
included in regulatory balancing accounts - net at December 31, 2002.

"New Accounting Standards."
Net regulatory assets (liabilities) are recorded on the Consolidated Balance Sheets at December 31 as follows (dollars in millions):

2002 2001
- -----------------------------------------------------------------------

Current regulatory assets $ 134 $ 158
Noncurrent regulatory assets 1,111 1,638
Current regulatory liabilities* (2) (1)
------- -------
Total $1,243 $1,795
======= =======
- -----------------------------------------------------------------------
follows:
(Dollars in millions) 2005 2004
Current regulatory assets $ 167 $ 132
Noncurrent regulatory assets 968 1,067
Current regulatory liabilities* -- (3 )
Noncurrent regulatory liabilities (1,216 ) (1,246 )
Total $ (81 ) $ (50 )
* Included in other current liabilities

Other Current Liabilities.
All theof these assets either earn a return, generally at short-term rates, or the cash has not yet been expended and the assets are offset by liabilities that do not incur a carrying cost.
Cash and Cash Equivalents
Cash equivalents are highly liquid investments with maturities of three months or less at the date of purchase.
Non-cash Investing and Financing Activities
SDG&E added utility plant of $150 million and $267 million in 2005 and 2004, respectively, related to the Palomar power plant (discussed in Note 2), which will not be paid until 2006. In 2003 the company received $1 million of assets from Sempra Energy and assumed related liabilities of $6million.
Collection Allowance

Allowances
The allowance for doubtful accounts receivable was $3 million, $5
million and $5$2 million at each of December 31, 2002, 20012005, 2004 and 2000,
respectively.2003. The company recorded a provisionprovisions for doubtful accounts of $4$3 million, $9$3 million and $6$1 million in 2002, 20012005, 2004 and 2000,2003, respectively.
Inventories
At December 31, 2002,2005, inventory shown on the Consolidated Balance Sheets included natural gas of $9$30 million, and materials and supplies of $37$48 million. The corresponding balances at December 31, 20012004 were $34$50 million and $36$38 million, respectively. Natural gas is valued by the last-in first-out (LIFO) method. When the inventory is consumed, differences between thisthe LIFO valuation and replacement cost will beare reflected in customer rates. Materials and supplies at SDG&Ethe company are generally valued at the lower of average cost or market.

Utility
Income Taxes
Income tax expense includes current and deferred income taxes from operations during the year. In accordance with SFAS 109,Accounting for Income Taxes, the company records deferred income taxes for temporary differences between the book and tax bases of assets and liabilities. Investment tax credits from prior years are being amortized to income over the estimated service lives of the properties. Other credits, mainly low-income housing tax credits, are recognized in income as earned. The company follows certain provisions of SFAS 109 that permit regulated enterprises to recognize regulatory assets or liabilities to offset deferred tax liabilities and assets, respectively, if it is probable that such amounts will be recovered from, or returned to, customers.
Property, Plant and Equipment
Utility plant primarily represents the buildings, equipment and other facilities used by the company to provide natural gas and electric utility services.

48
The cost of utility plant includes labor, materials, contract services, and related items, andcertain expenditures incurred during a major maintenance outage of a generating plant. Maintenance costs are expensed as incurred. In addition, the cost of plant includes an allowance for funds used during construction (AFUDC). The cost of most retired depreciable utility plant plus
removal costs minus salvage value is charged to accumulated depreciation.
Utility plant balances by major functional categories are as follows:

- -----------------------------------------------------------------------
Depreciation rates
Utility Plant for years ended
at December 31 December 31
- -----------------------------------------------------------------------
(Dollars in billions) 2002 2001 2002 2001 2000
- -----------------------------------------------------------------------

Natural gas operations $ 1.0 $ 1.0 3.62% 3.71% 3.79%
Electric distribution 3.0 2.9 4.66% 4.67% 4.67%
Electric transmission 0.9 0.8 3.17% 3.19% 3.21%
Other electric 0.5 0.3 9.37% 8.46% 8.33%
------ ------
Total $ 5.4 $ 5.0
====== ======
- -----------------------------------------------------------------------

Utility Plant at
December 31, Depreciation rates for years ended
December 31,
(Dollars in billions) 2005 2004 2005 2004 2003
Natural gas operations $ 1.1 $ 1.0 3.42 % 3.42 % 3.63 %
Electric distribution 3.5 3.4 4.13 % 4.11 % 4.70 %
Electric transmission 1.1 1.0 3.05 % 3.06 % 3.09 %
Other electric 0.6 0.6 9.75 % 11.33 % 9.53 %
Construction work in progress 0.6 0.3 NA NA NA
Total $ 6.9 $ 6.3
Accumulated depreciation and decommissioning of natural gas and electric utility plant in service were $0.6$0.4 billion and $2.2$1.6 billion, respectively, at December 31, 2002,2005, and were $0.5$0.4 billion and $2.1$1.4 billion, respectively, at December 31, 2001.2004. Depreciation expense is based on the straight-line method over the useful lives of the assets or a shorter period prescribed by the CPUC. See Note 10 forThe discussion of SFAS 143 under "New Accounting Standards" describes a change in the salepresentation of generation facilities and industry restructuring.
Maintenance costs are expensed as incurred.

accumulated depreciation.
AFUDC, which represents the cost of debt and equity funds used to finance the construction of utility plant, is added to the cost of utility plant. Although it is not a current source of cash, AFUDC also increases income and is recorded partly as an offset to interest charges and partly as a component of other income, shownOther Income, Net in the Statements of Consolidated Income, although it is not a current source of cash.
AFUDCIncome.AFUDC amounted to $21 million, $9$12million, $12 million and $8 million$17million for 2002, 20012005, 2004 and 2000,2003, respectively.

Long-Lived Assets

The company periodically evaluates whether events or circumstances have
occurred that may affect the recoverability or the estimated useful
lives of long-lived assets. Impairment occurs when the estimated future
undiscounted cash flows is less than the carrying amount of the assets.
If that comparison indicates that the assets' carrying value may be
permanently impaired, such potential impairment is measured based on
the difference between the carrying amount and the fair value of the
assets based on quoted market prices or, if market prices are not
available, on the estimated discounted cash flows. This calculation is
performed at the lowest level for which separately identifiable cash
flows exist. See further discussion of SFAS 144 in "New Accounting
Standards".

Nuclear-Decommissioning
Nuclear Decommissioning Liability
At December 31, 20022005 and 2001, deferred credits and other liabilities
include $1392004, the company had asset retirement obligations of $339 million and $151$328 million, respectively, and related regulatory liabilities of accrued$346 million and $333 million, respectively, related to nuclear decommissioning, costs associatedin accordance with the company's interest inSFAS 143. Information about San Onofre Nuclear Generating Station (SONGS) Unit 1, which was permanently
shut down in 1992. The corresponding liability for SONGS Units 2 and 3
decommissioning (included in accumulated depreciation and amortization)
is $355 million and $375 million at December 31, 2002 and 2001,
respectively. Additional information on SONGS decommissioning costs is included below in "New Accounting Standards".

Standards."
Legal Fees
Legal fees that are associated with a past event for which a contingent liability has been recorded are accrued when it is probable that fees also will be incurred.
Comprehensive Income
Comprehensive income includes all changes, except those resulting from investments by owners and distributions to owners, in the equity of a business enterprise from transactions and other events, including foreign-currency translation adjustments, minimum pension liability adjustments unrealized gains and losses on marketable securities that
are classified as available-for-sale, and certain hedging activities. The components of other comprehensive income, which consists of all these changes other than net income as shown on the Statements of Consolidated Income, are shown in the Statements of Consolidated Changes in Shareholders' Equity. At December 31, 2005, Accumulated Other Comprehensive Income consisted entirely of minimum pension liability adjustments, net of related income tax.
Revenues
Revenues are primarily derived from deliveries of electricity and natural gas to customers and changes in related regulatory balancing accounts. Revenues from electricity and natural gas sales and services are generally recorded under the accrual method and these revenues are recognized upon delivery. The portion of SDG&E's electric commodity that was procured for its customers by the California Department of Water Resources (DWR) and delivered by SDG&E is not included in SDG&E's revenues or costs. For
2001, California Power Exchange (PX)Commodity costs associated with long-term contracts allocated to SDG&E from the DWR also are not included in the Statements of Consolidated Income, since the DWR retains legal and Independent System Operator
(ISO) power revenues have been netted against purchased-power expense
to avoid double-counting as SDG&E sold power into the PX/ISO and then
purchased power therefrom. Refer tofinancial responsibility for these contracts. Note 10 for9 includes a discussion of the electric industry restructuring. Operating revenue includes amounts for services rendered but unbilled (approximately one-half month's deliveries) at the end of each year.

Operating costs of SONGS Units 2 and 3 (including nuclear fuel and
nuclear fuel financing costs) and incremental capital expenditures are
recovered through the Incremental Cost Incentive Pricing (ICIP)
mechanism which allows SDG&E to receive approximately 4.4 cents per
kilowatt-hour (kWh) through 2003. Any differences between these costs
and the incentive price affect net income and, for the year ended
December 31, 2002, the ICIP contributed $50 million to SDG&E's net
income. The CPUC has rejected an administrative law judge's proposed
decision to end ICIP prior to its December 31, 2003 scheduled
expiration date. However, the CPUC has also denied the previously
approved market-based pricing for SONGS beginning in 2004 and instead
provided for traditional rate-making treatment, under which the SONGS
ratebase would begin at zero, essentially eliminating earnings from
SONGS until ratebase grows. The company has applied for rehearing of
this decision.

50
Additional information concerning utility revenue recognition is discussed above under "Regulatory Matters."

Related Party
Transactions - Loans to Unconsolidatedwith Affiliates
On a daily basis, SDG&E has a promissory note receivableand SoCalGas share numerous functions with each other and they also receive various services from and provide various services to Sempra Energy which bears a
variable interest rate based on short-term commercial paper rates,Energy.
At December 31, 2005 and is due on demand. The note balance was $2502004, SDG&E had $32 million and $52$30 million, respectively, due from affiliates. These amounts are included in current assets as Due from Unconsolidated Affiliates.
Additionally, at December 31, 20022005, SDG&E had $441 million due to affiliates, including $20 million to Sempra Energy and 2001, respectively.$417 million related to the Palomar project, which is included in current liabilities as Due to Unconsolidated Affiliates. At December 31, 2001, the
"Due from unconsolidated affiliates" account balance also included $24
million of offsetting working capital balances with Sempra Energy
affiliates. In addition, at December 31, 2002,2004, SDG&E had $42 million
due from and $3$15 million due to Sempra Energy, affiliates. SDG&E also
had $16which is included in current liabilities and $267 million related to the Palomar project, which is included in noncurrent liabilities. These amounts are reported as Due to Unconsolidated Affiliates.
Other Income, Net
Other Income, Net consists of the following:
Years ended December 31,
(Dollars in millions) 2005 2004 2003
Interest income $ 23 $ 25 $ 42
Regulatory interest, net (3 ) (6 ) (5 )
Allowance for equity funds used during construction 9 9 12
Income taxes on non-operating income 21 (11 ) (21 )
Sundry, net 8 8 (3 )
Total $ 58 $ 25 $ 25
New Accounting Standards
SFAS 123 (revised 2004),"Share-Based Payment" (SFAS 123R): In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS 123R, a revision of SFAS 123,Accounting for Stock-Based Compensation(SFAS 123), which establishes the accounting for transactions in which an entity exchanges its equity instruments for goods or services received. This statement requires companies to measure and $5 millionrecord the cost of employee services received in non-current liabilities due toexchange for an award of equity instruments based on the grant-date fair value of the award. Sempra Energy at December 31, 2002 and 2001, respectively.

New Accounting Standards

expects to adopt the provisions of SFAS 123R using a modified prospective application. The modified prospective method requires companies to recognize compensation cost for unvested awards that are outstanding on the effective date based on the fair value that the company had originally estimated for purposes of preparing its SFAS 123 pro forma disclosures. For all new awards that are granted or modified after the effective dat e, a company would use SFAS 123R's measurement model. The effect of adopting FAS 123R has not been determined. The effective date of this statement is January 1, 2006 for Sempra Energy.
SFAS 143, "Accounting for Asset Retirement Obligations"and FASB Interpretation No (FIN) 47, "Accounting for Conditional Asset Retirement Obligations, an interpretation of SFAS 143": Beginning in 2003, SFAS 143 issued in July 2001, addresses financial accounting and reporting
for obligations associated with the retirement of tangible long-lived
assets and the associated asset retirement costs. This applies to legal
obligations associated with the retirement of long-lived assets that
result from the acquisition, construction, development and/or normal
operation of long-lived assets, such as nuclear plants. It requires entities to record the fairpresent value of a liabilityliabilities for an assetfuture costs expected to be incurred when assets are retired from service, if the retirement obligation inprocess is legally required. It requires recording of the period in which it is incurred. Whenestimated retirement cost over the liability is initially recorded, the entity increases the carrying
amountlife of the related long-lived asset by depreciating the present value of the future retirement cost. Overobligation (measured at the time of the asset's acquisition) and accreting the discount until the liability is accreted to its
full value and paid, and the capitalized cost is depreciated over the
useful life of the related asset. SFAS 143 is effective for financial
statements issued for fiscal years beginning after June 15, 2002. The
items noted below were identified by the company to have a material
asset retirement obligation.

Adoption of SFAS 143 will change the accounting for the decommissioning
of the company's share of SONGS. Prior to thesettled.The adoption of SFAS 143 the
company recorded the obligation for decommissioning over the lives of
the plants. At December 31, 2002, the company's share of
decommissioning cost for the SONGS' units has been estimated to be $309
million in 2002 dollars, based on a 2001 cost study filed with the
CPUC. The adoption of this standard, effective January 1, 2003 will
require a cumulative adjustment to adjust plant assets and
decommissioning liabilities toresulted in the values they would have been had this
standard been employed from the in-service datesrecording of the plants. Upon
adoption of SFAS 143 in 2003, the company will record an addition of
$70 million to utility plant of $71 million, representing the company's share of SONGSSONGS' estimated future decommissioning costs (as discounted to the present value at the datedates the various units began operation), and accumulate d depreciation of $41 million related to the increase to utility plant, for a net increase of $30 million. On January 1, 2003, the company recorded additional asset retirement obligations of $10 million associated with the future retirement of a former power plant.
In March 2005, the FASB issued FIN 47,"Accounting for Conditional Asset Retirement Obligations, an interpretation of SFAS 143." The interpretation clarifies that the term "conditional asset-retirement obligation" as used in SFAS 143, refers to a legal obligation to perform an asset-retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 requires companies to recognize a liability for the fair value of a conditional asset-retirement obligation if the fair value of the obligation can be reasonably estimated.
The adoption of FIN 47 on December 31, 2005 resulted in the recording of an addition to utility plant of $32 million and accumulated depreciation of $13 million related to the increase to utility plant, for a net increase of $19 million. In addition, the company recorded a corresponding retirement obligation liability of $309 million. The
nuclear decommissioning trusts' balance$116 million (which includes accretion of $494 million atthat discounted value to December 31, 2002 represents amounts collected for future decommissioning costs2005) and
earnings thereon, and has a corresponding offset in accumulated
depreciation ($355 million related to SONGS Units 2 and 3) and deferred
credits ($139 million related to SONGS Unit 1). The difference between
the amounts results in a regulatory liability of $214$164 million to 51
reflect that SDG&Ethe company has collected the funds from its customers more quickly than SFAS 143FIN 47 would accrete the retirement liability and depreciate the asset. See further discussion
The adoption of SONGS' decommissioningSFAS 143 required the reclassification of estimated removal costs collected in rates, which had historically been recorded in accumulated depreciation, to a regulatory liability. At December 31, 2005 and 2004, these costs were $724 million and $913 million, respectively. The change in the balance is due to the implementation of FIN 47, which required the reclassification of disposal costs that previously have been included in the company's estimated cost of removal obligations to a regulatory liability and to Asset Retirement Obligations.
In accordance with FIN 47, the company has determined that the amount of asbestos-containing materials could not be determined and, therefore, no liability has been recognized for the related nuclear decommissioning trustsremoval obligations. Since most, if not all, of the cost of removing such materials would be expected to be recovered in Note 4.

Asrates, the effect of January 1, 2003,not recognizing these liabilities is not material to the company's financial condition or results of operations. A liability for the obligations will be recorded in the period in which sufficient information is available to reasonably estimate the removal cost.
Had FIN 47 been in effect on December 31, 2004, the asset retirement obligation liability would have been $109 million as of that date.
Except for the items noted above, the company has determined that there are no other material retirement obligations associated with tangible long-lived assets.
Implementation of SFAS 143 and FIN 47 had additionalno significant effect on results of operations and is not expected to have a significant effect in the future.
The changes in the asset retirement obligations estimated to be $12 million associated with the retirement
of a former power plant.

SFAS 144, "Accounting for Impairment or Disposal of Long-Lived
Assets": In August 2001, the Financial Accounting Standards Board
(FASB) issued SFAS 144, which replaces SFAS 121, "Accounting for the Impairmentyears ended December 31, 2005 and 2004 are as follows (dollars in millions):
2005 2004
Balance as of January 1 $ 339 * $ 326 *
Adoption of FIN 47 116 --
Accretion expense 23 23
Payments (15 ) (10 )
Balance as of December 31 $ 463 * $ 339 *
* The current portion of Long-Lived Assetsthe obligation is included in Other Current Liabilities on the Consolidated Balance Sheets.
SFAS 154,"Accounting Changes and for Long-Lived Assets to Be
Disposed Of.Error Corrections, a replacement of Accounting Principles Board Opinion (APBO) 20 and FASB Statement No. 3:" SFAS 144This statement applies to all long-lived assets,voluntary changes in accounting principles and to changes required by an accounting pronouncement in instances where the pronouncement does not include specific transition provisions. APBO 20 previously required that most voluntary changes in accounting principle be recognized by including discontinued operations. SFAS 144 requires that those long-lived assets
classified as held for sale be measured at the lower of carrying amount
(cost less accumulated depreciation) or fair value less cost to sell.
Discontinued operations will no longer be measured atin net realizable
value or include amounts for operating losses that have not yet
occurred. SFAS 144 also broadens the reporting of discontinued
operations to include all components of an entity with operations that
can be distinguished from the restincome of the entity and that will be
eliminated from the ongoing operationsperiod of the entity in a disposal
transaction. The company has identified no material effectschange the cumulative effect of changing to the new accounting principle. SFAS 154 requires retrospective application to prior periods' financial statements from the implementation of SFAS 144.

SFAS 148, "Accounting for Stock-Based Compensation - Transition
and Disclosure": In December 2002, the FASB issued SFAS 148, an
amendment to SFAS 123, "Accounting for Stock-Based Compensation," which
gives companies electing to expense employee stock options three
methodschanges in accounting principle, unless it is impracticable to do so. In addition, theThis statement amends the disclosure
requirements to require more prominent disclosure about the method of
accounting for stock-based employee compensation and the effect of the
method used on reported results in both annual and interim financial
statements.

The company has elected to continue using the intrinsic value method of
accounting for stock-based compensation. Therefore, the amendment to
SFAS 123 will not have any effect on the company's financial
statements. See Note 7 for additional information regarding stock-based
compensation.

SFAS 149, "Accounting for Certain Financial Instruments with
Characteristics of Liabilities and Equity": On January 22, 2003, the
FASB directed its staff to prepare a draft of SFAS 149. The final draft
is expected to be issued in March 2003. The statement will establish
standardseffective for accounting for financial instruments with characteristicschanges and corrections of liabilities, equity, or both. Subsequent to the issuance of SFAS
149, certain investments that are currently classified as equity in the
financial statements might have to be reclassified as liabilities. In
addition, the FASB decided that SFAS 149 will prohibit the presentation
of certain items in the mezzanine section (the portion of the balance
sheet between liabilities and equity) of the statement of financial
position. For example, certain mandatorily redeemable preferred stock,
which is currently included in the mezzanine section, may be classified
as a liability once SFAS 149 goes into effect. The proposed effective
date of SFAS 149 is July 1, 2003 for the company.

FASB Interpretation 45, "Guarantor's Accounting and Disclosure
Requirements for Guarantees": In November 2002, the FASB issued
Interpretation 45, which elaborates on the disclosures to beerrors made in interim and annual financial statements of a guarantor about its
obligations under certain guarantees that it has issued. It also
clarifies that a guarantor is required to recognize, at the inception
of a guarantee, a liability for the fair value of the obligation
undertaken in issuing a guarantee. Initial recognition and measurement
provisions of the Interpretation are applicable on a prospective basis
to guarantees issued or modified after December 31, 2002. The
disclosure requirements are effective for financial statements of
interim or annual periods endingfiscal years beginning after December 15, 2002. As of
December 31, 2002, the company did not have any outstanding guarantees.

Other Accounting Standards: During 2002 and 2001 the FASB and the
Emerging Issues Task Force (EITF) issued several statements that are
currently not applicable to the company. In July 2001, the FASB issued
SFAS 142, "Goodwill and Other Intangible Assets,2005.
FIN 46," which addresses how
intangible assets that are acquired individually or with a group of
other assets (but not those acquired in a business combination) should
be accounted for in financial statements upon their acquisition. In
April 2002, the FASB issued SFAS 145, which rescinds SFAS 4, "Reporting
Gains and Losses from Extinguishment of Debt", and SFAS 64,
"Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements." In
June 2002, the FASB issued SFAS 146, "Accounting for Costs Associated
with Exit or Disposal Activities," which addresses accounting for
restructuring and similar costs. SFAS 146 supersedes previous
accounting guidance, principally EITF Issue 94-3, "Liability
Recognition for Certain Employee Termination Benefits and Other Costs
to Exit an Activity (including Certain Costs Incurred in a
Restructuring)." In October 2002, the FASB issued SFAS 147, "Accounting
for Certain Financial Institutions - an amendment of SFAS 72 and 144
and FASB Interpretation 9," which applies to acquisitions of financial
institutions. In June 2002, a consensus was reached in EITF Issue 02-3,
which codifies and reconciles existing guidance on the recognition and
reporting of gains and losses on energy trading contracts and addresses
other aspects of the accounting for contracts involved in energy
trading and risk management activities. In October 2002, the EITF
reached a consensus to rescind EITF Issue 98-10, "Accounting for Energy
Trading Contracts," the basis for mark-to-market accounting used for
recording energy-trading activities. In January 2003, the FASB issued
Interpretation 46, "ConsolidationConsolidation of Variable Interest Entities," which
addresses consolidation an interpretation of Accounting Research Bulletin (ARB) No. 51": FIN 46, as revised by business enterprises ofFIN 46R, requires an enterprise to consolidate a variable interest entities.

entity (VIE), as defined in FIN 46, if the company is the primary beneficiary of a VIE's activities.
Contracts under which SDG&E acquires power from generation facilities otherwise unrelated to SDG&E could result in a requirement for SDG&E to consolidate the entity that owns the facility. In accordance with FIN 46, SDG&E is continuing the process of determining whether it has any such situations and, if so, gathering the information that would be needed to perform the consolidation. The effects of this, if any, are not expected to significantly affect the financial position of SDG&E and there would be no effect on results of operations or liquidity.
NOTE 2. SHORT-TERM BORROWINGS

At December 31, 2002, DEBT AND CREDIT FACILITIES
Committed Lines of Credit
SDG&E and its affiliate,SoCalGas, hadhave a combined $600 million five-year syndicated revolving line of credit facility expiring in 2010, under which each utility individually couldmay borrow up to $300$500 million, subject to athe combined borrowing limit for both utilities of $500$600 million. Borrowings under the agreement which
are available for general corporate purposes including support for
commercial paper and variable-rate long-term debt, bear interest atinterestat rates varying with market rates and SDG&E's credit rating. This
revolving credit commitment expires in May 2003, at which time the
outstanding borrowings may be converted into a one-year term loan

subject to any requisite regulatory approvals related to long-term
debt. ThisThe agreement requires SDG&E to maintain, at the end of each quarter, a debt-to-totalratio of total indebtedness to total capitalization ratio (as defined in the agreement)facility) of not to exceed 60
percent. The rights, obligations and covenants of each utilityno more than 65 percent.Borrowings under the agreement are individual rather than joint with thoseobligations of the otherborrowing utility and a default by one utility would not constitute a default, or preclude borrowings by, the other. These lines of credit were unused at December 31, 2002. At December 31, 2002,2005, SDG&E had no commercial paper outstanding.

NOTE 3. amounts outstanding under this facility.
LONG-TERM DEBT

- -------------------------------------------------------------------
December 31,
(Dollars
December 31,
(Dollars in millions) 2005 2004
First mortgage bonds
6.8% June 1, 2015 $ 14 $ 14
5.3% November 15, 2015 250 --
5.9% June 1, 2018 68 68
5.9% September 1, 2018 93 93
5.85% June 1, 2021 60 60
5% to 5.25% December 1, 2027 150 150
2.516% to 2.832%* January and February 2034 176 176
5.35% May 15, 2035 250 --
2.8275%* May 1, 2039 75 75
1,136 636
Rate-reduction bonds, 6.31% to 6.37% at December 31, 2005 payable
through 2007 132 198
Other bonds
5.9% June 1, 2014 130 130
5.3% July 1, 2021 39 39
5.5% December 1, 2021 60 60
4.9% March 1, 2023 25 25
254 254
1,522 1,088
Current portion of long-term debt (66 ) (66 )
Unamortized discount on long-term debt (1 ) --
Total $ 1,455 $ 1,022
* After floating-to-fixed rate swaps expiring in millions) 2002 2001
- -------------------------------------------------------------------
First-mortgage bonds
6.8% June 1, 2015 $ 14 $ 14
5.9% June 1, 2018 68 68
5.9% to 6.4% September 1, 2018 176 176
6.1% September 1, 2019 35 35
Variable rates (1.34% to 1.35% at
December 31, 2002) September 1, 2020 58 58
5.85% June 1, 2021 60 60
6.4% and 7% December 1, 2027 225 225
8.5% April 1, 2022 -- 10
7.625% June 15, 2002 -- 28

------------------------
636 674
------------------------
Unsecured long-term debt
5.9% June 1, 2014 130 130
Variable rates (1.75% at December 31, 2002)
July 1, 2021 39 39
Variable rates (2.00% at December 31, 2002)
December 1, 2021 60 60
6.75% March 1, 2023 25 25
------------------------
254 254
------------------------
Rate-reduction bonds, 6.19% to 6.37% at
December 31, 2002 payable annually
through 2007 329 395
------------------------
1,219 1,323
Less:
Current portion of long-term debt 66 93
Unamortized discount on long-term debt -- 1
------------------------
Total $1,153 $1,229
- -------------------------------------------------------------------

2009.
Maturities of long-term debt are:
(Dollars in millions)
2006 $ 66
2007 66
2008 --
2009 --
2010 --
Thereafter 1,390
Total $ 1,522
Callable Bonds
At the company's option,certain bonds are $66 million in 2003, $66 million in
2004, $66 million in 2005, $66callable at various dates: $472 million in 2006 $66and $274 million in 2007 and
$889after 2010. In addition, $500 million thereafter. Holders of variable-rate bonds may require the
issueris callable subject to repurchase them prior to scheduled maturity. However, since
repurchased bonds would be remarketed and funds for repurchase are

provided by revolving lines of credit (which are generally renewed upon
expiration and which are described in Note 2), it is assumed the bonds
will be held to maturity for purposes of determining the maturities
listed above.

First-mortgagemake-whole provisions.
First Mortgage Bonds

The first-mortgage bonds are secured
First mortgage bondsaresecured by a lien on SDG&E's utility plant. SDG&E may issue additional first-mortgagefirst mortgage bonds upon compliance with the provisions of its bond indenture,itsbondindenture, which requires, among other things, the satisfaction of pro forma earnings-coverage tests on first-first mortgage bond interest and the availability of sufficient mortgaged property to support the additional bonds.bonds, after giving effect to prior bond redemptions. The most restrictive of these tests (the property test) would permit the issuance, subject to CPUC authorization, of an additional $2.1$2.3 billion of first-mortgagefirst mortgage bonds at December 31, 2002.

During2005.
In November 2005, the first quarter of 2001, SDG&E remarketed $150company issued $250 million of variable-rate first-mortgagefirst mortgage bonds for a five-year term at a fixed ratematuring in 2015.In May 2005, the company issued $250 million of 7%. At SDG&E's option, thefirst mortgage bonds may be remarketed at a fixed or
floating ratematuring in 2035.
Unsecured Long-term Debt
Various long-term obligations totaling $254million at December 1,31, 2005 the expiration of the fixed term.
In June and July 2002, SDG&E paid off its $28 million 7.625% first-
mortgage bonds and $10 million 8.5% first-mortgage bonds, respectively.

Callable Bonds

At SDG&E's option, certain bonds may be called at a premium, including
$157 million of variable-rate bonds that are callable at various dates
in 2003. Of SDG&E's remaining callable bonds, $460 million are callable
in 2003, $25 million in 2004, and $105 million in 2005.

unsecured.
Rate-Reduction Bonds
In December 1997, $658 million of rate-reduction bonds were issued on behalf of SDG&E at an average interest rate of 6.26 percent.6.26%. These bonds were issued to facilitate the 10%10percent rate reduction mandated by California's electric-restructuring law, which is described in Note 10.
These bonds9. They are being repaid over ten years by SDG&E's residential and small-commercial customers viathrough a specified charge on their electricity bills. These bonds are secured by the revenue streams collected from customers and are not secured by, or payable from, utility assets.

The sizes of the rate-reduction bond issuances were set so as to make
the investor owned utilities (IOUs) neutral as to the 10% rate
reduction, and were based on a four-year period to recover stranded
costs. Because SDG&E recovered its stranded costs in only 18 months
(due to the greater-than-anticipated plant-sale proceeds), the bond
sale proceeds were greater than needed. Accordingly, during the third
quarter of 2000, SDG&E returned to its customers $388 million of
surplus bond proceeds in accordance with a June 8, 2000 CPUC decision.
The bonds and their repayment schedule are not affected by this refund.

Unsecured Long-term Debt

In February 2001, SDG&E remarketed $25 million of variable-rate
unsecured bonds as 6.75 percent fixed-rate debt for a three-year term.
At SDG&E's option, the bonds may be remarketed at a fixed or floating

rate at February 29, 2004, the expiration of the fixed term. Various
long-term obligations totaling $254 million are unsecured at December
31, 2002.

property.
Interest-Rate Swaps
The company periodically enters into interest-rate swap agreements to moderate its exposure to interest-rate changes and to lower its overall cost of borrowing. During 2002 and 2001,
Cash flow hedges
In September 2004, SDG&E had anentered into interest-rate swap agreement that maturedswaps to exchange the floating rates on its $251 million Chula Vista Series 2004 bonds maturing from 2034 through 2039 for fixed rates. The swaps expire in 2002 that effectively fixed2009. At December 31, 2005 pre-tax income arising from the interest
rate on $45ineffective portion of interest-rate cash flow hedges included $4 million of variable-rate underlying debt at 5.4 percent.
This floating-to-fixed-rate swap did not qualify for hedge accounting
and, therefore, the gains and losses associated with the change in fair
value are recorded in Other Income, Net on the Statements of Consolidated Income. The effect of the interest-rate cash flow hedges on other comprehensive income (loss) was a $1 million gainimmaterial for the years ended December 31, 2005 and 2004. The balance in 2002 and a $1 million loss in 2001.
See additional discussion ofAccumulated Other Comprehensive Income (Loss) at December 31, 2005, related to interest-rate swaps in Note 8.

Financial Covenants

SDG&E's first-mortgage bond indenture requirescash flow hedges was reduced to zero due to the satisfaction of
certain bond interest coverage ratios and the availability of
sufficient mortgaged property to issue additional first-mortgage bonds,
but do not restrict other indebtedness. Note 2 discusses the financial
covenants applicable to short-term debt.

hedge ineffectiveness.
NOTE 4.3. FACILITIES UNDER JOINT OWNERSHIP
SONGS and the Southwest Powerlink transmission line are owned jointly with other utilities. The company's interests at December 31, 2002, are2005 were as follows:

(Dollars in millions)
Southwest
Project SONGS Powerlink
- --------------------------------------------------------------------
Percentage ownership 20% 88%
Utility plant in service $ 76 $222
Accumulated depreciation and amortization $ 53 $134
Construction work in progress $ 5 $ 12
- --------------------------------------------------------------------

(Dollars in millions) SONGS Southwest
Powerlink
Percentage ownership 20% 91%
Utility plant in service $ 39 $ 290
Accumulated depreciation and amortization $ 2 $ 156
Construction work in progress $ 21 $ 9
The company and the other owners each holdholds its interest as an undivided interest as tenants in common.common in the property. Each owner is responsible for financing its share of each project and participates in decisions concerning operations and capital expenditures.
The company's share of operating expenses is included in the Statements of Consolidated Income. Participants in each project must provide their
own financing. The amounts specified above for SONGS include nuclear
production, transmission and other facilities. Certain substation
equipment at SONGS is wholly owned by the company.

SONGS Decommissioning
Objectives, work scope and procedures for the future dismantling and decontamination of the SONGS units must meet the requirements of the 56
Nuclear Regulatory Commission (NRC), the Environmental Protection Agency, the U.S. Department of the Navy (the land owner), the CPUC and other regulatory bodies.
The company's share of decommissioning costs for the SONGS units is estimated to be $309$339 million in 2002 dollars, based on a 2001 cost
study completed and filed with the CPUC in 2002. At this time,2005 dollars. That amount includes the cost studyto decommission Units 2 and resulting contributions are expected3, and the remaining cost to be finalized and
approved or disapproved by the CPUCcomplete Unit 1's decommissioning, which is currently in April of 2003.progress. Cost studies are updated every three years and approved byyears. The most recent update was submitted to the CPUC. The next such
update is expected to occurCPUC for its approval in 2005. Rate recovery of decommissioning costs is allowed until the time that the costs are fully recovered, and is subject to adjustment every three years based on the costs allowed by regulators. The amount accrued each year is currently being collected
in rates. Currently, collectionsCollections are authorized to continue until 2013, but may be extended upon request to the CPUC until 2022. The requested
amount is consideredat which time sufficient to cover the company's share of future
decommissioning costs. Payments to the nuclear decommissioning trusts
(described below under "Nuclear Decommissioning Trusts")funds are expected to continue until sufficient funds have been collected to fully decommission SONGS, which is notbut may be extended by CPUC approval until 2022, when the units' NRC operating licenses terminate and the decommissioning of Units 2 and 3 would be expected to begin before 2022.

Unit 1 was permanently shut down in 1992, and physical decommissioning
began in January 2000. Several structures, foundations and large
components have been dismantled and removed. Preparations have been
made for the remaining major work to be performed in 2003 and beyond.
That work will include dismantling, removal and disposal of all
remaining Unit 1 equipment and facilities (both nuclear and non-nuclear
components), decontamination of the site and completion of an on-site
storage facility for Unit 1 spent fuel. These activities are expected
to be completed by 2008.

begin.
The amounts collected in rates are invested in externally managed trust funds (described below under "Nuclear Decommissioning Trusts"). The
securitiesfunds. Amounts held by the trusttrusts are considered available for sale and the
trust is shown on the Consolidated Balance Sheets at market value.
These values reflect unrealized gains of $95 million and $122 million
at December 31, 2002, and 2001, respectively,invested in accordance with the offsetting
credit recorded to accumulated depreciation and amortization on the
Consolidated Balance Sheets.

See discussion regarding the impact of SFAS 143 in Note 1.

Nuclear Decommissioning Trusts

SDG&E has a Nonqualified Nuclear Decommissioning Trust and a Qualified
Nuclear Decommissioning Trust. CPUC guidelines prohibit investments in
derivatives and securities of Sempra Energy or related companies. They
alsoregulations that establish maximum amounts for investments in equity securities (50 percent of thea qualified trust and 60 percent of thea nonqualified trust), international equity securities (20 percent) and securities of electric utilities having ownership interests in nuclear power plants (10 percent). Not less than 50 percent of the equity portion of the Trusts shalltrusts must be invested passively. 57

AtThe securities held by the trust are considered available for sale. These trusts are shown on the Consolidated Balance Sheets at market value with the offsetting credits recorded in Asset Retirement Obligations and Regulatory Liabilities Arising from Removal Obligations.
Unit 1 was permanently shut down in 1992, and physical decommissioning began in January 2000. Several structures, foundations and large components have been dismantled, removed and disposed of. Spent nuclear fuel has been removed from the Unit 1 Spent Fuel Pool and stored on-site in an independent spent fuel storage installation (ISFSI) licensed by the NRC. The remaining major work will include dismantling, removal and disposal of all remaining equipment and facilities (both nuclear and non-nuclear components), and decontamination of the site. These activities are expected to be completed in 2008. The ISFSI will be decommissioned after a permanent storage facility becomes available and the spent fuel is removed from the site by the U.S. Department of Energy. Unit 1's reactor vessel is expected to remain on site until Units 2 and 3 are decommissioned.
Trust investments include:
December 31,
(Dollars in millions) Maturity dates 2005 2004
Municipal bonds 2006 - 2034 $ 54 $ 45
U.S. government issues 2006 - 2038 222 209
Cash and other securities 2006 - 2033 35 55
Equity securities 327 303
Total $ 638 $ 612
Net earnings of the trust were $30 million in 2005, $46 million in 2004 and $82 million in 2003. Proceeds from sales of securities (which are reinvested) were $223 million in 2005, $237 million in 2004 and $266 million in 2003, including net gains of $3 million, $12 million and $4 million in 2005, 2004 and 2003, respectively. The net unrealized holding gains included in Asset Retirement Obligations and Regulatory Liabilities Arising from Removal Obligations on the Consolidated Balance sheets were $193 million, $182 million and $159 million at December 31, 20022005, 2004 and 2001, trust assets were allocated as follows
(dollars in millions):

Qualified Trust Nonqualified Trust
2002 2001 2002 2001
------------- -------------
Domestic equity $143 $144 $ 36 $ 48
Foreign equity 69 76 -- --
---- ---- ---- ----
Total equity 212 220 36 48
Total fixed income 220 225 26 33
---- ---- ---- ----
Total $432 $445 $ 62 $ 81
==== ==== ==== ====

Decommissioning cost studies are conducted every three years to
determine the appropriate level of contributions to be collected in
utility-customer rates to ensure adequate funding at the
decommissioning date. 2003, respectively.
Customer contribution amounts are determined by estimates of after-tax investment returns, decommissioning costs and decommissioning cost escalation rates. Lower actual investment returns or higher actual decommissioning costs would result in an increase in future customer contributions.
Discussion regarding the impact of SFAS 143 is provided in Note 1. Additional information regarding SONGS is included in Notes 109 and 12.

11.
NOTE 5.4. INCOME TAXES

The reconciliation
Reconciliations of the U.S. statutory federal income tax rate to the effective income tax rate isare as follows:

Years ended December 31 2002 2001 2000
- ---------------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Depreciation 2.3 5.9 6.6
State income taxes - net of
federal income tax benefit 6.1 5.8 8.5
Tax credits (0.9) (0.9) (1.5)
Settlement of Internal Revenue
Service audit (8.6) -- --
Other - net (3.6) (2.3) 0.2
-------------------------
Effective income tax rate 30.3% 43.5% 48.8%
- ---------------------------------------------------------------------

58
Years ended December 31,
2005 2004 2003
Statutory federal income tax rate 35 % 35 % 35 %
Depreciation 4 4 4
State income taxes - net of federal income tax benefit 6 5 7
Tax credits (1 ) (1 ) (1 )
Resolution of Internal Revenue Service audits (13 ) -- (12 )
Other - net (6 ) (2 ) (3 )
Effective income tax rate 25 % 41 % 30 %
The components of income tax expense are as follows:

(Dollars in millions) 2002 2001 2000
- ---------------------------------------------------------------------
Current
Federal $ 164 $ 120 $(115)
State 41 30 (41)
------------------------
Total current taxes 205 150 (156)
------------------------
Deferred
Federal (93) 7 244
State (18) (13) 59
------------------------
Total deferred taxes (111) (6) 303
------------------------
Deferred investment
tax credits - net (3) (3) (3)
------------------------
Total income tax expense $ 91 $ 141 $ 144
- ---------------------------------------------------------------------

Federal
Years ended December 31,
(Dollars in millions) 2005 2004 2003
Current:
Federal $ 27 $ 107 $ 133
State 25 41 44
Total 52 148 177
Deferred:
Federal 39 15 (20 )
State 1 (12 ) (6 )
Total 40 3 (26 )
Deferred investment tax credits (3 ) (3 ) (3 )
Total income tax expense $ 89 $ 148 $ 148
On the Statements of Consolidated Income, federal and state income taxes are allocated between operating income and other income. SDG&Eincome.The company is included in the consolidated income tax return of Sempra Energy and is allocated income tax expense from Sempra Energy in an amount equal to that which would result from the company's having always filed a separate return. At December 31, 2005, income taxes payable to Sempra Energy are $6 million.
Accumulated deferred income taxes at December 31 consist ofrelate to the following:

(Dollars in millions) 2002 2001
- ----------------------------------------------------------------------
Deferred tax liabilities:
Differences in financial and
tax bases of utility plant $ 552 $ 391
Regulatory balancing accounts 212 432
Loss on reacquired debt 22 24
Other 85 75
--------------------
Total deferred tax liabilities 871 922
--------------------
Deferred tax assets:
Investment tax credits 29 31
Other 187 124
--------------------
Total deferred tax assets 216 155
--------------------
Net deferred income tax liability $ 655 $ 767
- ----------------------------------------------------------------------

59
(Dollars in millions) 2005 2004
Deferred tax liabilities:
Differences in financial and tax bases of utility plant $ 591 $ 575
Regulatory balancing accounts 100 74
Loss on reacquired debt 14 20
Other 18 16
Total deferred tax liabilities 723 685
Deferred tax assets:
Investment tax credits 23 27
Deferred compensation 18 29
State income taxes 20 43
Workers compensation and public liability insurance 6 6
Environmental liabilities 8 11
Other accruals not yet deductible 59 30
Other 5 2
Total deferred tax assets 139 148
Net deferred income tax liability $ 584 $ 537
The net deferred income tax liability is recorded on the Consolidated Balance Sheets at December 31 as follows:

(Dollars in millions) 2002 2001
- --------------------------------------------------------------------
Current liability $ 53 $ 128
Noncurrent liability 602 639
------------------
Total $ 655 $ 767
- --------------------------------------------------------------------

(Dollars in millions) 2005 2004
Current (asset) liability $ (7 ) $ 15
Noncurrent liability 591 522
Total $ 584 $ 537
NOTE 6.5. EMPLOYEE BENEFIT PLANS
The company has funded and unfunded noncontributory defined benefit plans that together cover substantially all of its employees. The plans provide defined benefits based on years of service and either final average or career salary.
The company also has other postretirement benefit plans covering substantially all of its employees. The life insurance plans are both contributory and noncontributory, and the health care plans are contributory, with participants' contributions adjusted annually. Other postretirement benefits include medical benefits for retirees' spouses.
Pension and Other Postretirement Benefitsother postretirement benefits costs and obligations are dependent on assumptions used in calculating such amounts. These assumptions include discount rates, expected return on plan assets, rates of compensation increase, health care cost trend rates, mortality rates, and other factors. These assumptions are reviewed on an annual basis prior to the beginning of each year and updated when appropriate. The company sponsors several qualified and nonqualifiedconsiders current market conditions, including interest rates, in making these assumptions.
Effective January 1, 2006 the company's other postretirement benefit plans were amended to integrate the benefits plan design across the California Utilities, resulting in a $52 million increase in the benefit obligation as of December 31, 2005.
December 31 is the measurement date for the pension plans and other postretirement benefit plans for its employees.

During 2002, the company had amendments to other postretirement benefit
plans related to the transfer of employees to SDG&E and changes to
their specific benefits which resulted in a decrease in the benefits
obligation of $7 million. The amortization of these changes will affect
pension expense in future years.

During 2001, the company participated in a voluntary separation
program. As a result, the company recorded a $13 million special
termination benefit, a $1 million curtailment cost and a $19 million
settlement gain.

During 2000, the company participated in another voluntary separation
program. As a result, the company recorded a $5 million special
termination benefit.

60
plans. The following tables providetable provides a reconciliation of the changes in the plans' projected benefit obligations during the latest two years, and the fair value of assets over
the two years, and a statement of the funded status as of eachthe latest two year end:

Other
Pension Benefits Postretirement Benefits
--------------------------------------------
(Dollars in millions) 2002 2001 2002 2001
- -----------------------------------------------------------------------------------------

WEIGHTED-AVERAGE ASSUMPTIONS AS OF
DECEMBER 31:
Discount rate 6.50% 7.25% 6.50% 7.25%
Expected return on plan assets 8.00% 8.00% 4.00% 4.00%
Rate of compensation increase 4.50% 5.00% 4.50% 5.00%
Cost trend of covered health-care charges -- -- 7.00%(1) 7.25%(1)

CHANGE IN PROJECTED BENEFIT OBLIGATION:
Net obligation at January 1 $ 448 $ 477 $ 45 $ 49
Service cost 16 13 1 1
Interest cost 40 32 4 3
Plan amendments -- -- (7) --
Actuarial (gain) loss 62 4 9 (5)
Transfer of liability (2) 109 -- 11 --
Curtailments -- (7) -- --
Settlements -- 1 -- --
Special termination benefits -- 13 -- --
Benefits paid (62) (85) (3) (3)
--------------------------------------------
Net obligation at December 31 613 448 60 45
--------------------------------------------
CHANGE IN PLAN ASSETS:
Fair value of plan assets at January 1 465 604 24 22
Actual return on plan assets (53) (55) -- 1
Employer contributions -- -- 3 4
Transfer of assets (2) 118 1 4 --
Benefits paid (62) (85) (3) (3)
--------------------------------------------
Fair value of plan assets at December 31 468 465 28 24
--------------------------------------------
Plan assets net of obligation
at December 31 (145) 17 (32) (21)
Unrecognized net actuarial (gain) loss 79 (62) 6 (6)
Unrecognized prior service cost 11 13 (9) --
--------------------------------------------
Net recorded liability at December 31 $ (55) $ (32) $ (35) $ (27)
- -----------------------------------------------------------------------------------------
(1) Decreasing to ultimate trend of 6.50% in 2004.
(2) To reflect transfer of plan assets and liability from Sempra Energy.

The following table provides the amounts recognized on the Consolidated
Balance Sheets (under deferred credits and other liabilities) at
December 31:
Other
Pension Benefits Postretirement Benefits
-------------------------------------------
(Dollars in millions) 2002 2001 2002 2001
- -----------------------------------------------------------------------------------------
Accrued benefit cost $ (55) $ (32) $ (35) $ (27)
Additional minimum liability (52) -- -- --
Intangible asset 11 -- -- --
Accumulated other comprehensive
income, pretax 41 -- -- --
-------------------------------------------
Net recorded liability $ (55) $ (32) $ (35) $ (27)
- -----------------------------------------------------------------------------------------

61
ends:
Pension Benefits Other
Postretirement Benefits
(Dollars in millions) 2005 2004 2005 2004
CHANGE IN PROJECTED BENEFIT OBLIGATION:
Net obligation at January 1 $ 719 $ 662 $ 85 $ 76
Service cost 10 9 3 3
Interest cost 42 41 5 5
Plan amendments -- -- 52 --
Actuarial loss (gain) 33 40 (19 ) 6
Transfer of liability from Sempra Energy 35 28 2 --
Benefit payments (52 ) (61 ) (4 ) (5 )
Net obligation at December 31 787 719 124 85
CHANGE IN PLAN ASSETS:
Fair value of plan assets at January 1 569 538 39 34
Actual return on plan assets 44 65 2 2
Employer contributions 21 20 7 8
Transfer of assets from Sempra Energy 34 7 -- --
Benefit payments (52 ) (61 ) (4 ) (5 )
Fair value of plan assets at December 31 616 569 44 39
Benefit obligation, net of plan assets at December 31 (171 ) (150 ) (80 ) (46 )
Unrecognized net actuarial loss 138 94 1 19
Unrecognized prior service cost 4 7 46 (7 )
Net recorded liability at December 31 $ (29 ) $ (49 ) $ (33 ) $ (34 )
The assets and liabilities of the pension and other postretirement benefit plans are affected by changing market conditions as well as when actual plan experience is different than assumed. Such events result in gains and losses. Investment gains and losses are deferred and recognized in pension and postretirement benefit costs over a period of years. If, as of the beginning of a year, unrecognized net gain or loss exceeds 10 percent of the greater of the projected benefit obligation or the market-related value of plan assets, the excess is amortized over the average remaining service period of active participants. The 10-percent corridor accounting method helpsmitigate volatility of net periodic costs from year to year.
The net liability is recorded on the Consolidated Balance Sheets as follows:
Pension Benefits Other
Postretirement Benefits
(Dollars in millions) 2005 2004 2005 2004
Prepaid benefit cost $ 4 $ 6 $ -- $ --
Accrued benefit cost (33 ) (55 ) (33 ) (34 )
Additional minimum liability (128 ) (90 ) -- --
Intangible asset 5 6 -- --
Regulatory asset 99 62 -- --
Accumulated other comprehensive
income (pre-tax) 24 22 -- --
Net recorded liability $ (29 ) $ (49 ) $ (33 ) $ (34 )
At December 31, 2005 and 2004, the company had an unfunded and a funded pension plan. The funded plan had benefit obligations in excess of its plan assets. The following table provides information for the funded plan at December 31:
(Dollars in millions) 2005 2004
Projected benefit obligation $ 757 $ 694
Accumulated benefit obligation $ 752 $ 692
Fair value of plan assets $ 616 $ 569
The following table provides the components of net periodic benefit costcosts (income) for the plans:

Other
(Dollars in millions) Pension Benefits Postretirement Benefits
---------------------------------------------------
Years ended December 31 2002 2001 2000 2002 2001 2000
- -----------------------------------------------------------------------------------------

Service cost $ 16 $ 13 $ 10 $ 1 $ 1 $ 1
Interest cost 40 32 36 4 3 3
Expected return on assets (43) (42) (57) (1) (1) (1)
Amortization of:
Transition obligation -- -- -- 1 2 2
Prior service cost 2 3 3 (1) -- --
Actuarial (gain) loss -- (7) (17) -- -- --
Special termination benefits -- 13 5 -- -- 1
Curtailment cost -- 1 -- -- 1 --
Settlement credit -- (19) -- -- -- --
Regulatory adjustment -- -- -- 1 1 (2)
--------------------------------------------------
Total net periodic benefit cost
(income) $ 15 $ (6) $ (20) $ 5 $ 7 $ 4
- -----------------------------------------------------------------------------------------
years ended December 31:
Pension Benefits Other
Postretirement Benefits
(Dollars in millions) 2005 2004 2003 2005 2004 2003
Service cost $ 10 $ 9 $ 14 $ 3 $ 3 $ 2
Interest cost 42 41 40 5 5 4
Expected return on assets (44 ) (40 ) (33 ) (2 ) (3 ) (1 )
Amortization of:
Transition obligation -- -- -- -- -- 1
Prior service cost 3 2 3 (1 ) (1 ) (1 )
Actuarial loss 1 1 2 1 1 1
Regulatory adjustment 11 (55 ) -- 1 (8 ) --
Transfer of retirees 12 -- -- (1 )
Total net periodic benefit cost (income) $ 35 $ (42 ) $ 26 $ 6 $ (3 ) $ 6
The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) was enacted in December of 2003. The Act establishes a prescription drug benefit under Medicare (Medicare Part D) and a tax-exempt federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that actuarially is at least equivalent to Medicare Part D. The company and its actuarial advisors determined that benefits provided to certain participants actuarially will be at least equivalent to Medicare Part D, and, accordingly, the company expects to be entitled to a tax-exempt subsidy that reduces the company's accumulated postretirement benefit obligation under the plan at January 1, 2005 and the net postretirement benefit cost for 2005 by immaterial amounts.
The significant assumptions related to the company's pension and other postretirement benefit plans are as follows:
Pension Benefits Other
Postretirement Benefits
2005 2004 2005 2004
WEIGHTED-AVERAGE ASSUMPTIONS USED
TO DETERMINE BENEFIT OBLIGATION
AS OF DECEMBER 31:
Discount rate 5.50% 5.66% 5.60% 5.66%
Rate of compensation increase 4.50% 4.50% 4.50% 4.50%
WEIGHTED-AVERAGE ASSUMPTIONS USED
TO DETERMINE NET PERIODIC BENEFIT
COSTS FOR YEARS ENDED DECEMBER 31:
Discount rate 5.66% 6.00% 5.66% 6.00%
Expected return on plan assets 7.50% 7.50% 4.61% 4.76%
Rate of compensation increase 4.50% 4.50% 4.50% 4.50%
The company utilizes a bond-pricing model that is tailored to the attributes of its pension and other postretirement plans to determine the appropriate discount rate to use for its benefit plans.
The expected long-term rate of return on plan assets is derived from historical returns for broad asset classes consistent with expectations from a variety of sources, including pension consultants and investment advisors.
2005 2004
ASSUMED HEALTH CARE COST
TREND RATES AT DECEMBER 31:
Health-care cost trend rate 9.78 % * 19.00 % *
Rate to which the cost trend rate is assumed to
decline (the ultimate trend) 5.50 % 5.50 %
Year that the rate reaches the ultimate trend 2008 2008
* This is the weighted average of the increases for the company's health plans. The rate for these plans ranged from 8.50% to 10% in 2005 and from 10% to 20% in 2004.
Assumed health-care cost trend rates have a significant effect on the amounts reported for the health-care plans.plan costs. A one-percent change in assumed health-care cost trend rates would have the following effects:

- -----------------------------------------------------------------------
(Dollars
(Dollars in millions) 1% Increase 1% Decrease
Effect on total of service and interest cost components of net
periodic postretirement health-care benefit cost $ 1 $ (1 )
Effect on the health-care component of the accumulated other
postretirement benefit obligation $ 7 $ (6 )
Pension Plan Investment Strategy
The asset allocation for Sempra Energy's pension trust (which includes the company's pension plan) at December 31, 2005 and 2004 and the target allocation for 2006 by asset categories are as follows:
Target
Allocation Percentage of Plan
Assets at December 31,
Asset Category 2006 2005 2004
U.S. Equity 45 % 44 % 45 %
Foreign Equity 25 27 32
Fixed Income 30 29 23
Total 100 % 100 % 100 %
The company's investment strategy is to stay fully invested at all times and maintain its strategic asset allocation, keeping the investment structure relatively simple. The equity portfolio is balanced to maintain risk characteristics similar to the Morgan Stanley Capital International (MSCI) 2500 index with respect to industry and sector exposures and market capitalization. The foreign equity portfolios are managed to track the MSCI Europe, Pacific Rim and Emerging Markets indexes. Bond portfolios are managed with respect to the Lehman Aggregate Bond Index and Lehman Long Government Credit Bond Index. The plan does not invest in millions) 1% Increase 1% Decrease
- -----------------------------------------------------------------------
Effect on totalsecurities of serviceSempra Energy.
Investment Strategy for Postretirement Health Plans
The asset allocation for the company's postretirement health plans at December 31, 2005 and interest cost
components of net periodic2004 and the target allocation for 2006 by asset categories are as follows:
Target
Allocation Percentage of Plan
Assets at December 31,
Asset Category 2006 2005 2004
U.S. Equity 25 % 23 % 25 %
Foreign Equity 5 6 6
Fixed Income 70 71 69
Total 100 % 100 % 100 %
The company's postretirement health-care benefit cost $ -- $ --

Effect onhealth plans that are not included in the health-care componentpension trust (shown above) pay premiums to health maintenance organization and point-of-service plans from company and participant contributions. The company's investment strategy is to match the long-term growth rate of the accumulatedliability primarily through the use of tax-exempt California municipal bonds.
Future Payments
The company expects to contribute $1 million to the pension plan and $15 million to its other postretirement benefit obligation $ 3 $ (2)
- -----------------------------------------------------------------------

plans in 2006.
The following table reflects the total benefits expected to be paid for the next 10 years to current employees and retirees from the plans or from the company's assets, including both the company's share of the benefit cost and, where applicable, the participants' share of the costs, which is funded pension plan had plan assets less than accumulated
benefit obligations. by participant contributions to the plans.
Pension Benefits Other
Postretirement Benefits
(Dollars in millions)
2006 $ 54 $ 7
2007 $ 56 $ 8
2008 $ 61 $ 8
2009 $ 62 $ 9
2010 $ 64 $ 9
2011-2015 $ 347 $ 54
The projected benefit obligation and accumulated
benefit obligation were $613 million and $575 million, respectively,expected future Medicare Part D subsidy payments are as of December 31, 2002, and $448 million and $442 million, respectively,
as of December 31, 2001.

The company maintains dedicated assets in support of its Supplemental
Executive Retirement Plan.

Other postretirement benefits include retiree life insurance and
medical benefits for retirees and their spouses.

follows:
(Dollars in millions)
2006-2010 $ 2
2011-2015 $ 4
Savings Plans

Plan
The company offers a trusteed savings plans, administered by plan trustees, to all eligible employees. Eligibility to participate in the plansplan is immediate for salary deferrals. EmployeesSubject to plan provisions, employees may contribute subject to

plan provisions, from one percent to 25 percent of their regular earnings.earnings, beginning with the start of employment. After one year of each employee's completed service, the company begins to make matching contributions. Employer contributions are equal to 50 percent of the first 6 percent of eligible base salary contributed by employees and, if certain company goals are met, an additional amount related to incentive compensation payments.
Employer contributions are initially invested in Sempra Energy common stock and must remain so invested
until termination of employment. Atbut may be transferred by the direction of the employees, the
employees'employee into other investments. Employee contributions are invested in Sempra Energy stock, mutual funds, or institutional trusts.trusts (the same investments to which employees may direct the employer contributions) as elected by the employee. Company contributions to the savings plansplan were $7$11 million in 2002, $5 million2005, $10million in 20012004 and $5 million$8million in 2000.

Employee Stock Ownership Plan

All contributions to the Trust are made by the company; there are no
contributions made by the participants.

As the company makes contributions to the ESOP, the ESOP debt service
is paid and shares are released in proportion to the total expected
debt service. Compensation expense is charged and equity is credited
for the market value of the shares released. Income tax deductions are
based on the cost of the shares. Dividends on unallocated shares are
used to pay debt service and are applied against the liability. The
Trust held 2.6 million shares and 2.7 million shares of Sempra Energy
common stock, with fair values of $61.0 million and $65.9 million, at
December 31, 2002 and 2001, respectively.

2003.
NOTE 7.6. STOCK-BASED COMPENSATION
Sempra Energy has stock-based compensation plans intended to align employee and shareholder objectives related to the long-term growth of the company. The plans permit a wide variety of stock-based awards, including nonqualified stock options, incentive stock options, restricted stock, stock appreciation rights, performance awards, stock payments and dividend equivalents.
In 1995, SFAS 123 "Accounting for Stock-Based Compensation," was issued. It encouragesencouraged a fair-value-based method of accounting for stock-based compensation. As permitted by SFAS 123, Sempra Energy and its subsidiaries adopted only its disclosure requirements and continuecontinued to account for stock-based compensation in accordance with the provisions of Accounting Principles Board Opinion 25, "Accounting for
Stock Issued to Employees." See additional discussionAPBO 25. The issuance of SFAS 148,123R will require the amendmentcompany to begin accelerated recognition of stock-based compensation expense for participants who are eligible for retirement-related vesting, beginning in 2006. Discussion of SFAS 123,123R (a revision of SFAS 123) is provided in Note 1.

The
Sempra Energy subsidiaries record an expense for the plans to the extent that subsidiary employees participate in the plans or that the subsidiaries are allocated a portion of Sempra Energy's costs of the plans. SDG&E recorded expenses of $1$12 million, $2$9 million and $1$7 million in 2002,
20012005, 2004 and 2000,2003, respectively.

63
NOTE 8.7. FINANCIAL INSTRUMENTS
Fair Value Hedges
The company periodically enters into interest-rate swap agreements to moderate its exposure to interest-rate changes and to lower its overall cost of borrowing. The company's interest-rate swaps are discussed in Note 2.
Cash Flow Hedges
The company's interest-rate swaps to hedge cash flows are also discussed in Note 2.
Energy Contracts
At SDG&E, the use of derivative instruments is subject to certain limitations imposed by company policy and regulatory requirements. These instruments allow the company to estimate with greater certainty the effective prices to be received by the company and the prices to be charged to customers. The company records transactions for natural gas and electric energy contracts in Cost of Natural Gas and in Cost of Electric Fuel and Purchased Power, respectively,in the Statements of Consolidated Income. Unrealized gain and losses related to these derivatives have offsetting regulatory assets and liabilities on the Consolidated Balance Sheets to the extent derivative gains and losses will be recoverable from or payable to customers in future rates.
Fair Value of Financial Instruments
The fair values of certain of the company's financial instruments (cash, temporary investments, notes receivable and customer deposits) approximate thetheir carrying amounts. The following table provides the carrying amounts and fair values of the remaining financial instruments at December 31:
(Dollars in millions) 2002 2001
- -------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- -------------------------------------------------------------------------------

First-mortgage bonds $ 636 $ 689 $ 674 $ 704
Rate-reduction bonds 329 357 395 411
Other long-term debt 254 273 254 265
-------- -------- -------- --------
Total long-term debt $1,219 $1,319 $1,323 $1,380
- -------------------------------------------------------------------------------
Preferred stock $ 104 $ 98 $ 104 $ 98
- -------------------------------------------------------------------------------
2005 2004
Carrying Fair Carrying Fair
(Dollars in millions) Amount Value Amount Value
Total long-term debt $ 1,522 $ 1,544 $ 1,088 $ 1,179
Preferred stock of subsidiaries $ 98 * $ 96 $ 100 * $ 100
* $19 million and $21 million in 2005 and 2004, respectively, of mandatorily redeemable preferred stock is included in Deferred Credits and Other Liabilities and in Other Current Liabilities on the Consolidated Balance Sheets.
The fair values of long-term debt anddebtand preferred stock were estimatedare based on their quoted market prices or quoted market prices for them or for similar issues.

Accounting for Derivative Instrumentssecurities.
NOTE 8. PREFERRED STOCK
Call/
Redemption December 31,
Price 2005 2004
Not subject to mandatory redemption: (in millions)
$20 par value, authorized 1,375,000 shares:
5% Series, 375,000 shares outstanding $ 24.00 $ 8 $ 8
4.5% Series, 300,000 shares outstanding $ 21.20 6 6
4.4% Series, 325,000 shares outstanding $ 21.00 7 7
4.6% Series, 373,770 shares outstanding $ 20.25 7 7
Without par value:
$1.70 Series, 1,400,000 shares outstanding $ 25.85 35 35
$1.82 Series, 640,000 shares outstanding $ 26.00 16 16
Total $ 79 $ 79
Subject to mandatory redemption:
Without par value: $1.7625 Series, 750,000 and 850,000
shares outstanding at December 31, 2005
and December 31, 2004, respectively $ 25.00 $ 19* $ 21*
* At December 31, 2005 and Hedging Activities

SFAS 133 "Accounting for Derivative Instruments2004, $16 million and Hedging
Activities," as amended by SFAS 138, "Accounting for Certain Derivative
Instruments$19 million, respectively, were included in Deferred Credits and Certain Hedging Activities" recognizes all derivatives
as either assets or liabilitiesOther Liabilities, and $3 million and 2 million, respectively, were included in the statement of financial position,
measures those instruments at fair value and recognizes changes in the
fair value of derivatives in earnings in the period of change unless
the derivative qualifies as an effective hedge that offsets certain
exposure.

The company utilizes derivative financial instruments to reduce its
exposure to unfavorable changes in commodity prices, which are subject
to significant and often volatile fluctuation. Derivative financial
instruments include futures, forwards, swaps, options and long-term
delivery contracts. These contracts allow the company to predict with
greater certainty the effective prices to be received by the company
and the prices to be charged to its customers. Since adoption of SFAS
133 on January 1, 2001, the company classifies its forward contracts as
follows:

Normal Purchase and Sales: These contracts generally are long-term
contracts that are settled by physical delivery and, therefore, are
eligible for the normal purchases and sales exception of SFAS 133. The
contracts are accounted for at historical cost with gains and losses
reflected in the Statements of Consolidated Income at the contract
settlement date.

Electric and Natural Gas Purchases and Sales: The unrealized gains and
losses related to these forward contracts are reflectedOther Current Liabilities on the Consolidated Balance Sheets as regulatory assets and liabilities to the
extent derivative gains and losses will be recoverable or payable in
future rates. If gains and losses are not recoverable or payable
through future rates, the company applies hedge accounting if certain
criteria are met. When a contract no longer meets the requirements of
SFAS 133, the unrealized gains and losses will be amortized over the
remaining contract life.

In instances where hedge accounting is applied to derivatives, cash
flow hedge accounting is elected and, accordingly, changes in fair
values of the derivatives are included in other comprehensive income,
but not reflected in the Statements of Consolidated Income until the
corresponding hedged transaction is settled. The effect on other
comprehensive income for the years ended December 31, 2002 and 2001 was
not material. In instances where derivatives do not qualify for hedge
accounting, gains and losses are recorded in the Statements of
Consolidated Income.

The following were recorded in the Consolidated Balance Sheets at
December 31:

(Dollars in millions) 2002 2001
- -----------------------------------------------------------------------
Fixed-priced contracts and other derivatives:
Current assets $ 2 $ 1
----- -----
Total 2 1
----- -----
Current liabilities 59 84
Noncurrent liabilities 579 634
----- -----
Total 638 718
----- -----
Net liabilities $ 636 $ 717
===== =====
Regulatory assets and liabilities:
Current regulatory assets $ 59 $ 83
Noncurrent regulatory assets 579 634
----- -----
Total 638 717
----- -----

Current regulatory liabilities 2 1
----- -----
Net regulatory assets $ 636 $ 716
===== =====
- -----------------------------------------------------------------------

$1 million in income and $1 million in losses were recorded in 2002 and
2001, respectively, in "other income - net" in the Statements of
Consolidated Income.

Market Risk

The company's policy is to use derivative instruments to manage
exposure to fluctuations in interest rates, foreign-currency exchange
rates and prices. Transactions involving these instruments are with
major exchanges and other firms believed to be credit-worthy. The use
of these instruments exposes the company to market and credit risk
which may at times be concentrated with certain counterparties,
although counterparty nonperformance is not anticipated.

Interest-Rate Risk Management

The company periodically enters into interest-rate swap agreements to
moderate exposure to interest-rate changes and to lower the overall
cost of borrowing.

SDG&E had an interest-rate swap agreement that matured in December 2002
and effectively fixed the interest rate on $45 million of variable-rate
underlying debt at 5.42 percent. This floating-to-fixed-rate swap did
not qualify for hedge accounting and, therefore, the gains and losses
associated with the change in fair value were recorded in the
Statements of Consolidated Income. The effect on income was a $1
million gain and a $1 million loss for the years ended December 31,
2002 and 2001, respectively. Although this financial instrument did not
meet the hedge accounting criteria of SFAS 133, it was effective in
achieving the risk management objectives for which it was intended.

Energy Derivatives

SDG&E utilizes derivative instruments to reduce its exposure to
unfavorable changes in energy prices, which are subject to significant
and often volatile fluctuation. Derivative instruments are comprised of
futures, forwards, swaps, options and long-term delivery contracts.
These contracts allow SDG&E to predict with greater certainty the
effective prices to be received and the prices to be charged to their
customers. See Note 1 for discussion of how these derivatives are
classified under SFAS 133.

Energy Contracts

SDG&E records natural gas and electric energy contracts in "Cost of
natural gas distributed" and "Electric fuel and net purchased power,"
respectively, in the Statements of Consolidated Income. For open
contracts not expected to result in physical delivery, changes in
market value of the contracts are recorded in these accounts during the
period the contracts are open, with an offsetting entry to a regulatory
asset or liability. The majority of the company's contracts result in
physical delivery.

There was no impact on the Statements of Consolidated Income for
changes in the fair value of derivative instruments, other than the $1
million gain and $1 million loss for the years ended December 31, 2002
and 2001, respectively, from the interest-rate swap noted above.

NOTE 9. PREFERRED STOCK

- ----------------------------------------------------------------------------------
Call December 31,
(Dollars in millions, except call price) Price 2002 2001
- ----------------------------------------------------------------------------------

Not Subject to mandatory redemption
$20 par value, authorized 1,375,000 shares:
5% Series, 375,000 shares outstanding $ 24.00 $ 8 $ 8
4.5% Series, 300,000 shares outstanding $ 21.20 6 6
4.4% Series, 325,000 shares outstanding $ 21.00 7 7
4.6% Series, 373,770 shares outstanding $ 20.25 7 7
Without par value:
$1.70 Series, 1,400,000 shares outstanding $ 25.85 35 35
$1.82 Series, 640,000 shares outstanding $ 26.00 16 16
-----------------
Total $ 79 $ 79
-----------------
Subject to mandatory redemption
Without par value, $1.7625 Series, 1,000,000
shares outstanding $ 25.00 $ 25 $ 25
- ----------------------------------------------------------------------------------
Sheets.
All series of SDG&E's preferred stock have cumulative preferences as to dividends. The $20 par value preferred stock has two votes per share on matters being voted upon by shareholders of SDG&E and a liquidation value at par, whereas thepar. The no-par-value preferred stock is nonvoting and has a liquidation value of $25 per share plus any unpaid dividends. SDG&E is authorized to issue 10,000,000 shares of no-par-value preferred stock (both subject to and not subject to mandatory redemption). All series are callable at December 31, 2002, except for
the $1.7625 and $1.70 Series (callable in January and October 2003,
respectively).callable. The $1.7625 Series has a sinking fund requirement to redeem 50,000 shares at $25 per year from 2003 toshare in each of 2006 and 2007; theall remaining 750,000 shares must be redeemed in 2008. On each of January 15, 2005 and January 15, 2006, SDG&E redeemed 100,000 shares.
NOTE 10.9. ELECTRIC INDUSTRY REGULATION
Background

Supply/demand imbalances and a number of other factors resulted in
abnormally high electric-commodity prices beginning in mid-2000 and
continuing into 2001. This caused SDG&E's customer bills
One legislative response to be
substantially higher than normal. These higher prices were initially
passed through to customers and resulted in bills that in most cases
were double or triple those from 1999 and early 2000. This resulted in
several legislative and regulatory responses, including AB 265, enacted
in Septemberthe 2000 and in effect through December 31, 2002. AB 265
imposed a ceiling of 6.5 cents/kWh on the cost of the electric
commodity that SDG&E could pass on to its small-usage customers on a
current basis, effective retroactive to June 1, 2000.

SDG&E accumulated the amount that it paid for electricity in excess of
the ceiling rate in an interest-bearing balancing account (the AB 265
undercollection). It increased to approximately $750 million in the

first quarter of- 2001 and decreased to $392 million at December 31,
2001 and $215 million at December 31, 2002 (included in current
"regulatory balancing accounts - net").

In June 2001, representatives of California Governor Davis, the DWR,
Sempra Energy and SDG&E entered into a Memorandum of Understanding
(MOU) contemplating the implementation of a series of transactions and
regulatory settlements and actions to resolve many of the issues
affecting SDG&E and its customers arising out of the California energy
crisis. During 2001, implementation of some of the MOU's provisions
(with the rest no longer likely to be implemented) resulted in a
partial reduction of the AB 265 undercollection (see above). In
addition, the DWR's procurement of SDG&E's full net short position
during 2001 and 2002 (see below)power crisis resulted in the cessationpurchase by the 'DWR of growth in
the AB 265 undercollection.

The Department of Water Resources and Power Procurement

In February 2001, through the passage of Assembly Bill 1, Chapter 4,
Statutes of the 2001 First Extraordinary Session (AB X1), the DWR began
to purchase power from generators and marketers and entered into long-
term contracts for the purchase of a substantial portion of the state's power requirements that is served by the IOUs. SDG&E and the DWR had an
agreement under which the DWR purchased the net short supply for
bundled SDG&E customers through December 31, 2002.

Since earlyof California's electricity users. In 2001, the DWR has procuredentered into long-term contracts with suppliersto provide power for the utility procurement customers of each of the California IOUs and theinvestor-owned utilities (IOUs). The CPUC has established the allocation of the power and the
related costits administrative responsibility, including collection of power contract costs from utility customers, among the IOUs. Beginning on January 1, 2003, the IOUs resumed responsibility for electric commodity procurement above their allocated share of the DWR's long-term contracts.
Department of Water Resources
The DWR operating agreement with SDG&E, approved by the CPUC, provides that power.SDG&E is acting as a limited agent on behalf of the DWR in undertaking energy sales and natural gas procurement functions under the DWR contracts allocated to SDG&E's allocation resultscustomers. Legal and financial responsibility associated with these activities continues to reside with the DWR. Therefore, commodity costs associated with long-term contracts allocated to SDG&E from the DWR (and the revenues to recover those costs) are not included in its overall rates being comparablethe Statements of Consolidated Income.
In October 2003, the CPUC initiated a proceeding to thoseconsider a permanent methodology for allocating the DWR's revenue requirement beginning in 2004 through the remaining life of the other two California electric IOUs,DWR contracts (2013). On June 30, 2005, the CPUC changed its prior decision and assigned SDG&E customers $422 million of the costs (instead of the $790 million pursuant to the prior decision). Such allocation does not affect SDG&E's net income, but does affect its customers' commodity rates. In August 2005, Southern California Edison (Edison), The Utility Reform Network and Pacific Gas and Electric (PG&E).the California Large Energy Consumers Association(collectively the Parties) filed a Petition for Modification, not disputing the allocation of the DWR decision, but rather the schedule for reallocation. On December 17, 2002,1, 2005, the CPUC issuedapproved a decision allocatingthat denied the costParties' petition to modify.
In December 2005, the CPUC approved a draft decision reallocating one of the DWR's revenue
requirement for its 2003state's DWR power purchases.contracts (Williams Energy "Power D") from SDG&E to Edison. The decision poolswas modified to make the total
fixed costs of the DWR's contracts and allocates these costs among the
IOUs on the basis of the quantity of the energy supplied to each IOU
from the contracts. Variable costs related to the energy supplied under
each contract go to the IOU assigned each contract. This decision
allocates $643 million to SDG&E and will be handled within existing
utility rates. That amount is currently under additional review as the
DWR revenue requirement was reduced when the IOUs began power
procurement onreallocation effective January 1, 2003 (see discussion below).

The CPUC's objective was2007, allowing SDG&E an additional year to plan for and acquire the necessary replacement resources. In the same decision, the CPUC rejected Edison's request to reallocate administration of Sempra Generation's DWR contract to SDG&E.
Power Procurement and Resource Planning
In 2001, the CPUC directed the IOUs to take theresume electric commodity procurement function
back from the DWR by the beginning of 2003. On September 19, 2002, the
CPUC issued a decision on how the power from the long-term contracts
signed by the DWR should be allocated to the customers of each of the
IOUs for purposes of determining the amount of additional power each
utility is required to procure in 2003 and thereafter to fulfill its
resource needs. The reasonableness of the IOUs' administration and
dispatch of the allocated contracts will be reviewed by the CPUC in an
annual proceeding. AB 57, signed by California Governor Davis on
September 24, 2002, requires the CPUC to make this determination, and
to establish procedures that will allow the IOUs to recover their
electric procurement costs in a timely fashion without the need for
retrospective reasonableness reviews. SDG&E believes that the return to

the procurement function in accordance with AB 57 will have no adverse
impact on its financial position or results of operations.

On August 22, 2002, the CPUC issued a decision that authorized the
California IOUs to begin interim procurement of power to cover their net short energy requirements starting on January 1, 2003. The net
short is the difference between the amount of electricity needed to
cover a utility's customer demand and the power provided by owned
generation and existing contracts, including the long-term power
contracts allocated to the customers of each IOU by the DWR (see
above). The IOUs are authorized to enter into contracts of up to five
years for power from traditional sources, and up to 15 years for power
from renewable sources. SDG&E is required to purchase approximately 10
percent of its customer requirements in 2003, based on the allocation
of the DWR power approved by the CPUC on December 17, 2002.

On October 24, 2002, the CPUC issued a decision in the Electric
Procurement proceeding that officially directs the resumption of the
electric commodity procurement function by IOUs by January 1, 2003 and begins the implementation of recentalso implemented legislation regarding procurement and renewables portfolio standards addressed in AB 57 and Senate Bill
1078. The decisionstandards. In addition, the CPUC established a process for review and approval of the utilities' updated 2003long-term resource and procurement plans, which is intended to identify forecasted needs for generation and transmission resources within a utility's service territory to support transmission grid reliability and to serve customers.
In June 2004, the CPUC approved a request by SDG&E to enter into new electric resource contracts to meet its short-term and long-term (20-year) procurement plans.grid reliability needs, including the ten-year 573-Megawatt (MW) Otay Mesa Power Purchase Agreement (OMPPA) with Calpine Corp. (Calpine). The OMPPA was to begin January 1, 2008. In June 2005, the CPUC approved SDG&E's 2003 procurement plan in December 2002 andgranted limited rehearing of its approval of the long-term planOMPPA and on February 16, 2005, the CPUC re-affirmed its approval of the OMPPA. However, several conditions precedent required by the OMPPA have not yet been satisfied. In lieu of the OMPPA, SDG&E and Calpine have entered into a non-binding letter of intent contemplating the negotiation of a definitive agreement for the sale of the Otay Mesa power plant to SDG&E. Any final, definitive agreement would require the approval of the CPUC and the bankruptcy court having jurisdiction over the Calpine case.
In July 2005, the CPUC also approved SDG&E's request for the construction (CPCN application) of $209 million in transmission facilities needed, in part, to provide full dispatchability of the Otay Mesa generation project. SDG&E has commenced construction of the OMPPA transmission upgrade project, spending $8 million through December 31, 2005.
The CPUC requires SDG&E to achieve a 20% renewable energy portfolio by 2010. SDG&E has entered into contracts with four developers for the purchase of energy from projects scheduled to begin operation between 2007 and 2016. SDG&E has entered into a 20-year contract to develop a 900-MW solar project in the Imperial Valley area of California. The first phase would provide 300 MW of power beginning in 2008 - 2010. The second phase would provide an option for an additional 300 MW beginning in 2010 - 2012. The third phase would provide the right of first refusal for another 300 MW of power beginning after 2012. The first two phases received CPUC approval in December 2005. SDG&E has also entered into a 20-year contract for development of a 205.5-MW wind project scheduled to begin in 2007 - 2008. The projects are expected to raise SDG&E's overall renewable portfolio to 13.3 % in 2010. The projects are contingent upon successful completion of new transmission lines.
San Onofre Nuclear Generating Station (SONGS)
On May 5, 2005, the CPUC granted SDG&E a rehearing to resolve what SDG&E has contended was a computational error in the CPUC's setting of revenue for SDG&E's share of the operating costs of SONGS. Any adjustment would be retroactive to January 1, 2004. If SDG&E is fully successful, its revenue for the period in which the rehearing is concluded would be increased by $10 million for each of 2004 and 2005. Final resolution is expected during 2003. The CPUC has
authorizedin the utilities to use derivatives to manage procurement risk
and to acquire a varietyfirst half of resource types including utility ownership,
conventional generation, distributed generation, self generation,
demand side resources, transmission and renewables. A semiannual cost
review and rate revision mechanism is established, and a trigger is
established for more frequent changes if undercollected commodity costs
exceed five percent of annual, non-DWR generation revenues, to provide
for timely recovery of any undercollections.

The Electric Procurement decision also described above directed each
IOU to procure from renewable sources at least one percent of its 2003
total energy sales and an additional one percent of energy sales each
year thereafter, until a 20-percent renewable resources portfolio is
achieved by the year 2017. SDG&E has contracted to procure
approximately four percent of its 2003 total energy sales from
renewable sources and, pursuant to a December 2002 CPUC resolution, may
"bank" or credit toward future years' compliance any excess over its
one-percent requirement.

The CPUC has placed a moratorium on the IOUs' purchasing electricity
from their affiliates for the earlier of two years or until the CPUC
completes a rulemaking on this matter. SDG&E believes that this
moratorium will have no adverse impact on its financial position or
results of operations. During 2002, SDG&E's purchases of electricity
from its affiliate Sempra Energy Trading were less than one percent of
total electricity purchases.

DWR Operating and Servicing Agreements

On December 19, 2002, the CPUC issued an Operating Order setting the
terms by which the IOUs will administer the DWR contracts allocated to
the customers of each of the utilities (see above). The DWR continues

to bear the credit risk on the contracts and the IOUs have assumed the
administrative burden of the contracts. The order requires the IOUs to
take financial responsibility for acquiring natural gas supplies for
the generation facilities that are subject to the DWR contracts.

SDG&E currently has pending an operating and servicing agreement signed
by the DWR and SDG&E which, if approved by the CPUC, will supercede the
CPUC's operating order referred to above. The pending agreement will
clearly delineate that the natural gas procurement and associated risk
will continue to reside with the DWR.

Effect on Customer Rates

On December 19, 2002, the CPUC issued a decision denying SDG&E's
application for a rate surcharge to expedite recovery of the AB 265
undercollection. However, even at current rates and allocation of the
resulting revenues between the DWR and SDG&E, the balance is expected
to be completely recovered before2006.
With the end of 2005. Alsothe Incremental Cost Incentive Mechanism in 2003, SDG&E's SONGS ratebase restarted at issue is the
ownership of certain power sale profits stemming from intermediate term
purchase power contracts entered into by SDG&E during the early stages
of California's electric utility industry restructuring. The company
believes that all profits associated with these contracts properly are
for the benefit of SDG&E shareholders rather than customers, whereas
the CPUC asserted that all the profits should accrue to the benefit of
customers. Accordingly, SDG&E challenged the CPUC's disallowance of
profits from the contracts in both the California Court of Appeals and
in Federal District Court.

These court proceedings have been held in abeyance pending the CPUC's
consideration of various other proposed settlements. On December 19,
2002, the CPUC rendered a 3-to-2 decision approving the June 2002
proposed settlement, previously described in the company's Quarterly
Report$0 on Form 10-Q for the quarter ended September 30, 2002, that
divides the profits from these contracts, $199 million for SDG&E
customers and $173 million for SDG&E shareholders. Of the $199 million
in profits allocated to customers, $175 million had already been
credited to ratepayers in 2001. The remaining $24 million was applied
as a balancing account transfer that reduced the AB 265 balancing
account in December 2002. The profits allocated to customers reduce
SDG&E's AB 265 undercollection, but do not adversely affect SDG&E's
financial position, liquidity or results of operations. The term of a
commissioner who voted to approve the settlement has expired, and a new
commissioner has been appointed. On January 29, 2003, the CPUC's Office
of Ratepayer Advocates (ORA), the City of San Diego and the Utility
Consumers' Action Network, a consumer-advocacy group, filed requests
for a CPUC rehearing of the decision. On February 13, 2003, the company
filed its opposition to rehearing of the decision. Parties requesting a
rehearing and parties to any rehearing may also appeal the CPUC's final
decision to the California appellate courts.

Direct Access

On March 21, 2002, the CPUC affirmed its decision prohibiting new
direct access (DA) contracts after September 20, 2001, but rejected a
proposal to make the prohibition retroactive to July 1, 2001. Contracts
in place as of September 20, 2001 may be renewed or assigned to new
parties. On November 7, 2002, the CPUC issued a decision adopting DA

exit fees with an interim cap of 2.7 cents per kWh, effective January 1, 2003. This decision will have no effect2004 and, therefore, SDG&E's earnings from SONGS are now generally limited to a return on SDG&E's cash flows or
resultsnew additions to ratebase.
In 2004 Edison, the operator of operations, because any shortfall dueSONGS, applied for CPUC approval to replace the cap onsteam generators at SONGS, stating that the exit
fees willwork needed to be funded by bundled customersdone in current rates. The CPUC is
conducting further proceedings to determine whether, or to what extent,
the interim cap should be revised after July 1, 2003.

SONGS

Operating costs of SONGS2009 and 2010 for Units 2 and 3, including nuclear fuelrespectively, and related financing costs, and incrementalwould require an estimated capital expenditures are
recovered through the ICIP mechanism which allows SDG&E to receive
approximately 4.4 cents per kilowatt-hour for SONGS generation. Any
differences between these costs and the incentive price affect net
income. For the year ended December 31, 2002, ICIP contributed $50expenditure of $680 million to SDG&E's net income. The CPUC has rejected an administrative
law judge's proposed decision to end ICIP prior to its December 31,
2003 scheduled expiration date. However, the CPUC has also denied the
previously approved market-based pricing for SONGS beginning in(in 2004 and insteaddollars). As provided for traditional rate-making treatment, under whichin the SONGS ratebase would begin at zero, essentially eliminating
earnings from SONGS until ratebase grows. The company has applied for
rehearing of this decision.

FERC Actions

The FERC is investigating prices chargedOperating Agreement, SDG&E elected not to buyersparticipate in the California PX
and ISO markets by various electric suppliers. It is seeking to
determinesteam generator replacement project, which triggered a dispute under the operating agreement over the extent to which individual sellers have yetSDG&E's ownership share and its related share of SONGS's output would be reduced from its existing 20% interest if SDG&E does not participate in the project. In February 2005, an arbitrator issued a decision that would result in SDG&E's ownership interest in SONGS and its related share of SONGS's output being reduced to be paidzero if SDG&E continues to decline to participate in the project.
SDG&E intervened in Edison's CPUC application and requested that the CPUC either deny Edison's application as premature, direct Edison to purchase the new steam generators but defer the replacement until it is warranted, or direct Edison to purchase SDG&E's share in the facility and offer back a long-term power purchase agreement in an amount equal to SDG&E's current share (430 MW). Hearings before the CPUC on Edison's application were completed in February 2005, and a final decision approving the steam generator project was issued on December 15, 2005. That decision sets cost recovery at a maximum cap of $782 million and requires a reasonableness review of all costs if total costs exceed $680 million. The decision also approves Edison's revised schedule, which provides for power supplied duringcompletion of the period of Octoberproject for Unit 2 2000 through June
20, 2001and Unit 3 by early 2010 and late 2010, respectively. To relinquish its ownership share and to estimateaddress the amountsarbitrator's decision, SDG&E is required to file by which individual buyersApril 14, 2006, an appl ication with the CPUC to determine the reasonableness of the transfer of all or part of SDG&E's share of SONGS to Edison, with a decision expected in 2007. The CPUC could require SDG&E to participate in the project and sellers paidretain a share of SONGS or SDG&E could elect to participate in the project and were paidretain its current 20-percent ownership share of SONGS. If SDG&E's ownership share of SONGS is reduced, SDG&E would seek to recover its net investment in SONGS made since January 1, 2004 ($86 million at December 31, 2005, including materials and supplies of $31 million) and any future SONGS investments made prior to the time the ownership reduction becomes effective, and a return on its investment in SONGS ratebase (including that portion of the $31 million that is transferred to plant by that time).
Spent Nuclear Fuel
SONGS owners have responsibility for the interim storage of spent nuclear fuel generated at SONGS until it is accepted by the Department of Energy (DOE) for final disposal. Spent nuclear fuel has been stored in the SONGS Units 1, 2 and 3 spent fuel pools and in the ISFSI. Movement of all spent fuel to the ISFSI was completed as of December 31, 2005, providing sufficient space for the Units 2 and 3 spent fuel pools to meet storage requirements through mid-2007 and mid-2008, respectively. The ISFSI has adequate storage capacity through 2022.
NOTE 10. OTHER REGULATORY MATTERS
Utility Ratemaking Incentive Awards
Performance-Based Regulation (PBR) consists of three primary components. The first is a mechanism to adjust rates in years between general rate cases or cost of service cases. It annually adjusts base rates from those of the prior year to provide for inflation based on the most recent Consumer Price Index (CPI) forecast, subject to minimum and maximum percentage increases that change annually.
The second component is a mechanism whereby any earnings in excess of competitive market prices.
Based on these estimates,those authorized plus a narrow band above that are shared with customers in varying degrees depending upon the FERC could find that individual net
buyers, such as SDG&E, are entitled to refunds and individual net
sellers are obliged to provide refunds. To the extent any such refunds
are actually realized by SDG&E, they would reduce SDG&E's rate-ceiling
balancing account. In December 2002, a FERC administrative law judge's
(ALJ) preliminary findings indicate that California owes power
suppliers $1.2 billion (the $3 billion that California still owes
energy companies less $1.8 billion the ALJ finds the energy companies
overcharged California). California is seeking $8.9 billion in refunds
and indicated it would appeal if the ALJ's findings are adopted. A FERC
decision is not expected before the second half of 2003. More recently,
FERC has launched an investigation into whether there was manipulation
of short-term energy prices in the West that resulted in unjust and
unreasonable long-term power sales contracts.

In addition, in February 2002 the CPUC and the California Electricity
Oversight Board petitioned the FERC to determine that the long-term
power contracts the DWR signed with energy companies during the heightamount of the energy crisis do not provide just and reasonable rates, and to
abrogate or reform the contracts. In April 2002, the FERC ordered
hearings on the complaints. additional earnings.
The order requires the complainants to
satisfy a "heavy" burden of proof to support a revision of the
contracts, and cited the FERC's long-standing policy to recognize the
sanctity of contracts, from which it has deviated only in "extreme
circumstances." In December 2002, a FERC administrative law judge held

formal hearings and in January 2003 issued a partial, initial decision
recommending that the validity of their contracts be determined under a
"public interest" standard that requires the complainants to satisfy a
significantly higher standard of review to invalidate the contracts
than would a just and reasonable standard. Final briefs were submitted
to the full FERC commission later in January with respect to the public
interest standard of review and the FERC has indicated that it expects
to issue a final decision by March 2003.

NOTE 11. OTHER REGULATORY MATTERS

Gas Industry Restructuring

In January 1998, the CPUC released a staff report initiating a project
to assess the current market and regulatory framework for California's
natural gas industry. In July 1999, after hearings, the CPUC issued a
decision stating which natural gas regulatory changes it found most
promising, encouraging parties to submit settlements addressing those
changes, and providing for further hearings if necessary.

On December 11, 2001, the CPUC issued a decision adopting muchthird component consists of a settlement that had been submitted in 2000 by SDG&E and approximately
30 other parties representing all segmentsseries of measures of utility performance. Generally, if performance is outside of a band around specified benchmarks, the natural gas industry
in Southern California, but opposed by some parties. The CPUC decision
adopts the following provisions: a system for shippers to hold firm,
tradable rights to capacity on SoCalGas' major natural gas transmission
lines; new balancing services, including separate core and noncore
balancing provisions; a reallocation among customer classes of the cost
of interstate pipeline capacity held by SoCalGas and an unbundling of
interstate capacity for natural gas marketers serving core customers;
and the elimination of noncore customers' option to obtain natural gas
procurement service from SDG&E. The CPUC modified the settlement to
provide increased protection against the exercise of market power by
persons who would acquire rights on the SoCalGas natural gas
transmission system. The CPUC also rejectedutility is rewarded or penalized certain aspects of the
settlement that would have provided more options for natural gas
marketers serving core customers.

During 2002 the California Utilities filed a proposed implementation
schedule and revised tariffs and rules required for implementation.
However, protests of these compliance filings were filed, and the CPUC
has not yet authorized implementation of most of the provisions of its
decision. On December 30, 2002, the CPUC deferred acting on a plan to
implement its decision.

SDG&E believes that implementation of the decision would make natural
gas service more reliable, more efficient and better tailored to meet
the needs of customers. The decision is not expected to adversely
affect SDG&E's earnings.

Cost of Service (COS) and Performance-Based Regulation (PBR)

To promote efficient operations and improved productivity and to move
away from reasonableness reviews and disallowances, the CPUC adopted
PBR for SDG&E effective in 1994 PBR has resulted in modification to the
general rate case and certain other regulatory proceedings for SDG&E.
Under PBR, regulators require future income potential to be tied to

achieving or exceeding specific performance and productivity goals,
rather than relying solely on expanding utility plant to increase
earnings.dollar amounts. The three areas that arehave been eligible for PBR rewards or penalties are operational incentives based on measurements of safety, reliability and customer satisfaction;service; demand-side management (DSM) rewards based on the effectiveness of the DSM programs; and natural gas procurement rewards.
These incentive rewards or penalties. As noted below, the latest Cost of Service proceeding established formula-based performance measures for customer service, safety and reliability.
PBR and DSM awards are not included in the company's earnings before they areuntil CPUC approval of the award is received. During 2005, the incentive rewards approved by the CPUC.

The COS and PBR cases forincluded in earnings consisted of $0.2 million related to SDG&E were filed on December 20, 2002. The
filings outline projected expenses (excluding the commodity cost of
electricity or&E's Year 11 (2003-2004) natural gas consumed by customers or expensesPBR.
In October, 2005, the CPUC approved the settlement agreement between the California Utilities and the CPUC's DRA, resolving all outstanding shareholder earnings claims associated with DSM, energy efficiency and low-income energy efficiency programs through various dates, depending on the program. The decision provides for programs such as low-income assistance)$73 million in awards, including interest, franchise fees, uncollectible amounts and revenue requirementsawards earned in prior years that had not yet then been requested. Approximately $37 million of the $73 million award was included in fourth quarter 2005 income.
In October 2005, the CPUC also approved $8.2 million in PBR incentive awards for 2004SDG&E's 2003 Distribution PBR performance report, relating to employee safety, customer service and electric reliability. This award is subject to refund in the event the current investigation of Edison's service quality incentive awards warrants a formulafurther investigation of PBR incentives for 2005 through 2008.other utilities, including SDG&E's&E. The CPUC's Consumer Protection and Safety Division is conducting an ongoing investigation of Edison's PBR incentive data reporting.
The cumulative amount of these awards that is subject to refund based on the outcome of the Border Price Investigation discussed in "Legal Proceedings" in Note 11 below is $8.5 million, the majority of which has been included in income.
Cost of Service
The California Utilities' proposed settlement of Phase II of their cost of service study
proposes increases in electricproceedings, addressing attrition allowances and natural gas base rate revenues of
$58.9 million and $21.6 million, respectively. The filings also
requested a continuance and expansion of PBR in terms of earnings
sharing and performance service standards that include both reward and
penalty provisions related to customer satisfaction, employee safety
and system reliability. The resulting new base rates are expected to be
effective on January 1, 2004. A CPUC decision is expected in late 2003.
SDG&E's in effect through December 31, 2003, at which time the
mechanism will be updated. That update will include, among other
things, a reexamination of SDG&E's reasonable costs of operation to be
allowed in rates.

An October 10, 2001 decision denied SDG&E's request to continue equal
sharing between ratepayers and shareholders of the estimated savings
for the PE/Enova merger as more fully discussed in Note 1 and, instead,
ordered that all of the estimated 2003 merger savings go to ratepayers.
This decision will adversely affect the company's net income by $11
million.

In August 2002, the CPUC issued a resolution approving SDG&E's 2000 PBR
report. The resolution approved SDG&E's request for a total net reward
of $11.7 million (pretax), as well as SDG&E's actual 2000 rate of
return (applicable only to electric distribution and natural gas
transportation) of 8.74 percent, which is below the authorized 8.75
percent. This results in no sharing of earnings in 2000 under the PBR
sharing mechanism. The financial results herein include the reward
during the third quarter of 2002.

During 2002, SDG&E filed its 2001 PBR report with the CPUC. Based on
the results against the performance indicator benchmarks, SDG&E
requested a total net reward of $12.2 million.

These proceedings do not encompass electric transmission issues. By the
end of February 2003, SDG&E will file an electric transmission rate
request with the FERC, updating its ratebase and its revenue
requirement for operating and maintenance costs.

Natural Gas Procurement PBR

SDG&E has a Natural Gas Procurement PBR mechanism that allows SDG&E to
receive a share of the savings it achieves by buying natural gas for
customers below a monthly benchmark. SDG&E's request for a reward of
$6.7 million for the PBR natural gas procurement period ended July 31,

2001 (Year 8)performance-based incentive mechanisms, was approved by the CPUC onand related performance measures and incentives were adopted. The CPUC's decision establishes an indexing methodology for post-test-year ratemaking that includes inflation adjustments and earnings-sharing mechanisms. The decision is retroactive to January 30, 2003. As part1, 2005 and is applicable to years 2005-2007. It eliminates earnings sharing and incentive awards for 2004.
For 2005 - 2007, the California Utilities' authorized base-rate revenues will be annually increased by the increase in the CPI, subject to minimum and maximum percentage increases that vary with the particular utility and increase yearly. The annual minimum increases range from 3.2% to 3.8% and the annual maximum percentage increases range from 4.2% to 4.8%. Pursuant to the indexing mechanisms, SDG&E increased its 2006 base margin revenue requirements by $33 million. The base margin adjustments included the recalibration of the reward calculation is based2005 base margin escalation to reflect actual index values before calculating the 2006 base margin revenue.For 2005-2007, any utility base-rate earnings that exceed the CPUC-authorized rate of return on California-Arizona natural gas
border price indices, the decision reserved the right to revise the
rewardratebase plus 0.5 percentage point will be shared with customers, in the future, depending on the outcome of the CPUC's border
price investigation (see below) and the FERC's investigation into
alleged energy price manipulation (see Note 10 above). In October 2002,
SDG&E filed its Year 9 report for the PBR natural gas procurement
period ended July 31, 2002, reporting a $1.4 million disallowance,
which was recorded during the three-month period ended September 30,
2002. SDG&E also filed an application on October 31, 2002, seeking to
modify and extend the Natural Gas PBR mechanism beyond Year 10, which
ends July 31, 2003.

Demand Side Management (DSM) and Energy Efficiency Awards

Since the 1990s, the IOUs have been eligible to earn awards for
implementing and/or administering energy-conservation programs. SDG&E
has offered these programs to customers and has consistently achieved
significant earnings therefrom. Beginning in 2002, earnings for non-
low-income energy-efficiency programs were eliminated; however, awards
related to DSM and low-income energy-efficiency programs may still be
requested.

SDG&E has outstanding before the CPUC applications to recover
shareholder rewards earned for performance under the DSM programs for
1995 through 2001. Reward requests in these applications total $35.5
million.

A CPUC Administrative Law Judge has scheduled a pre-hearing conference
to review the IOU's DSM programs. The review may include reanalyzing
the uncollected portion of past rewards earned by IOUs (which have not
been included in SDG&E's income), and potentially recomputeproportions that vary with the amount of the DSM rewards.excess, beginning with customers' receiving 75% of the excess, declining to 25% as the excess increases. The decision authorizes either utility to file for a suspension of the indexing and sharing mechanisms if its base-rate earnings for any year are at least 1.75 percentage points below its authorized rate of return and authorizes others to file for a suspension if either utility's base-rate earnings for any year are at least 1.75 percentage points above its authorized rate of return. The mechanisms would be automatically suspended for either utility if its base-rate earnings for 2005 or 2006 are at least 3 percentage points above or below its authorized rate of return.
The decision also establishes formula-based performance measures for customer service, safety and reliability. These provide symmetrical annual reward and penalty potentials aggregating approximately $14 million.
Cost of Capital
On December 15, 2005, the CPUC approved a return on equity (ROE) of 10.7% for SDG&E, an increase from its current ROE of 10.37%. SDG&E's authorized capital structure remains unchanged at 45.25% debt, 5.75% preferred stock and 49% common equity.
CPUC Investigation of Compliance with Affiliate Rules
In November 2004, the CPUC initiated the independent audit (known as the GDS audit) to evaluate energy-related holding company systems and affiliate activities undertaken by Sempra Energy within the service territories of the California Utilities. A draft audit report covering years 1997 through 2003 was provided to the CPUC's Energy Division in December 2005. The Energy Division is reviewing the draft audit report and plans to make the final audit report available in the first half of 2006. The scope of the audit is broader than the annual affiliate audit.
In May 2005, the California Utilities filed with the CPUC the results of the annual independent audit of the California Utilities' 2004 transactions with other Sempra Energy affiliates. Although the company does not agree with a finding of the auditor that utility procurement information was improperly provided to an affiliated risk-management consulting firm employed by Sempra Energy, the California Utilities have adopted the auditor's recommendation to perform risk management functions themselves rather than utilizing Sempra Energy's Risk Management Department.
"CPUC Investigation of Energy-Utility Holding Companies" and "Natural Gas Market OIR" (below) also discuss issues related to affiliate relationships.
CPUC Investigation of Energy-Utility Holding Companies
On October 27, 2005, the CPUC initiated a proceeding to re-examine the relationships between the California IOUs and their respective parent holding companies and other non-utility affiliates. It contemplates a review of the capital budgets, capital allocation processes, and dividend and capital retention policies of the utilities and their non-utility affiliates to better understand the amount of capital to be allocated for investment in energy infrastructure to meet California's need for reliable energy. The CPUC has broadly determined that, in appropriate circumstances, it could require the holding company to provide cash to a utility subsidiary to cover its operating expenses and working capital to the extent it is not adequately funded through retail rates. The CPUC may propose additional rules or regulations to ensure that the utilities retain sufficient capital and the ability to access such capital to meet their customers' needs, and to address potential conflicts between the interests of utility ratepayers and those of non-utility affiliates to ensure that they do not undermine the utilities' ability to meet their public service obligations at the lowest possible cost. A preliminary schedule contemplates that any proposed rules and final rules would be issued for comment and final rules be adopted in the first half of 2006.
Natural Gas Industry Restructuring (GIR)
In December 2001, the CPUC issued a decision related to GIR, with implementation anticipated during 2002. On April 1, 2004, after many delays and changes, the CPUC issued a decision that adopts tariffs to implement the 2001 decision. However, that decision stayed implementation of the GIR tariffs until the CPUC issued a decision in Phase I of the Natural Gas Market Order Instituting Ratemaking (OIR) discussed below. At that time, the CPUC ordered the California Utilities to file a new proposal for system integration, firm access rights and off-system deliveries, as referenced below. The company is required to file a new Biennial Cost Allocation Proceeding (BCAP) application after the stay in the GIR implementation proceeding is lifted.
Natural Gas Market OIR
The CPUC's Natural Gas Market OIR was instituted in January 2004 and is being addressed in two phases. The focus of the Natural Gas Market OIR is the period from 2006 to 2016. The California Utilities have opposedmade comprehensive filings in the OIR, outlining a proposed market structure that is intended to create access to new natural gas supply sources, such as liquefied natural gas, for California. In their filings, the California Utilities proposed a recalculation.framework to provide firm tradable access rights for intrastate natural gas transportation; provide SoCalGas with continued balancing account protection for intrastate transmission and distribution revenues, thereby eliminating throughput risk; and integrate their transmission systems so as to have common rates and rules. The issueCalifornia Utilities also proposed that the capital expenditures necessary to access new sources of supply be included in ratebase and that the total amount of the expenditures would be $200 million to $300 million. A decision on Phase I w as issued in September 2004. The California Utilities were required to file separate applications to address system integration, firm access rights and off-system deliveries. The CPUC also determined that the ratemaking treatment and cost responsibility for any access-related infrastructure will be addressed in future applications to be filed when more is stillknown about the particular project.
Evidentiary hearings on the system integration proposal were held in September 2005 to consider whether the transmission component of the natural gas transportation rates of the California Utilities should be equalized. System integration would allow customers in the California Utilities' service territories to access upstream supplies of natural gas on an equal basis. A decision on this phase is expected during the first quarter of 2006. Evidentiary hearings on infrastructure adequacy were held in August 2005 and addressed a variety of issues including the infrastructure adequacy of the California Utilities' transmission and storage facilities. Natural gas quality standards and interconnection requirements are being addressed in separate phases. In the second phase, to be addressed in mid-2006, the CPUC will consider establishing a system of firm access rights into the California Utilities' system and off-system deliveries.
The California Utilities proposed a methodology and framework to be used by the CPUC for granting pre-approval of new interstate transportation agreements. The Phase I decision approved the California Utilities' transportation capacity pre-approval procedures with some modifications. In 2005, SDG&E was granted approval for capacity contracts with El Paso Natural Gas Company (El Paso), Transwestern Pipeline Company and Kern River Gas Transmission Company, enabling the company to meet its identified goal to operate within the CPUC's approved planning range by November 1, 2006. All interstate transportation capacity under the pre-approved contracts will be used to transport natural gas supplies on behalf of the California Utilities' core residential and small commercial customers, and all costs of the capacity will be recovered in the customers' procurement rates.
Recovery of Certain Disallowed Transmission Costs
In September 2005, the FERC approved SDG&E's May 2005 settlement with the California Independent System Operator (ISO), which provides for refunds of ISO charges on the Arizona Public Service Co. and the Imperial Irrigation District ownership shares of the Southwest Powerlink, and resolves such unreimbursed charges going forward. Therefore, SDG&E recorded pre-tax income of $44 million in the third quarter of 2005.
California Utilities' Structural Changes
On January 4, 2006, the company announced an agreement that, subject to court approval, would settle the Continental Forge antitrust litigation, an identical proceeding in Nevada and class action lawsuits alleging price misreporting and wash trading. The agreement included that the California Utilities will seek approval from the CPUC to integrate their natural gas transmission facilities and to develop both firm, tradable natural gas receipt point rights for access to their combined intrastate transmission system and firm storage capacity rights on SoCalGas' underground natural gas storage system. Additional discussion of the settlement is provided in Note 11 under "Legal Proceedings."
Gain on Sale Rulemaking
A rulemaking was issued in September 2004 to standardize the treatment of gains on sales of property by the IOUs. This rulemaking may result in the adoption of a general ratemaking policy for allocation between utility shareholders and ratepayers of any gain or loss on sale of utility property. The CPUC will consider adopting a standard percentage allocation, probably between 5 percent and 50 percent to shareholders, rather than resolving such allocations on a case-by-case basis, as is now its practice. In unusual circumstances the CPUC would be able to depart from the standard allocation to be adopted. The CPUC intends to apply this standard percentage to sales of both depreciable and non-depreciable property. The rulemaking states that the new policy would replace the CPUC's current policy of allocating to shareholders all gain or loss to shareholders on sale to a municipality of a utility operating system.In November 2005, a proposed decision was issued that, if approved, would adopt a process for allocating gains on sale received by certain electric, natural gas, telecommunications and water utilities when they sell utility land, assets such as buildings, or other tangible or intangible assets formerly used to serve utility customers. In most cases, utility customers should receive 75% of the gain. The utilities' shareholders should receive the remaining 25% of the gain on sale. Opening and reply comments to the proposed decision were filed in January 2006. The final outcome of the rulemaking may be different than that proposed for comment in the order instituting the rulemaking.
Southern California Wildfires
In August 2005, the CPUC granted SDG&E full recovery, via its catastrophic event memorandum account (CEMA), of incurred costs ($40.8 million) associated with the fires.
NOTE 11. COMMITMENTS AND CONTINGENCIES
Legal Proceedings
In January 2006, the company reached agreements, subject to court approval, to settle certain litigation arising out of the 2000 - 2001 California energy crisis. As a result of that settlement, the company increased its reserves at December 31, 2005, to $79million, of which $76million relates to the settled matters.
Other reserves of $3million have been established for the litigation that is continuing at February 22, 2006. The uncertainties inherent in complex legal proceedings make it difficult to estimate with any degree of certainty the costs and effects of resolving these matters. Accordingly, costs ultimately incurred may differ materially from estimated costs and could materially adversely affect the company's business, cash flows, results of operations and financial condition.
Settlement Agreements
The litigation that is the subject of the settlement agreements is frequently referred to as the Continental Forge litigation, although the settlements also include other cases. The Continental Forge litigation, consisting of class-action and individual antitrust and unfair competition lawsuits consolidated in San Diego Superior Court, allege that Sempra Energy and the California Utilities, along with El Paso and several of its affiliates, unlawfully sought to control natural gas and electricity markets and claim damages of $23 billion after applicable trebling. Plaintiff class members include virtually all natural gas and electric consumers served by the California IOUs. The settlement of Continental Forge would also include the settlement of class action price reporting litigation, consisting of antitrust and unfair competition lawsuits coordinated in the San Diego Superior Court, alleging that Sempra Energy and its subsidiaries unlawfully misreported natural gas transactions to publishers of price indi ces and engaged in natural gas wash trading transactions. A second settlement agreement relates to class-action litigation brought by the Nevada Attorney General in Nevada Clark County District Court and involves virtually identical allegations to those in the Continental Forge litigation.
To settle the California and Nevada litigation, Sempra Energy would make cash payments in installments aggregating $377 million, of which $347 million relates to the Continental Forge and California class action price reporting litigation and $30 million relates to the Nevada antitrust litigation. Of the $377 million, $83 million would be paid within thirty days of final approval of the settlement by the San Diego County Superior Court and an additional $83 million would be paid on the first anniversary of that approval. Of the remaining amount, $27.3 million would be paid on the closing date of the settlement and $26.3 million would be paid on each successive anniversary of the closing date through the seventh anniversary of the closing date. At any time after the first anniversary of the closing date, Sempra Energy would have the option to prepay all or any portion of the remaining unpaid settlement amounts at a discount rate of 7%, with any partial prepayment applied to and reducing each remaining paym ent on an equal and proportionate basis.
Additional consideration for the California settlement includes an agreement that Sempra LNG would sell to the California Utilities, subject to CPUC approval, re-gasified liquefied natural gas from its liquefied natural gas terminal being constructed in Baja California, Mexico at the California border index price minus $0.02. The volumes to be purchased and sold would be up to 500 million cubic feet per day that Sempra Energy subsidiaries currently have contractual rights to purchase and that is not delivered or sold to Mexican entities. The California Utilities also would seek approval from the CPUC to integrate their natural gas transmission facilities and to develop both firm, tradable natural gas receipt point rights for access to their combined intrastate transmission system and SoCalGas' underground natural gas storage system. In addition, as described below, Sempra Generation voluntarily would reduce the price that it charges for power and limit the places at which it would deliver power under its contract with the DWR.
The California settlement is subject to the approval of the San Diego Superior Court, which has preliminarily approved the settlement, and authorized providing notice to the plaintiff class. The Los Angeles City Council has not yet voted to approve the City of Los Angeles's participation in the settlement and it may elect to continue pursuing its individual case against Sempra Energy and the California Utilities. If the City of Los Angeles decides not to participate, Sempra Energy may, at its option, either proceed with the settlement of the class action and other individual cases or terminate the entire agreement. The California Attorney General, the DWR, the California Energy Oversight Board, Edison, and Pacific Gas & Electric Company unsuccessfully challenged the proposed notice to the class based on their concern that, among other things, the releases in the settlement agreement may be sufficiently broad to encompass other proceedings against Sempra Energy and its subsidiaries to which they are pa rties. The final approval hearing for the Continental Forge settlement is scheduled to occur on June 8, 2006. The Nevada settlement is subject to approval by the Nevada Clark County District Court, which has not yet approved notice to the class or scheduled a final approval hearing. Both the California and Nevada settlements must be approved for either settlement to take effect, but Sempra Energy is permitted to waive this condition. The settlements are not conditioned upon approval by the CPUC, the DWR, or any other governmental or regulatory agency to be effective.
Sempra Energy recorded an after-tax charge of $116 million for the quarter ended December 31, 2005 (all at the parent company) to provide additional reserves to reflect the costs of the settlements that exceed amounts previously reserved. The additional and previously reserved amounts for the California and Nevada settlements aggregate $585 million (including $76 million at SDG&E and $155 million at SoCalGas) and fully provide for the present value of both the cash amounts to be paid in the settlements and the price discount to be provided on electricity expected to be delivered under the DWR contract.
Other Natural Gas Cases
On November 21, 2005, the California Attorney General and the CPUC filed a lawsuit against Sempra Energy and the California Utilities in San Diego County Superior Court alleging that in 1998 Sempra Energy and the California Utilities had intentionally misled the CPUC in ultimately obtaining CPUC approval to use the utilities' California natural gas pipeline capacity to enable Sempra Energy's non-utility subsidiaries to deliver natural gas to a power plant in Mexico. It further alleges that, as a result of insufficient utility pipeline capacity to serve both the power plant and California customers, SDG&E curtailed natural gas service to electric generators and large California commercial and industrial customers 17 times in 2000 - 2001, with service disruptions resulting in increased air pollution and higher electricity prices for California consumers from the use of oil as an alternate fuel source by electric generating plants. The lawsuit seeks statutory penalties of not less than $1 million, $2,50 0 for each of an unspecified number of instances of unfair business practices, and unspecified amounts of actual and punitive damages. It also seeks an injunction to require divestiture by Sempra Energy of non-utility subsidiaries to an extent to be determined by the court.
In April 2003, Sierra Pacific Resources and its utility subsidiary Nevada Power filed a lawsuit in U.S. District Court in Las Vegas against major natural gas suppliers, and included Sempra Energy, the California Utilities and Sempra Commodities, seeking recovery of damages alleged to aggregate in excess of $150 million (before trebling). The U.S. District Court dismissed the case in November 2004, determining that the FERC had exclusive jurisdiction to resolve the claims. In January 2005, plaintiffs filed an appeal with the Ninth Circuit Court of Appeals.
During 2004, 12 antitrust actions were filed against the company,alleging that energy prices were unlawfully manipulated by the reporting of artificially inflated natural gas prices to trade publications and by entering into wash trades. Several of those lawsuits seek class action certification. On April 8, 2005, one of those lawsuits, filed in the Nevada U.S. District Court, was dismissed, on the grounds that the claims asserted were preempted by federal law and the Filed Rate Doctrine. In June 2005, the three remaining lawsuits pending in the Nevada U.S. District Court were amended to name the California Utilities as defendants and to include conspiracy allegations similar to those made in the Continental Forge litigation. On December 27, 2005, the District Court dismissed these three actions, on the grounds that the claims asserted in these suits were preempted under federal law and the Filed Rate Doctrine. In addition, in June 2005, a class action lawsuit similar to the pending individual suits in the Nevada federal court was filed in the U.S. District Court for the Eastern District of California and has now been coordinated with the Nevada federal court proceeding. That action was stayed pending the court's determination of the motions to dismiss in the other federal cases. Sempra Energy will proceed to seek the dismissal of this action as well. With respect to the lawsuits coordinated before the CPUC.

Pending Incentive Awards

At December 31, 2002,San Diego Superior Court, on June 29, 2005, the following performance incentives werecourt denied the defendants' motion to dismiss on preemption and Filed Rate Doctrine grounds. A separate motion to dismiss filed by Sempra Energy for improper joinder remains pending CPUC approval and therefore, were not includedresolution by the court. On January 4, 2006, the parties agreed to settle the class action cases coordinated in the company's
earnings (dollarsSan Diego Superior Court as part of the overall Continental Forge settlement described above.
Electricity Cases
Various antitrust lawsuits, which seek class-action certification, allege that numerous entities, including Sempra Energy and certain subsidiaries, including SDG&E, that participated in millions):

Program
---------------------------------
PBR $ 12.2
Natural gas procurement 6.7
DSM 35.5
---------------------------------
Total $ 54.4
=================================

Cost of Capital

Effective January 1, 2003, SDG&E's authorized rate of return on equity
is 10.9 percent (increased from 10.6 percent) for SDG&E's electric
distribution and natural gas businesses. This change resultsthe wholesale electricity markets unlawfully manipulated those markets. Collectively, these lawsuits allege damages against all defendants in an annual revenue requirement increaseaggregate amount in excess of $2.4 million ($1.9 million
electric$16 billion (before trebling). In January 2003, the federal court granted a motion to dismiss one of these lawsuits, filed by the Snohomish County, Washington Public Utility District against Sempra Energy and $0.5 million natural gas)certain non-utility subsidiaries, among others, on the grounds that the claims contained in the complaint were subject to the Filed Rate Doctrine and increases SDG&E's overall

ratewere preempted by the Federal Power Act. In September 2004, the Ninth Circuit U.S. Court of return from 8.75 percentAppeals affirmed the district court's ruling, finding that the FERC, not civil courts, has exclusive jurisdiction over the matter. Snohomish County appealed the Ninth Circuit decision to 8.77 percent. These rates remainthe U.S. Supreme Court, which, in effect through 2003.June 2005, declined to review the decision. The electric-transmission costcompany believes that this decision provides a precedent for the dismissal on the basis of capital is
determined under a separate FERC proceeding.

Border Price Investigationfederal preemption and the Filed Rate Doctrine of the other lawsuits against the Sempra Energy companies claiming manipulation of the electricity markets. On October 4, 2005, on the basis of federal preemption and Filed Rate grounds, the San Diego Superior Court dismissed with prejudice the initial consolidated cases that claimed that energy companies, such as the Sempra Energy companies, manipulated the wholesale electricity markets. In December 2005, plaintiffs filed an appeal in that case.
CPUC Border Price Investigation
In November 21, 2002, the CPUC instituted an investigation into the Southern California natural gas market and the price of natural gas delivered to the California-Arizona (CA-AZ)California - Arizona border during the period ofbetween March 2000 throughand May 2001. The Administrative Law Judge's (ALJ) proposed decision was rejected by the CPUC intends to examine the possible
reasons for and issues potentially relatedin December 2004.
The portion of this investigation relating to the elevated border
prices that affected California consumers during this period.

SDG&EUtilities is included among the respondents to the investigation.still open. If the investigation determineswere to determine that the conduct of any respondenteither of the California Utilities contributed to the natural gas price spikes atthat occurred during the CA-AZ border during thisinvestigation period, the CPUC may modify the respondent's applicableparty's natural gas procurement incentive mechanism, reduce the amount of any shareholder award for the period involved, and/or order the respondentparty to issue a refund to ratepayersratepayers. At December 31, 2005, the cumulative amount of these shareholder awards, substantially all of which has been included in income, was $8.5 million.
The CPUC may hold additional hearings to offsetconsider whether other companies, including other California utilities, contributed to the higher rates paid. SDG&Enatural gas price spikes, or issue an order terminating the investigation. Discovery is fully cooperating
with the CPUCongoing and initial testimony was filed in November 2005. Hearings are expected to begin in late July 2006.
FERC Refund Proceedings
The FERC is investigating prices charged to buyers in the investigationCalifornia Power Exchange (PX) and believeISO markets by various electric suppliers. In December 2002, a FERC ALJ issued preliminary findings indicating that the CPUC will
ultimately determine that they were not responsiblePX and ISO owe power suppliers $1.2 billion for the high border
prices during this period.

Biennial Cost Allocation Proceeding (BCAP)

The BCAP determinesOctober 2, 2000 through June 20, 2001 period (the $3.0 billion that the allocationCalifornia PX and ISO still owe energy companies less $1.8 billion that the energy companies charged California customers in excess of authorized costs between customer
classes and the rates and rate design applicable to such classes forpreliminarily determined competitive market clearing prices). In March 2003, the FERC adopted its ALJ's findings, but changed the calculation of the refund by basing it on a different estimate of natural gas transportation service. SDG&E filed itsprices. The March 2003 BCAP on
October 5, 2001. In February 2003, a CPUC Administrative Law Judge
granted a motionorder estimates that the replacement formula for estimating natural gas prices will increase the refund obligations from $1.8 billion to defer the BCAP. SDG&E must submit an amended
application by September 2003, with new rates scheduled to be
implemented by September 2004.

Nuclear Decommissioning Trusts

On June 17, 2002, SDG&E amended its March 21, 2002 joint application
with Edison, requesting the CPUC to set contribution levelsmore than $3 billion for the SONGS nuclear decommissioning trust funds. SDG&E requested a rate
increase to cover its share of projected increased decommissioning
costs for SONGS. If approved,same time period. Pending in the current annual contribution to
SDG&E's trust funds, which is recovered in rates, would increase to
$11.5 million annually from $4.9 million. Prior to August 1999, SDG&E's
annual contribution had been $22 million.

Utility Integration

On September 20, 2001, the CPUC approved Sempra Energy's request to
integrate the management teams of SDG&E and SoCalGas. The decision
retains the separate identities of each utility and is not a merger.
Instead, utility integration is a reorganization that consolidates
senior management functionsNinth Circuit are various parties' appeals on aspects of the two utilities and returnsFERC's order. In April 2005, the Ninth Circuit heard oral argument on issues relating to the utilities the majority of shared support services previously provided
by Sempra Energy's centralized corporate center. Once implementation is
completed, the integration is expected to result in more effective
operations.

In a related development, an August 2002 CPUC interim decision denied a
request by SDG&E and SoCalGas to combine their natural gas procurement
activities at this time, pending completionscope of the CPUC's Border Price
Investigation referred to above.

CPUC Investigation of Energy-Utility Holding Companies

The CPUC has initiated an investigation intorefund proceeding and whether the relationship between
California's IOUs and their parent holding companies. Among the matters
to be considered in the investigation are utility dividend policies and
practices and obligations of the holding companies to provide financial
support for utility operations under the agreements with the CPUC
permitting the formation of the holding companies. On January 11, 2002,
the CPUC issued a decision to clarify under what circumstances, if any,
a holding company would be required to provide financial support to its
utility subsidiaries. The CPUC broadly determined that it would require
the holding company to provide cash to a utility subsidiary to cover
its operating expenses and working capital to the extent they are not
adequately funded through retail rates. This would be in addition to
the requirement of holding companies to cover their utility
subsidiaries' capital requirements, as the IOUs have previously
acknowledged in connection with the holding companies' formations. On
January 14, 2002, the CPUC ruled on jurisdictional issues, deciding
that the CPUCFERC had jurisdiction to create the holding company system
and, therefore, retainsorder refunds from governmental entities. The Ninth Circuit determined in September 2005 that FERC did not have jurisdiction to enforce conditionsorder refunds from governmental entities. The California IOUs, including SDG&E, have now filed claims with the various governmental entities to whichrecoup monies paid over and above the holding companies had agreed. The company's requestjust and reasonable rate for rehearingpower in the 2000-2001 time frame. A decision on the remaining issues was denied byargued before the CPUC and the company subsequently filed
appealsCourt in the California Court of Appeal, which are stillApril 2005 remains pending.

Valley-Rainbow Interconnect

On December 19, 2002, the CPUC issued a decision finding that the
Valley-Rainbow Interconnect, a proposed 500-kv transmission line
connecting SDG&E's and Edison's transmission systems, is not needed to
meet SDG&E's projected resource needs within a planning horizon that
the CPUC deemed appropriate (five years). If it chooses to,
SDG&E can
refile at a later date. In January 2003, SDG&E and the ISO filed
applications for rehearing of the decision. If this project is
abandoned SDG&E plans to seek recovery of its costs ($20has been awarded $137 million through December 31, 2002)2005, in settlement of certain claims against electricity suppliers related to the 2000-01 California energy crisis. The net proceeds of these settlements are applied to reduce electric rates.
FERC Manipulation Investigation
The FERC is separately investigating whether there was manipulation of short-term energy markets in the western United States that would constitute violations of applicable tariffs and warrant disgorgement of associated profits. In this proceeding, the FERC's authority is not confined to the periods relevant to the refund proceeding. In May 2002, the FERC ordered all energy companies engaged in electric energy trading activities to state whether they had engaged in various specific trading activities in violation of the PX and ISO tariffs.
On June 25, 2003, the FERC issued several orders requiring various entities to show cause why they should not be found to have violated California ISO and PX tariffs. The FERC directed 43 entities, including SDG&E, to show cause why they should not disgorge profits from certain transactions between January 1, 2000 and June 20, 2001 that are asserted to have constituted gaming and/or anomalous market behavior under the California ISO and/or PX tariffs. SDG&E and the FERC resolved the matter through a FERC filingsettlement, which documents the ISO's finding that SDG&E did not engage in market activities in violation of the ISO or PX tariffs, and in which SDG&E agreed to be made in February
2003.

NOTE 12. COMMITMENTS AND CONTINGENCIES

pay $27,792 into a FERC-established fund.
Natural Gas Contracts
SDG&E buys natural gas under short-term and long-term contracts. Short-
term purchasesPurchases are from various Southwest U.S. and Canadian suppliers and are primarily based on monthly spot-market prices. SDG&EThe company transports natural gas under long-term firm pipeline capacity agreements that provide for annual reservation charges, which are recovered in rates.
SDG&E has long-term natural gas transportation contracts with various interstate pipelines that expire on various dates between 20032006 and 2023. SDG&E has a long-term purchase agreement with a Canadian supplier
that expires in August 2003, and in which the delivered cost of natural
gas is tied to the California border spot-market price. SDG&Ecurrently purchases

76
natural gas on a spot basis to fill its additional long-term pipeline
capacity. SDG&E intends to continue using the long-term pipeline capacity, in other ways as well, including the transport of other
natural gasand purchases additional spot market supplies delivered directly to California for its own use andremaining requirements. SDG&E continues its ongoing assessment of its long-term pipeline capacity portfolio, including the release of a portion of this capacity to third parties. In accordance with regulatory directives, SDG&E reconfigured its pipeline capacity portfolio in November 2005 to secure firm transportation rights from a diverse mix of U.S. and Canadian supply sources for its projected core customer natural gas requirements.
All of SDG&E's natural gas is delivered through SoCalGas' pipelines under a short-term transportation agreement. In addition, under a separate agreement expiring in March 2003,2006, SoCalGas provides SDG&E 4.5six billion cubic feet of storage capacity. An agreement is expected to be
completedIn February 2006, SDG&E entered into two agreements with SoCalGas that willto extend the storage services through March
2004.

capacity to 2008. The agreements are pending to the CPUC's approval.
At December 31, 2002,2005, the future minimum payments under existing natural gas storage and transportation contracts were:

Storage and Natural
(Dollars in millions) Transportation Gas Total
- --------------------------------------------------------------------
2003 $ 14 $ 17 $ 31
2004 14 -- 14
2005 13 -- 13
2006 12 -- 12
2007 11 -- 11
Thereafter 153 -- 153
----------------------------------------------
Total minimum payments $ 217 $ 17 $ 234
- --------------------------------------------------------------------

(Dollars in millions)
2006 $ 22
2007 15
2008 13
2009 10
2010 10
Thereafter 112
Total minimum payments $ 182
Total payments under natural gas contracts were $205$455 million in 2002,
$4572005, $347 million in 20012004 and $273$274 million in 2000.

2003.
Purchased-Power Contracts

On January 17, 2001, the California Assembly passed AB X1 to allow the
DWR to purchase power under long-term contracts for the benefit of
California consumers. In accordance with AB X1, SDG&E entered into an
agreement with the DWR under which the DWR purchases SDG&E's full net
short position (the power needed by SDG&E's customers, other than that
provided by SDG&E's nuclear generating facilities or its previously
existing purchased power contracts) through December 31, 2002. Starting
on January 1, 2003, SDG&E and the other IOUs resumed their electric
commodity procurement function based on a CPUC decision issued in
October 2002.
For additional discussion of this matter see Note 10.

For 2003,2006, SDG&E expects to receive 43 percent of its customer power requirementrequirements from DWR allocations. Of the remaining requirements, that
SDG&E must provide, SONGS willis expected to account for 2117 percent, long-term contracts for 2619 percent (of which 7 percent is provided by renewable contracts expiring on various dates through 2025), Palomar for 12 percent and spot market purchases for 109 percent. As
of January 2003, SDG&E has approximately 90 percent of its electric
power requirements met by a combination ofThe long-term contracts, DWR-
allocated contracts and its share of nuclear generating facilities.
The contracts expire on various dates between 2003 and 2025. Prior to
January 1, 2001, the cost of these contracts was recovered by bidding
them into the PX and receiving revenue from the PX for bids accepted.
As of January 1, 2001, in compliance with a FERC order prohibiting
sales to the PX, SDG&E no longer bids those contracts into the PX.

Those contracts are now used to serve customers in compliance with a
CPUC order. In late 2000, SDG&E entered into additional contracts to
serve customers instead of buying all of its power from the PX. These
contracts expire in 2003. In addition, during 2002 SDG&E entered into
contracts which will provide approximately four percent of its 2003
total energy sales from renewable sources. These contracts expire from
2008 through 2018.

2032.
At December 31, 2002,2005, the estimated future minimum payments under the long-term contracts (not including the DWR allocation)allocations) were:

(Dollars in millions)
- --------------------------------------------------------------------
2003 $ 257
2004 227
2005 228
2006 224
2007 213
Thereafter 2,285
--------
Total minimum payments $ 3,434
- --------------------------------------------------------------------

(Dollars in millions)
2006 $ 247
2007 248
2008 288
2009 283
2010 282
Thereafter 2,627
Total minimum payments $ 3,975
The payments represent capacity charges and minimum energy purchases. SDG&E is required to pay additional amounts for actual purchases of energy that exceed the minimum energy commitments. TotalExcluding DWR-allocated contracts, total payments under the contracts were $235$363 million in 2002, $5122005, $329 million in 20012004 and $257$396 million in 2000.

2003.
Leases
SDG&E has operating leases on real and personal property expiring at various dates from 20032006 to 2045. Certain2045.Certain leases on office facilities contain escalation clauses requiring annual increases in rent ranging from 32 percent to 5 percent. The rentals payable under these leases are determined on both fixed and percentage bases, and most leases contain extension options which are exercisable by SDG&E. SDG&E terminated its
capital lease agreement for nuclear fuel in mid-2001 and now owns its
nuclear fuel.

the company.
At December 31, 2002,2005, the minimum rental commitments payable in future years under all noncancellable leases were as follows:

(Dollars in millions)
- ------------------------------------------------------------
2003 $16
2004 14
2005 12
2006 10
2007 6
Thereafter 17
--------
Total future rental commitments $75
- ------------------------------------------------------------

(Dollars in millions)
2006 $ 19
2007 17
2008 12
2009 9
2010 8
Thereafter 19
Total future rental commitments $ 84
Rent expense for operating leases totaled $27$22 million in 2002, $212005, $20 million in 20012004 and $20 million in 2003.
Construction Projects
In addition to the recurrent expenditures for plant improvements, the company will spend $500 million in 2006 to purchase the 550-MW Palomar power plant, which is currently being constructed by Sempra Generation, and other costs associated with the plant. The capitalized costs through December 31, 2005 are recorded as construction work in progress inUtilityPlant on the Consolidated Balance Sheets.
Guarantees
As of December 31, 2005, the company did not have any outstanding guarantees.
Department Of Energy Nuclear Fuel Disposal
The Nuclear Waste Policy Act of 1982 made the DOE responsible for the disposal of spent nuclear fuel. However, it is uncertain when the DOE will begin accepting spent nuclear fuel from SONGS. This delay by the DOE will lead to increased costs for spent fuel storage. This cost will be recovered through SONGS revenue unless the company is able to recover the increased cost from the federal government.
Electric Distribution System Conversion
Under a CPUC-mandated program, the cost of which is included in utility rates, and through franchise agreements with various cities, SDG&E is committed, in varying amounts, to converting overhead distribution facilities to underground. As of December 31, 2005, the aggregate unexpended amount of this commitment was $67 million. Capital expenditures for underground conversions were $32 million in 2000.

78
2005, $23 million in 2004 and $28 million in 2003.
Environmental Issues
The company's operations are subject to federal, state and local environmental laws and regulations governing hazardous wastes, air and water quality, land use, solid waste disposal and the protection of wildlife. As applicable, appropriate and relevant, these lawsLaws and regulations require that the company investigate and remediate the effects of the release or disposal of materials at sites associated with past and present operations, including sites at which the company has been identified as a Potentially Responsible Party (PRP) under the federal Superfund laws and comparable state laws. The company is required to obtain numerous governmental permits, licenses and other approvals to construct facilities and operate its businesses, and must spend significant sums on environmental monitoring, pollution control equipment and emissions fees. Costs incurred to operate the facilities in compliance with these laws and regulations generally have been recovered in customer rates.

Significant costs incurred to mitigate or prevent future environmental contamination or extend the life, increase the capacity or improve the safety or efficiency of property utilized in current operations are capitalized. The company's capital expenditures to comply with environmental laws and regulations were $4$9 million in 2002, $12005, $9 million in 20012004 and $2$5 million in 2000.2003. The cost of compliance with these regulations over the next five years is not expected to be significant.
Costs that relate to current operations or an existing condition caused by past operations are generally recorded as a regulatory asset due to the assuranceprobability that these costs will be recovered in rates.

The environmental issues currently facing the company or resolved during the latest three-year periodlast three years include investigation and remediation of its manufactured-gas sites (three(two completed as of December 31, 20022005 and site-closure letters received for two), cleanup
at SDG&E's former fossil fuel power plants (all sold in 1999 and actual
or estimated cleanup costs included in the transactions)received), cleanup of third-party waste-disposal sites used by the company, which has been identified as a PRP (investigations and remediations are continuing) and mitigation of damage to the marine environment caused by the cooling-water discharge from SONGS (the requirements for enhanced fish protection, a 150-acre artificial reef and restoration of 150 acres of coastal wetlands are in process). Through December 31, 2003, the SONGS
mitigation costs are recovered through the ICIP mechanism.

Environmental liabilities are recorded when the company's liability is probable and the costs are reasonably estimable. In many cases, however, investigations are not yet at a stage where the company has been able to determine whether it is liable or, if the liability is probable, to reasonably estimate the amount or range of amounts of the cost or certain components thereof. Estimates of the company's liability are further subject to other uncertainties, such as the nature and extent of site contamination, evolving remediation standards and imprecise engineering evaluations. The accruals are reviewed periodically and, as investigations and remediation proceed, adjustments are made as necessary. AtNot including the liability for SONGS marine mitigation, which SDG&E is participating in jointly with Edison, at December 31, 2002,2005, the company's accrued liability for environmental matters was $14.8$17.5 million, of which $1.5$6.3 million is related to manufactured-gas sites, $12.1$10.3 million to cleanup at SDG&E's formerfo rmer fossil-fueled power plants, and $0.9 million to waste-disposal sites used by the company (which has been identified as 79
a PRP) and $0.3 million to other hazardous waste sites. These. The majority of these accruals are expected to be paid ratably over the next threetwo years.
Nuclear Insurance
SDG&E and the other co-ownersowners of SONGS have insurance to respond to any nuclear liability claims related to SONGS. The insurance policy
provides $200coverage of $300 million, in coverage, which is the maximum amount available. In addition, to this primary financial protection, the Price-
AndersonPrice-Anderson Act provides for up to $9.25$10.5 billion of secondary financial protection if the liability loss exceeds the insurance limit.protection. Should any of the licensed/commercial reactors in the United States experience a nuclear liability loss which exceeds the $200$300 million insurance limit, all utilities owning nuclear reactors could be assessed under
the Price-Anderson Act to provide the secondary financial protection. SDG&E and the other co-owners of SONGS could be assessed up to $176
million under the Price-Anderson Act. SDG&E's total share would be $36up to $40 million, subject to an annual maximum assessment of $6 million, unless a default occurswere to occur by any other SONGS co-owner.owner. In the event the secondary financial protection limit iswere insufficient to cover the liability loss, the Price-Anderson Act provides for CongressSDG&E could be subject to
enact further revenue raising measures to pay claims. These measures
could include an additional assessment on all licensed reactor
operators.

assessment.
SDG&E and the other co-ownersowners of SONGS have $2.75 billion of nuclear property, decontamination and debris removal insurance. The coverage
also provides the SONGS ownersinsurance and up to $490 million for outage expenses and replacement power costs incurred because of accidental property damage. This coverage is limited to $3.5 million per week for the first 52 weeks and $2.8 million per week for up to 110 additional weeks. Coverage is also
provided for the cost of replacement power, which includes indemnity
payments for up to three years,weeks, after a waiting period of 12 weeks. The insurance is provided through a mutual insurance company, owned by
utilities with nuclear facilities. Under the policy's risk sharing
arrangements,through which insured members are subject to retrospective premium assessments if losses at any covered facility exceed the insurance
company's surplus and reinsurance funds. Should there be a
retrospective premium call,(up to $8.65 million in SDG&E could be assessed up to $7.6 million.

Both the&E's case).
The nuclear liability and property insurance programs subscribed to by members of the nuclear power generating industry include industry aggregate limits for non-certified acts (as defined by the Terrorism Risk Insurance Act) of terrorism-related SONGS losses, resulting fromincluding replacement power costs. There are industry aggregate limits of $300 million for liability claims and $3.24 billion for property claims, including replacement power costs, for non-certified acts of terrorism. Department Of Energy Decommissioning

The Energy Policy ActThese limits are the maximum amount to be paid to members who sustain losses or damages from these non-certified terrorist acts. For certified acts of 1992 established a fund forterrorism, the decontamination and decommissioning of the Department of Energy (DOE)
nuclear fuel enrichment facilities. Utilities which have used DOE
enrichment services are being assessed a total of $2.3 billion, subject
to adjustment for inflation, over a 15-year period ending in 2006. Each
utility's share is based on its share of enrichment services purchased
from the DOE through 1992. SDG&E's annual assessment is approximately
$1 million, which is recovered through SONGS revenue.

Department Of Energy Nuclear Fuel Disposal

The Nuclear Waste Policy Act of 1982 made the DOE responsible for the
disposal of spent nuclear fuel. However, it is uncertain when the DOE
will begin accepting spent nuclear fuel from SONGS. This delay by the
DOE will lead to increased cost for spent fuel storage. This cost will
be recovered through SONGS revenue unless the company is able to
recover the increased cost from the federal government.

Litigation

Lawsuits filed in 2000 and currently consolidated in San Diego Superior
Court seek class-action certification and damages, alleging that Sempra
Energy, SoCalGas and SDG&E, along with El Paso Energy Corp. and several
of its affiliates, unlawfully sought to control and have manipulated
natural gas and electricity markets. On October 16, 2002, the assigned
San Diego Superior Court judge ruled that the case can proceed with
discovery and that the California courts, rather than the FERC, have
jurisdiction in the case. This was a preliminary ruling and not a
ruling on the merits or facts of the case. Northern California cases,
which only name El Paso as a defendant, are scheduled for trial in
September 2003 and the remainder of the cases is set for trial in
January 2004. During the fourth quarter of 2002, additional similar
lawsuits have been filed in various jurisdictions.

SDG&E and two other subsidiaries of Sempra Energy, along with all other
sellers in the western power market, have been named defendants in a
complaint filed at the FERC by the California Attorney General's office
seeking refunds for electricity purchases based on alleged violations
of FERC tariffs. The FERC has dismissed the complaint. The California
Attorney General's office requested a rehearing, which the FERC denied.
The California Attorney General has filed an appeal in the 9th
Circuit.

Except for the matters referred toindividual policy limits stated above neither the company nor its
subsidiary is party to, nor is their property the subject of, any
material pending legal proceedings other than routine litigation
incidental to their businesses.

Management believes the above allegations are without merit and will
not have a material adverse effect on the company's financial condition
or results of operations.

Other Legal Proceedings

In connection with its investigation into California energy prices, in
May 2002 the FERC ordered all energy companies engaged in electric
energy trading activities to state whether they had engaged in "death
star," "load shift," "wheel out," "ricochet," "inc-ing load" and
various other specific trading activities as described in memos
prepared by attorneys retained by Enron Corporation and in which it was
asserted that Enron was manipulating or "gaming" the California energy
markets. In response to the inquiry, SDG&E has denied using any of
these strategies. It did disclose and explain a single de minimus 100-
mW transaction for the export of electricity out of California. In
response to a related FERC inquiry regarding natural gas trading, it
has also denied engaging in "wash" or "round trip" trading activities.

SDG&E is also cooperating with the FERC and other governmental agencies
and officials in their various investigations of the California energy
markets. Management believes that this matter will not have a material
adverse effect on the company's financial condition or results of
operations.

Electric Distribution System Conversion

Under a CPUC-mandated program and through franchise agreements with
various cities, SDG&E is committed, in varying amounts, to converting
overhead distribution facilities to underground. As of December 31,
2002, the aggregate unexpended amount of this commitment was $98
million. Capital expenditures for underground conversions were $33
million in 2002, $12 million in 2001 and $26 million in 2000.

apply.
Concentration Of Credit Risk
The company maintains credit policies and systems to manage overall credit risk. These policies include an evaluation of potential counterparties' financial condition and an assignment of credit limits. These credit limits are established based on risk and return considerations under terms customarily available in the industry. The company grants credit to customers and counterparties, substantially all of whom are located in its serviceitsservice territories, which coverscover all of San Diego County and an adjacent portion of Orange County.

As discussed in Note 10, SDG&E accumulated certain costs of electricity
purchases in a balancing account (the AB 265 undercollection). SDG&E
may experience an increase in customer credit risk as it passes on
these costs to customers, as well as charges on behalf of the state of
California to repay the state bonds issued in connection with its past
purchases of power for IOU customers. However, mitigating this increase
in customer credit risk are the decline in the cost of the electric
commodity and return to stability thereof, and the October 2002 CPUC
decision which allows SDG&E to enter into new contracts to procure
electric energy and to establish a cost recovery mechanism. The
decision establishes a semiannual cost review and rate recovery
mechanism with a trigger for more frequent rate changes if balances
exceed five percent of annual, non-DWR generation revenues, to provide
for timely recovery of any undercollections.

82
NOTE 13.12. QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarters ended
------------------------------------------------
Dollars in millions March 31 June 30 September 30 December 31
- --------------------------------------------------------------------------------------

2002
Operating revenues $ 427 $ 407 $ 420 $ 442
Operating expenses 358 340 356 380
------------------------------------------------
Operating income $ 69 $ 67 $ 64 $ 62
------------------------------------------------
Net income $ 55 $ 52 $ 48 $ 54
Dividends on preferred stock 2 1 2 1
------------------------------------------------
Earnings applicable
to common shares $ 53 $ 51 $ 46 $ 53
================================================
2001
Operating revenues $ 1,129 $ 511 $ 333 $ 389
Operating expenses 1,056 454 271 360
------------------------------------------------
Operating income $ 73 $ 57 $ 62 $ 29
------------------------------------------------
Net income $ 54 $ 38 $ 45 $ 46
Dividends on preferred stock 2 1 2 1
------------------------------------------------
Earnings applicable
to common shares $ 52 $ 37 $ 43 $ 45
================================================

The sum
Quarters ended
(Dollars in millions) March 31 June 30 September 30 December 31
2005
Operating revenues $ 621 $ 539 $ 601 $ 751
Operating expenses 553 487 497 692
Operating income $ 68 $ 52 $ 104 $ 59
Net income $ 60 $ 30 $ 104 $ 73
Dividends on preferred stock 1 1 2 1
Earnings applicable to common shares $ 59 $ 29 $ 102 $ 72
2004
Operating revenues $ 580 $ 536 $ 550 $ 608
Operating expenses 518 488 486 526
Operating income $ 62 $ 48 $ 64 $ 82
Net income $ 51 $ 31 $ 62 $ 69
Dividends on preferred stock 1 1 2 1
Earnings applicable to common shares $ 50 $ 30 $ 60 $ 68
Operating revenues for the fourth quarter of 2005 included $23 million before-tax from the 2005 Internal Revenue Service decision relating to the sale of the quarterly amounts does not necessarily equalcompany's former South Bay power plant. Operating expenses for the annual
totals duethird quarter of 2005 included $44 million before-tax California energy crisis litigation costs, offset by $38 million before-tax related to rounding.

the 2005 recovery of line losses and grid management charges arising from the favorable settlement with the ISO. Net income for the third quarter of 2005 included the favorable resolution of prior years' income-tax issues.
Operating revenues and expenses in the fourth quarter of 2004 included a $34 million favorable impact of the final Cost of Service decision, offset by $19 million of litigation expense.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information required on Identification of Directors is incorporated
by reference from "Election of Directors" in the Information Statement
prepared for the May 2003 annual meeting of shareholders. The
information required on the company's executive officers is provided
below.

EXECUTIVE OFFICERS OF THE REGISTRANT
Name Age* Position
- -------------------------------------------------------------------

Edwin A. Guiles 53 Chairman and Chief Executive Officer

Debra L. Reed 46 President and Chief Financial Officer

James P. Avery 46 Senior Vice President, Electric
Transmission

Steven D. Davis 46 Senior Vice President, Customer
Service and External Relations

Margot A. Kyd 49 Senior Vice President, Corporate
Business Solutions

Roy M. Rawlings 58 Senior Vice President, Distribution
Operations

William L. Reed 50 Senior Vice President, Regulatory
Affairs

Lee M. Stewart 57 Senior Vice President, Gas
Transmission

Terry M. Fleskes 46 Vice President and Controller

* As of December 31, 2002.

Except for Mr. Avery, each Executive Officer has been an officer or
employee of Sempra Energy or one of its subsidiaries for more than five
years. Prior to joining SDG&E in 2001, Mr. Avery was a consultant with
R.J. Rudden Associates. Except for Mr. Avery, each executive officer of
San Diego Gas & Electric Company holds the same position at Southern
California Gas Company.

ITEM 11. EXECUTIVE COMPENSATION

The information required by Item 11 is incorporated by reference from
"Election of Directors" and "Executive Compensation" in the Information
Statement prepared for the May 2003 annual meeting of shareholders.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The information required by Item 12 is incorporated by reference from
"Share Ownership" in the Information Statement prepared for the May
2003 annual meeting of shareholders.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

None.

ITEM 14. 9A.CONTROLS AND PROCEDURES.PROCEDURES
Company management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rules 13a-15(f). The company has designed and maintains disclosure controls and procedures to ensure that information required to be disclosed in the company's reports under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and is accumulated and communicated to the company's management, including its Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating these controls and procedures, management recognizes that any system of controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired objectives and necessarily applies judgment in evaluating the cost-benefit relationship of other possible controls and procedures. In addition,proce dures.
During the company has investments in
unconsolidated entitiesyear ended December 31, 2005, management outsourced certain human resource, payroll, and employee benefit functions to a third-party service provider, and implemented a new software application that it does not control or manageautomates the calculation of the income tax provision. The changes strengthen the design and consequently, its disclosureeffectiveness of the internal controls and procedures with respectimprove the efficiency of these systems. As part of the conversion processes, management performed substantial testing of related internal controls intended to provide reasonable assurances that the converted data and subsequent ongoing process meet the company's objective to provide reliable financial reporting. Management has determined that the design of the controls surrounding these entitiesnew processes satisfies the control objectives and that the controls are necessarily substantially more limited than those it
maintains with respectoperating effectively.
Except for these changes, there have been no changes in the company's internal controls over financial reporting during the company's most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, the company's internal controls over financial reporting.
The company evaluates the effectiveness of its consolidated subsidiaries.internal control over financial reporting based on the framework inInternal Control--Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. Under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer, the company within 90 days prior to the date of this report has
evaluated the effectiveness of the design and operation of the company's disclosure controls and procedures.procedures as of December 31, 2005, the end of the period covered by this report. Based on that evaluation, the company's Chief Executive Officer and Chief Financial Officer have
concluded that the company's disclosure controls and procedures are effective.

There have been no significant changeswere effective at the reasonable assurance level.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required on Identification of Directors is incorporated by reference from "Election of Directors" in the company's internal controlsInformation Statement prepared for the May 2006 annual meeting of shareholders. The information required on the companies' executive officers is set forth below.
EXECUTIVE OFFICERS OF THE REGISTRANT
Name Age* Position*
Edwin A. Guiles 56 Chairman and Chief Executive Officer
Debra L. Reed 49 President and Chief Operating Officer
James P. Avery 49 Senior Vice President, Electric
Steven D. Davis 50 Senior Vice President, External Relations and
Chief Financial Officer
William L. Reed 54 Senior Vice President, Regulatory and Strategic Planning
Anne S. Smith 52 Senior Vice President, Customer Service
Lee M. Stewart 60 Senior Vice President, Gas Operations
Robert M. Schlax 50 Vice President, Controller and Chief Accounting Officer
* As of February 22, 2006.
Except for Mr. Schlax, each executive officer has been an officer or in other factors that could significantly affect the internal controls
subsequentemployee of Sempra Energy or one of its subsidiaries for more than five years. Prior to the datejoining the company completed its evaluation.

85
in 2005, Mr. Schlax was Chief Financial Officer, Treasurer and Vice President of Finance of Mercury Air Group, Inc. Except for Mr. Avery, each executive officer of San Diego Gas & Electric Company holds the same position at Southern California Gas Company.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 is incorporated by reference from "Election of Directors" and "Executive Compensation" in the Information Statement prepared for the May 2006 annual meeting of shareholders.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Security Ownership of Certain Beneficial Owners
The security ownership information required by Item 12 is incorporated by reference from "Share Ownership" in the Information Statement prepared for the May 2006 annual meeting of shareholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information regarding principal accountant fees and services as required by Item 14 is incorporated by reference from "Proposal 3: Ratification of Independent Auditors" in the Information Statement prepared for the May 2006 annual meeting of shareholders.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K
(a) The following documents are filed as part of this report:
1. Financial statements
Page in
This Report
Independent Auditors' Report . . . . . . . . . . . . . . 40

Statements of Consolidated Income for the years
ended December 31, 2002, 2001 and 2000 . . . . . . . . 41

Consolidated Balance Sheets at December 31,
2002 and 2001. . . . . . . . . . . . . . . . . . . . . 42

Statements of Consolidated Cash Flows for the
years ended December 31, 2002, 2001 and 2000 . . . . . 44

Statements of Consolidated Changes in
Shareholders' Equity for the years ended
December 31, 2002, 2001 and 2000 . . . . . . . . . . . 45

Notes to Consolidated Financial Statements . . . . . . . 46

Page in
This Report
Management's Report on Internal Control over Financial Reporting 30
Reports of Independent Registered Public Accounting Firm 31
Statements of Consolidated Income for the years ended December 31, 2005, 2004 and 2003 34
Consolidated Balance Sheets at December 31, 2005 and 2004 35
Statements of Consolidated Cash Flows for the years ended December 31, 2005, 2004 and 2003 37
Statements of Consolidated Changes in Shareholders' Equity for the years ended December 31, 2005, 2004 and 2003 39
Notes to Consolidated Financial Statements 40
2. Financial statement schedules

Other schedules
Schedules for which provision is made in Regulation S-X are not required under the instructions contained therein, are inapplicable or the information is included in the Consolidated Financial Statements and notes thereto.
3. Exhibits
See Exhibit Index on page 8982 of this report.
(b) Reports on Form 8-K
The following reports on Form 8-K were filed after September 30, 2002:

None.

86
2005:
Current Report on Form 8-K filed November 2, 2005, including as exhibits Sempra Energy's press release of November 2, 2005, giving the financial results for the three months ended September 30, 2005, and related Income Statement Data by Business Unit.
Current Report on Form 8-K filed November 17, 2005, discussing the status of the company's energy crisis era legal proceedings.
Current Report on Form 8-K filed November 17, 2005, discussing the company's $250 million bond offering.
Current Report on Form 8-K filed November 23, 2005, discussing the status of an action filed by the Attorney General of California against the company.
Current Report on Form 8-K filed January 5, 2006, announcing the agreement to settle certain litigation and the effect of the settlements on the company's results of operations and financial condition for the year ended December 31, 2005.
Current Report on Form 8-K filed February 22, 2006, including as exhibits Sempra Energy's press release of February 22, 2006, giving the financial results for the three months ended December 31, 2005, and related Income Statement Data by Business Unit.

CONSENT OF INDEPENDENT AUDITORS' CONSENT
REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of San Diego Gas & Electric Company:
We consent to the incorporation by reference in Registration Statement Numbers 33-45599, 33-52834, 333-52150 and 33-49837 on Form S-3 of our reportreports dated February 14, 2003,21, 2006 relating to the financial statements of San Diego Gas and Electric Company (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the Company's adoption of Financial Accounting Standards Board Interpretation No. 47,Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143,effective December 31, 2005) and management's report on the effectiveness of internal control over financial reporting, appearing in and incorporated by reference in this Annual Report on Form 10-K of San Diego Gas and Electric Company for the year ended December 31, 2002.

/S/2005.
/S/ DELOITTE & TOUCHE LLP

San Diego, California
February 25, 2003

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be
signed on its behalf by the undersigned, hereunto duly authorized.

SAN DIEGO GAS & ELECTRIC COMPANY

21, 2006

SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
SAN DIEGO GAS & ELECTRIC COMPANY,
(Registrant)
By: /s/ Edwin A. Guiles

Edwin A. Guiles
Chairman and Chief Executive Officer

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

Name/Title Signature Date

Principal Executive Officer: Edwin A. Guiles
Edwin A. Guiles
Chairman and Chief Executive Officer /s/
Pursuant to the requirements of the Securities Exchange Act of 1934, this report is signed below by the following persons on behalf of the Registrant in the capacities and on the dates indicated.
Name/Title Signature Date
Principal Executive Officer:
Edwin A. Guiles
Chairman and Chief Executive Officer

/s/ Edwin A. Guiles

February 17, 2003

13, 2006
Principal Financial Officer:
Debra L. Reed
Steven D. Davis
Senior Vice President, External Relations
and Chief Financial Officer /s/ Debra L. Reed

/s/ Steven D. Davis

February 17, 2003

13, 2006
Principal Accounting Officer:
Terry
Robert M. Fleskes
Schlax
Vice President, and
Controller /s/ Terryand
Chief Accounting Officer

/s/ Robert M. Fleskes Schlax

February 17, 2003

13, 2006
Directors:
Edwin A. Guiles, Chairman /s/ /s/ Edwin A. Guiles February 17, 2003

13, 2006
Debra L. Reed, Director /s/ /s/ Debra L. Reed February 17, 2003

13, 2006
Frank H. Ault, Director /s/ /s/ Frank H. Ault February 17, 2003
13, 2006

EXHIBIT INDEX
The Forms S-8, 8-K, 10-K and 10-Q referred to herein were filed under Commission File Number 1-3779 (SDG&E), Commission File Number 1-11439 (Enova Corporation,Corporation), Commission File Number 1-14201 (Sempra Energy) and/or Commission File Number 333-30761, (SDG&E Funding LLC).
Exhibit 1 -- Underwriting Agreements
1.01 Underwriting Agreement dated December 4, 1997 (Incorporated by reference from
Form 8-K filed by SDG&E Funding LLC on December 23, 1997 (Exhibit 1.1)).
Exhibit 3 -- Bylaws and Articles of Incorporation
Bylaws
3.01 Restated Bylaws of San Diego Gas & Electric as of November 6, 2001. (2001 Form 10-K Exhibit 3.01)
Articles of Incorporation
3.02 Amended and Restated Articles of Incorporation of San Diego Gas & Electric Company (Incorporated by reference from the SDG&E Form 10-Q for the three months ended March 31, 1994 (Exhibit 3.1)).
Exhibit 4 -- Instruments Defining the Rights of Security Holders, Including Indentures
The Companycompany agrees to furnish a copy of each such instrument to the Commission upon request.
4.01 Mortgage and Deed of Trust dated July 1, 1940. (Incorporated by reference from SDG&E Registration Statement No. 2-49810, Exhibit 2A.).
4.02 Second Supplemental Indenture dated as of March 1, 1948. (Incorporated by reference from SDG&E Registration Statement No. 2-49810, Exhibit 2C.)

2C).
4.03 Ninth Supplemental Indenture dated as of August 1, 1968. (Incorporated by reference from SDG&E Registration Statement No. 2-68420, Exhibit 2D.)

2D).
4.04 Tenth Supplemental Indenture dated as of December 1, 1968. (Incorporated by reference from SDG&E Registration Statement No. 2-36042, Exhibit 2K.)

2K).
4.05 Sixteenth Supplemental Indenture dated August 28, 1975. (Incorporated by reference from SDG&E Registration Statement No. 2-68420, Exhibit 2E.)

2E).
4.06 Thirtieth Supplemental Indenture dated September 28, 1983. (Incorporated by reference from SDG&E Registration Statement No. 33-34017, Exhibit 4.3.)

4.3).
4.07 Forty-Ninth Supplemental Indenture dated June 1, 2004. (2004 Sempra Energy Form 10-K, Exhibit 4.07).
4.08 Fiftieth Supplemental Indenture Dated as of May 19, 2005. (8-K filed on May 19, 2005, Exhibit 4.1).
4.09 Fifty-First Supplemental Indenture Dated as of November 17, 2005. (8-K filed on November 17, 2005, Exhibit 4.1).
Exhibit 10 -- Material Contracts
10.01 Restated LetterForm of Continental Forge and California Class Action Price Reporting Settlement Agreement dated as of January 4, 2006 (8-K filed on January 5, 2006, Exhibit 99.1)
10.02 Form of Nevada Antitrust Settlement Agreement dated as of January 4, 2006 (8-K filed on January 5, 2006, Exhibit 99.2)
10.03 Text of Stipulation in Continental Forge Litigation (8-K filed on September 9, 2005, Exhibit 99.1)
10.04 San Diego Gas & Electric Underwriting Agreement dated November 14, 2005 (8-K filed on November 17, 2005, Exhibit 1.1)
10.05 San Diego Gas & Electric Pricing Agreement dated November 14, 2005 (8-K filed on November 17, 2005, Exhibit 1.2)
10.06 Operating Agreement between San Diego Gas & Electric
Company and the California Department of Water Resources dated April 5, 2001 (200117, 2003 (2003 Sempra Energy Form 10-K, Exhibit 10.04)10.06).

10.02
10.07 Servicing Agreement between San Diego Gas & Electric and the California Department of Water Resources dated December 19, 2002 (2003 Sempra Energy Form 10-K, Exhibit 10.07).
10.08 Transition Property Purchase and Sale Agreement dated December 16, 1997 (Incorporated by reference from Form 8-K filed by SDG&E Funding LLC on December 23, 1997, Exhibit 10.1).

10.03
10.09 Transition Property Servicing Agreement dated December 16, 1997 (Incorporated by reference from Form 8-K filed by SDG&E Funding LLC on December 23, 1997, Exhibit 10.2).
Compensation
10.10 Form of Severance Pay Agreement (2004 Sempra Energy 10-K, Exhibit 10.10).
10.11 Sempra Energy 2005 Deferred Compensation 10.04Plan (San Diego Gas & Electric Form 8-K filed on December 07, 2004, Exhibit 10.1).
10.12 Sempra Energy Employee Stock Incentive Plan (September 30, 2004 Sempra Energy Form 10-Q, Exhibit 10.1).
10.13 Sempra Energy Amended and Restated Executive Life Insurance Plan (September 30, 2004 Sempra Energy Form 10-Q, Exhibit 10.2).
10.14 Sempra Energy Excess Cash Balance Plan (September 30, 2004 Sempra Energy Form 10-Q, Exhibit 10.3).
10.15 Form of Sempra Energy 1998 Long Term Incentive Plan Performance-Based Restricted Stock Award (September 30, 2004 Sempra Energy Form 10-Q, Exhibit 10.4).
10.16 Form of Sempra Energy 1998 Long Term Incentive Plan Nonqualified Stock Option Agreement (September 30, 2004 Sempra Energy Form 10-Q, Exhibit 10.5).
10.17 Form of Sempra Energy 1998 Non-Employee Directors' Stock Plan Nonqualified Stock Option Agreement (September 30, 2004 Sempra Energy Form 10-Q, Exhibit 10.6).
10.18 Sempra Energy Supplemental Executive Retirement Plan (September 30, 2004 Sempra Energy Form 10-Q, Exhibit 10.7).
10.19 Neal Schmale Restricted Stock Award Agreement (September 30, 2004 Sempra Energy Form 10-Q, Exhibit 10.8).
10.20 Severance Pay Agreement between Sempra Energy and Donald E. Felsinger (September 30, 2004 Sempra Energy Form 10-Q, Exhibit 10.9).
10.21 Severance Pay Agreement between Sempra Energy and Neal Schmale (September 30, 2004 Sempra Energy Form 10-Q, Exhibit 10.10).
10.22 Sempra Energy Executive Personal Financial Planning Program Policy Document (September 30, 2004 Sempra Energy Form 10-Q, Exhibit 10.11).
10.23 2003 Sempra Energy Executive Incentive Plan B (2003 Sempra Energy Form 10-K, Exhibit 10.10).
10.24 Sempra Energy 2003 Executive Incentive Plan (June 30, 2003 Sempra Energy Form 10-Q Exhibit 10.1)
10.25 Amended 1998 Long-Term Incentive Plan (June 30, 2003 Sempra Energy Form 10-Q Exhibit 10.2)
10.26 Sempra Energy Executive Incentive Plan effective January 1, 2003 (2002 Sempra Energy Form 10-K, Exhibit 10.09).

10.05
10.27 Amended Sempra Energy Retirement Plan for Directors (2002 Sempra Energy Form 10-K, Exhibit 10.10).

10.06
10.28 Amended and Restated Sempra Energy Deferred Compensation and Excess Savings Plan (Sempra Energy September(September 30, 2002 Sempra Energy Form 10-Q, Exhibit 10.3).

10.07
10.29 Form of Sempra Energy Severance Pay Agreement for Executives (2001 Sempra Energy Form 10-K, Exhibit 10.07).

10.08
10.30 Sempra Energy Executive Security Bonus Plan effective January 1, 2001 (2001 Sempra Energy Form 10-K, Exhibit 10.08).

10.09
10.31 Sempra Energy Deferred Compensation and Excess Savings Plan effective January 1, 2000 (2000 Sempra Energy Form 10-K, Exhibit 10.07).

10.10
10.32 Sempra Energy 1998 Long Term Incentive Plan (Incorporated by reference from the Registration Statement on Form S-8 Sempra Energy Registration Statement No. 333-56161 dated June 5, 1998(Exhibit1998 (Exhibit 4.1)).
Financing
10.11
10.33 Loan agreement with the City of Chula Vista in connection with the issuance of $25 million of Industrial Development Bonds, dated as of October 1, 1997 (Enova 1997(1997 Enova Corporation Form 10-K, Exhibit 10.34).

10.12
10.34 Loan agreement with the City of Chula Vista in connection with the issuance of $38.9 million of Industrial Development Bonds, dated as of August 1, 1996 (1996 Form 10-K, Exhibit 10.31).

10.13
10.35 Loan agreement with the City of Chula Vista in connection with the issuance of $60 million of Industrial Development Bonds, dated as of November 1, 1996 (1996 Form 10-K, Exhibit 10.32).

10.14 Loan agreement with City of San Diego in connection with
the issuance of $57.7 million of Industrial Development
Bonds, dated as of June 1, 1995 (June 30, 1995 SDG&E
Form 10-Q, Exhibit 10.3).

10.15
10.36 Loan agreement with the City of San Diego in connection with the issuance of $92.9 million of Industrial Development Bonds 1993 Series C dated as of July 1, 1993 (June 30, 1993 SDG&E Form 10-Q, Exhibit 10.2).

10.16
10.37 Loan agreement with the City of San Diego in connection with the issuance of $70.8 million of Industrial Development Bonds 1993 Series A dated as of April 1, 1993 (March 31, 1993 SDG&E Form 10-Q, Exhibit 10.3).

10.17 Loan agreement with the City of San Diego in connection with
the issuance of $118.6 million of Industrial Development
Bonds dated as of September 1, 1992 (Sept. 30, 1992 SDG&E
Form 10-Q, Exhibit 10.1).

10.18
10.38 Loan agreement with the City of Chula Vista in connection with the issuance of $250 million of Industrial Development Bonds, dated as of December 1, 1992 (1992 SDG&E Form 10-K, Exhibit 10.5).

10.19
10.39 Loan agreement with the California Pollution Control Financing Authority in connection with the issuance of $129.82 million of Pollution Control Bonds, dated as of June 1, 1996 (1996 Form 10-K, Exhibit 10.41).

10.20
10.40 Loan agreement with the California Pollution Control Financing Authority in connection with the issuance of $60 million of Pollution Control Bonds dated as of June 1, 1993 (June 30, 1993 SDG&E Form 10-Q, Exhibit 10.1).

10.21
10.41 Loan agreement with the California Pollution Control Financing Authority dated as of December 1, 1991, in connection with the issuance of $14.4 million of Pollution Control Bonds, dated as of December 1, 1991 (1991 SDG&E Form 10-K, Exhibit 10.11).

Nuclear
10.22 Uranium enrichment services contract between
10.42 Loan agreement with the U.S.
DepartmentCity of Energy (DOE assigned its rights toChula Vista in connection with the U.S.
Enrichment Corporation, a U.S. government-owned corporation,
on July 1, 1993) and Southern California Edison Company,issuance of $251.3 million of Industrial Development Revenue Refunding Bonds, dated as agent for SDG&E and others; Contract DE-SC05-84UEO7541,
dated November 5, 1984, effectiveof June 1, 1984, as amended
(1991 SDG&E2004 (2004 Sempra Energy Form 10-K, Exhibit 10.9)10.43).

10.23
Nuclear
10.43 Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station, approved November 25, 1987 (1992 SDG&E Form 10-K, Exhibit 10.7).

10.24
10.44 Amendment No. 1 to the Qualified CPUC Decommissioning Master Trust Agreement dated September 22, 1994 (see Exhibit 10.23
herein)10.43 above)(1994 SDG&E Form 10-K, Exhibit 10.56).

10.25
10.45 Second Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.23 herein)10.43 above)(1994 SDG&E Form 10-K, Exhibit 10.57).

10.26
10.46 Third Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.23 herein)10.43 above)(1996 Form 10-K, Exhibit 10.59).

10.27
10.47 Fourth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.23 herein)10.43 above)(1996 Form 10-K, Exhibit 10.60).

10.28
10.48 Fifth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.23 herein)10.43 above)(1999 Form 10-K, Exhibit 10.26).

10.29
10.49 Sixth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.23 herein)10.43 above)(1999 Form 10-K, Exhibit 10.27).

10.30
10.50 Seventh Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.43 above)(2003 Sempra Energy Form 10-K, Exhibit 10.42).
10.51 Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station, approved November 25, 1987 (1992 SDG&E Form 10-K, Exhibit 10.8).

10.31
10.52 First Amendment to the San Diego Gas & Electric Company Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.30 herein)10.51 above)(1996 Form 10-K, Exhibit 10.62).

10.32
10.53 Second Amendment to the San Diego Gas & Electric Company Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.30 herein)10.51 above)(1996 Form 10-K, Exhibit 10.63).

10.33
10.54 Third Amendment to the San Diego Gas & Electric Company Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.30 herein)10.51 above)(1999 Form 10-K, Exhibit 10.31).

10.34
10.55 Fourth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.30 herein)10.51 above)(1999 Form 10-K, Exhibit 10.32).

10.35
10.56 Fifth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.51 above)(2003 Sempra Energy Form 10-K, Exhibit 10.48).
10.57 Second Amended San Onofre Operating Agreement among Southern California Edison Company, SDG&E, the City of Anaheim and the City of Riverside, dated February 26, 1987 (1990 SDG&E Form 10-K, Exhibit 10.6).

10.36
10.58 U. S. Department of Energy contract for disposal of spent nuclear fuel and/or high-level radioactive waste, entered into between the DOE and Southern California Edison Company, as agent for SDG&E and others; Contract DE-CR01-83NE44418, dated June 10, 1983 (1988 SDG&E Form 10-K, Exhibit 10N).

92
Natural Gas Transportation and Storage
10.37 Master Services Contract, Schedule J, Transaction Based Storage
Service Agreement dated April 1, 2002 and expiring March 31,
2003 between San Diego Gas & Electric Company and Southern
California Gas Company.

10.38 Master Services Contract (Intrastate Transmission Service),
dated July 1, 1998 (month to month) between San Diego Gas &
Electric Company and Southern California Gas Company.
(1998 10-K, Exhibit 10.64)

10.39
10.59 Amendment to Firm Transportation Service Agreement, dated December 2, 1996, between Pacific Gas and Electric Company and San Diego Gas & Electric Company (1997 Enova Corporation Form 10-K, Exhibit 10.58).

10.40
10.60 Firm Transportation Service Agreement, dated December 31, 1991 between Pacific Gas and Electric Company and San Diego Gas & Electric Company (1991 SDG&E Form 10-K, Exhibit 10.7).

10.41
10.61 Firm Transportation Service Agreement, dated October 13, 1994 between Pacific Gas Transmission Company (succeeded by TransCanada Pipelines - GTN Systems) and San Diego Gas & Electric Company (1997 Enova Corporation Form 10-K, Exhibit 10.60).
Other
10.42
10.62 Lease agreement dated as of March 25, 1992 with CarrAmerica Development and Construction as lessor of an office complex at Century Park (1994 SDG&E Form 10-K, Exhibit 10.70).
Exhibit 12 -- Statement Re: Computation Of Ratios
12.01 Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends for the years ended December 31, 2005, 2004, 2003, 2002 2001, 2000, 1999 and 1998.

2001.
Exhibit 21 --- Subsidiaries
21.01 Schedule of Subsidiaries at December 31, 2002.

2005.
Exhibit 23 --- Consent of Independent Auditors' Consent,Registered Public Accounting Firm, page 87.

GLOSSARY

AB X1 A California Assembly bill authorizing the
California Department of Water Resources to
purchase energy for California consumers.

AB California Assembly Bill

AFUDC Allowance for Funds Used During Construction

ALJ Administrative Law Judge

BCAP Biennial Cost Allocation Proceeding

Bcf Billion Cubic Feet (of natural gas)

CEC California Energy Commission

COS Cost of Service

CPUC California Public Utilities Commission

DA Direct Access

DOE Department of Energy

DSM Demand Side Management

DWR Department of Water Resources

Edison Southern California Edison Company

EITF Emerging Issues Task Force

EMFs Electric and Magnetic Fields

Enova Enova Corporation

ERMG Energy Risk Management Group

EPA Environmental Protection Agency

FASB Financial Accounting Standards Board

FERC Federal Energy Regulatory Commission

ICIP Incremental Cost Incentive Pricing mechanism

Intertie Pacific Intertie

IOUs Investor-Owned Utilities

ISO Independent System Operator

kWh Kilowatt Hour

LIFO Last-in first-out inventory costing method

mmbtu Million British Thermal Units (of natural gas)

MOU Memorandum of Understanding

mW Megawatt

NRC Nuclear Regulatory Commission

ORA Office of Ratepayers Advocates

Parent Enova Corporation

PBR Performance-Based Ratemaking/Regulation

PE Pacific Enterprises

PG&E Pacific Gas and Electric Company

PGA Purchased Gas Balancing Account

PGE Portland General Electric Company

PRP Potentially Responsible Party

PX Power Exchange

QFs Qualifying Facilities

RD&D Research, Development and Demonstration

ROE Return on Equity

ROR Rate of Return

S&P Standard & Poor's

SB California Senate Bill

SDG&E San Diego Gas & Electric Company

SEC Securities and Exchange Commission

SFAS80.
Exhibit 31 -- Section 302 Certifications
31.1 Statement of Financial Accounting Standards

SoCalGas Southern California Gas Company

SONGS San Onofre Nuclear Generating Station

Southwest Powerlink A transmission line connecting San DiegoRegistrant's Chief Executive Officer pursuant to
Phoenix and intermediate points.

TCBA Transition Cost Balancing Account

TURN The Utility Reform Network

UEG Utility Electric Generation

VaR Value at Risk

CERTIFICATIONS

I, Edwin A. Guiles, certify that:

1. I have reviewed this Annual Report on Form 10-K of San Diego Gas &
Electric Company;

2. Based on my knowledge, this Annual Report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect
to the period covered by this Annual Report;

3. Based on my knowledge, the financial statements and other financial
information included in this Annual Report fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented
in this Annual Report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:

a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
Annual Report is being prepared;

b) evaluated the effectiveness15d-14 of the registrant's disclosure
controlsSecurities Exchange Act of 1934.
31.2 Statement of Registrant's Chief Financial Officer pursuant to Rules 13a-14 and procedures as of a date within 90 days prior to the
filing date of this Annual Report (the "Evaluation Date"); and

c) presented in this Annual Report our conclusions about the
effectiveness15d-14 of the disclosure controls and procedures based on
our evaluation asSecurities Exchange Act of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors
and the audit committee1934.
Exhibit 32 -- Section 906 Certifications
32.1 Statement of registrant's board of directors (or
persons performing the equivalent function):

a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and

6. The registrant's other certifying officers and I have indicated in
this Annual Report whether or not there were significant changes in
internal controls or in other factors that could significantly
affect internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.

February 26, 2003

/s/ Edwin A. Guiles
Edwin A. GuilesRegistrant's Chief Executive Officer 96

I, Debra L. Reed, certify that:

1. I have reviewed this Annual Report on Form 10-Kpursuant to 18 U.S.C. Sec. 1350.
32.2 Statement of San Diego Gas &
Electric Company;

b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this Annual Report (the "Evaluation Date"); and

c) presented in this Annual Report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors
and the audit committee of registrant's board of directors (or
persons performing the equivalent function):

b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and

February 26, 2003

/s/ Debra L. Reed
Debra L. ReedRegistrant's Chief Financial Officer 97

pursuant to 18 U.S.C. Sec. 1350.

GLOSSARY
AFUDC Allowance for Funds Used During Construction
ALJ Administrative Law Judge
APBO Accounting Principles Board Opinion
ARB Accounting Research Bulletin
BCAP Biennial Cost Allocation Proceeding
California Utilities Southern California Gas Company and San Diego Gas& Electric
Calpine Calpine Corporation
CEC California Energy Commission
CEMA Catastrophic Event Memorandum Act
CPI Consumer Price Index
CPUC California Public Utilities Commission
DOE Department of Energy
DSM Demand Side Management
DWR Department of Water Resources
Edison Southern California Edison Company
EITF Emerging Issues Task Force
El Paso El Paso Natural Gas Company
EMFs Electric and Magnetic Fields
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
FIN FASB Interpretation Number
GAAP Generally Accepted Accounting Principles
GIR Gas Industry Restructuring
IOUs Investor-Owned Utilities
IRS Internal Revenue Service
ISFSI Independent Spent Fuel Storage Facility
ISO Independent System Operator
LIFO Last in first out inventory costing method
mmbtu Million British Thermal Units (of natural gas)
MSCI Morgan Stanley Capital International
MW Megawatt
NRC Nuclear Regulatory Commission
OIR Order Instituting Ratemaking
OMPPA Otay Mesa Power Purchase Agreement
PBR Performance-Based Ratemaking/Regulation
PG&E Pacific Gas and Electric Company
PGE Portland General Electric Company
PIER Public Interest Energy Research
PRP Potentially Responsible Party
PX Power Exchange
QF Qualifying Facility
RD&D Research Development and Demonstration
RMC Risk Management Committee
RMD Risk Management Department
ROE Return on Equity
SDG&E San Diego Gas & Electric Company
SFAS Statement of Financial Accounting Standards
SoCalGas Southern California Gas Company
SONGS San Onofre Nuclear Generating Station
VaR Value at Risk
VIE Variable Interest Entity

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


[ ]	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		1-3779

SAN DIEGO GAS & ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)
	California		95-1184800

	(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
8326 Century Park Court, San Diego, California 92123

(Address of principal executive offices) (Zip Code)
(619) 696-2000

(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

	Preference Stock (Cumulative) Without Par Value (except $1.70 and $1.7625 Series) Cumulative Preferred Stock, $20 Par Value (except 4.60% Series)		American American

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:				None

			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.
								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):

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).
			Yes				No	X

Exhibit Index on page 82. Glossary on page 89.

Aggregate market value of the voting stock held by non-affiliates of the registrant as of June 30, 2005 was $24.6 million.

Registrant's common stock outstanding as of January 31, 2006 was wholly owned by Enova Corporation.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the Information Statement prepared for the May 2006 annual meeting of shareholders are incorporated by reference into Part III.


TABLE OF CONTENTS		Page

PART I
Item 1.	Business and Risk Factors	4
Item 2.	Properties	15
Item 3.	Legal Proceedings	15
Item 4.	Submission of Matters to a Vote of Security Holders	16

PART II
Item 5.	Market for Registrant's Common Equity and Related Stockholder Matters	16
Item 6.	Selected Financial Data	16
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	17
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	29
Item 8.	Financial Statements and Supplementary Data	30
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures	76
Item 9A.	Controls and Procedures	76

PART III
Item 10.	Directors and Executive Officers of the Registrant	77
Item 11.	Executive Compensation	77
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	77
Item 13.	Certain Relationships and Related Transactions	77
Item 14.	Principal Accountant Fees and Services	78

PART IV
Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	78

Consent of Independent Registered Public Accounting Firm		80

Signatures		81

Exhibit Index		82

Glossary		89

Supplier		Source	Expiration date	Megawatts (MW)
Supplier		Source	Expiration date	Megawatts (MW)


PURCHASED POWER CONTRACTS:

DWR ** -allocated contracts:
	Williams Energy Marketing & Trading	Natural gas	2007 to 2010	1,906	*
	Sunrise Power Co. LLC	Natural gas	2012	574
	Other	Natural gas / wind	2006 to 2013	227

	Total			2,707

Other contracts with Qualifying Facilities (QFs):
	Applied Energy Inc.	Cogeneration	2019	102
	Yuma Cogeneration	Cogeneration	2024	50
	Goal Line Limited Partnership	Cogeneration	2025	50
	Other (16 contracts)	Cogeneration	2009 and thereafter	61

	Total			263

Other contracts with renewable sources:
	Oasis Power Partners	Wind	2019	60
	AES Delano	Bio-mass	2007	49
	PPM Energy	Wind	2018	25
	WTE / FPL	Wind	2019	17
	Other (6 contracts)	Bio-gas	2007-2014	24

	Total			175

Other long-term contracts:
	Portland General Electric (PGE)	Coal	2013	89

Total contracted				3,234


GENERATION:
	SONGS			430
	Miramar			47

Total Generation				477

TOTAL CONTRACTED AND GENERATION				3,711

(Dollars in millions, except per share amounts)			At December 31, or for the years then ended

			2005		2004		2003		2002		2001

Income Statement Data:
	Operating revenues	$	2,512	$	2,274	$	2,308	$	1,725	$	2,359
	Operating income	$	283	$	256	$	388	$	256	$	241
	Dividends on preferred stock	$	5	$	5	$	6	$	6	$	6
	Earnings applicable to common shares	$	262	$	208	$	334	$	203	$	177

Balance Sheet Data:
	Total assets	$	7,492	$	6,834	$	6,461	$	6,285	$	6,542
	Long-term debt	$	1,455	$	1,022	$	1,087	$	1,153	$	1,229
	Short-term debt (a)	$	66	$	66	$	66	$	66	$	93
	Preferred stock subject to mandatory redemption (b)	$	--	$	--	$	--	$	25	$	25
	Shareholders' equity	$	1,562	$	1,376	$	1,343	$	1,223	$	1,165

	(a) Includes long-term debt due within one year. (b) At December 31, 2005 and 2004, $16 million and $19 million, respectively, were included in Deferred Credits and Other Liabilities, and $3 million and $2 million, respectively, were included in Other Current Liabilities on the Consolidated Balance Sheets.

(Dollars in millions)

2005		$ 267
2004		$ 213
2003		$ 340
2002		$ 209
2001		$ 183

	Net Income									Operating Income

(Dollars in millions)		2005			2004			2003			2005			2004			2003

Reported amounts	$	267		$	213		$	340		$	283		$	256		$	388

Unusual items:

Resolution of prior years' income tax issues (21)		(60	)		(12	)		(79	)		(60	)		(12	)		(79	)

Increase in California energy crisis litigation reserves (66)		28			11			11			28			11			11

South Bay charitable contribution deduction (21)		(23	)		--			--			(21	)		--			--

DSM¹ awards (62)		(22	)		--			--			(21	)		--			--

Other regulatory matters (66)		(23	)		(21	)		--			(20	)		(15	)		--

Power contract settlement		--			--			(65	)		--			--			(65	)

SONGS2 incentive pricing (ended 12/31/03)		--			--			(53	)		--			--			(53	)

	$	167		$	191		$	154		$	189		$	240		$	202

								Transportation and Exchange
			Natural Gas Sales					Transportation and Exchange					Total

			Volumes		Revenue			Volumes		Revenue			Volumes		Revenue

2005:
	Residential			31		$	381		--		$	--		31		$	381
	Commercial and industrial			17			174		4			5		21			179
	Electric generation plants			1			3		59			39		60			42

				49		$	558		63		$	44		112			602
	Balancing accounts and other																107

		Total														$	709

2004:
	Residential			33		$	332		--		$	--		33		$	332
	Commercial and industrial			18			142		4			4		22			146
	Electric generation plants			--			2		74			36		74			38

				51		$	476		78		$	40		129			516
	Balancing accounts and other																80

		Total														$	596

2003:
	Residential			32		$	291		--		$	--		32		$	291
	Commercial and industrial			17			127		4			5		21			132
	Electric generation plants			--			3		62			30		62			33

				49		$	421		66		$	35		115			456
	Balancing accounts and other																51

		Total														$	507

(Dollars in millions)		2006		2007 and 2008		2009 and 2010		Thereafter		Total

Long-term debt	$	66	$	66	$	--	$	1,389	$	1,521
Interest on debt (1)		78		145		152		1,687		2,062
Operating leases		19		29		17		19		84
Litigation reserve		25		50		--		--		75
Purchased-power contracts		247		536		565		2,627		3,975
Natural gas contracts		22		28		20		112		182
Preferred stock subject to mandatory redemption		3		16		--		--		19
Construction commitments		16		24		7		20		67
SONGS decommissioning		14		11		--		314		339
Other asset retirement obligations		4		9		5		105		123
Pension and postretirement benefit obligations (2)		41		106		89		257		493
Environmental commitments		9		9		--		--		18

Totals	$	544	$	1,029	$	855	$	6,530	$	8,958

	Standard & Poor's	Moody's Investor Services, Inc.	Fitch

Secured debt	A+	A1	AA
Unsecured debt	A-	A2	AA-
Preferred stock	BBB+	Baa1	A+
Commercial paper	A-1	P-1	F1+

				Years ended December 31,

				2005			2004			2003


Operating revenues
		Electric		$	1,803		$	1,678		$	1,801
		Natural gas			709			596			507

			Total operating revenues		2,512			2,274			2,308


Operating expenses
	Cost of electric fuel and purchased power				624			576			541
	Cost of natural gas				456			347			274
	Other operating expenses				603			574			611
	Depreciation and amortization				264			259			242
	Income taxes				110			137			127
	Franchise fees and other taxes				119			113			114
	Litigation expense				52			19			17
	Gain on sale of assets				(1	)		(1	)		(9	)
	Impairment losses (adjustments)				2			(6	)		3

			Total operating expenses		2,229			2,018			1,920


Operating income					283			256			388


Other income, net (Note 1)					58			25			25


Interest charges
		Long-term debt			65			61			67
		Other			12			10			11
		Allowance for borrowed funds used during construction			(3	)		(3	)		(5	)

			Total		74			68			73


Net income					267			213			340
Preferred dividend requirements					5			5			6

Earnings applicable to common shares				$	262		$	208		$	334

					December 31, 2005			December 31, 2004
					December 31, 2005			December 31, 2004


ASSETS
Utility plant, at original cost					$	6,927		$	6,345
Accumulated depreciation and amortization						(1,956	)		(1,821	)

		Utility plant, net				4,971			4,524


Nuclear decommissioning trusts						638			612


Current assets:
	Cash and cash equivalents					236			9
	Accounts receivable - trade					188			185
	Accounts receivable - other					83			30
	Interest receivable					17			55
	Due from unconsolidated affiliates					32			30
	Deferred income taxes					7			--
	Regulatory assets arising from fixed-price contracts					76			55
				and other derivatives		76			55
	Other regulatory assets					91			77
	Inventories					78			88
	Other					39			31

			Total current assets			847			560


Other assets:
	Deferred taxes recoverable in rates					294			278
	Regulatory assets arising from fixed-price contracts					398			448
				and other derivatives		398			448
	Other regulatory assets					276			341
	Sundry					68			71

			Total other assets			1,036			1,138

Total assets					$	7,492		$	6,834

	Comprehensive Income		Preferred Stock Not Subject to Mandatory Redemption	Common Stock		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total Shareholders' Equity

Balance at December 31, 2002			$ 79	$ 943		$ 235		$ (34	)	$ 1,223
Net income	$ 340					340				340
Other comprehensive income adjustment - pension	(9	)						(9	)	(9	)

Comprehensive income	$ 331

Preferred stock dividends declared						(6	)			(6	)
Common stock dividends declared						(200	)			(200	)
Capital contribution				(5	)					(5	)

Balance at December 31, 2003			79	938		369		(43	)	1,343
Net income	$ 213					213				213
Other comprehensive income adjustment - pension	30							30		30

Comprehensive income	$ 243

Preferred stock dividends declared						(5	)			(5	)
Common stock dividends declared						(205	)			(205	)

Balance at December 31, 2004			79	938		372		(13	)	1,376
Net income	$ 267					267				267
Other comprehensive income adjustment - pension	(1	)						(1	)	(1	)

Comprehensive income	$ 266

Preferred stock dividends declared						(5	)			(5	)
Common stock dividends declared						(75	)			(75	)

Balance at December 31, 2005			$ 79	$ 938		$ 559		$ (14	)	$ 1,562

		Utility Plant at December 31,				Depreciation rates for years ended December 31,


(Dollars in billions)		2005		2004		2005		2004		2003

Natural gas operations		$	1.1	$	1.0	3.42	%	3.42	%	3.63	%
Electric distribution			3.5		3.4	4.13	%	4.11	%	4.70	%
Electric transmission			1.1		1.0	3.05	%	3.06	%	3.09	%
Other electric			0.6		0.6	9.75	%	11.33	%	9.53	%
Construction work in progress			0.6		0.3	NA		NA		NA

	Total	$	6.9	$	6.3

	2005			2004

Balance as of January 1	$	339	*	$	326	*
Adoption of FIN 47		116			--
Accretion expense		23			23
Payments		(15	)		(10	)

Balance as of December 31	$	463	*	$	339	*


			December 31,
(Dollars in millions)			2005			2004

First mortgage bonds
	6.8% June 1, 2015	$	14		$	14
	5.3% November 15, 2015		250			--
	5.9% June 1, 2018		68			68
	5.9% September 1, 2018		93			93
	5.85% June 1, 2021		60			60
	5% to 5.25% December 1, 2027		150			150
	2.516% to 2.832%* January and February 2034		176			176
	5.35% May 15, 2035		250			--
	2.8275%* May 1, 2039		75			75

			1,136			636

Rate-reduction bonds, 6.31% to 6.37% at December 31, 2005 payable
	through 2007		132			198

Other bonds
	5.9% June 1, 2014		130			130
	5.3% July 1, 2021		39			39
	5.5% December 1, 2021		60			60
	4.9% March 1, 2023		25			25

			254			254

			1,522			1,088

Current portion of long-term debt			(66	)		(66	)
Unamortized discount on long-term debt			(1	)		--

Total		$	1,455		$	1,022

(Dollars in millions)	SONGS	Southwest Powerlink

Percentage ownership	20%	91%
Utility plant in service	$ 39	$ 290
Accumulated depreciation and amortization	$ 2	$ 156
Construction work in progress	$ 21	$ 9

			December 31,

(Dollars in millions)	Maturity dates		2005		2004

Municipal bonds	2006 - 2034	$	54	$	45
U.S. government issues	2006 - 2038		222		209
Cash and other securities	2006 - 2033		35		55
Equity securities			327		303

Total		$	638	$	612

	Pension Benefits						Other Postretirement Benefits
	Pension Benefits						Other Postretirement Benefits

(Dollars in millions)		2005			2004			2005			2004

CHANGE IN PROJECTED BENEFIT OBLIGATION:
Net obligation at January 1	$	719		$	662		$	85		$	76
Service cost		10			9			3			3
Interest cost		42			41			5			5
Plan amendments		--			--			52			--
Actuarial loss (gain)		33			40			(19	)		6
Transfer of liability from Sempra Energy		35			28			2			--
Benefit payments		(52	)		(61	)		(4	)		(5	)

Net obligation at December 31		787			719			124			85


CHANGE IN PLAN ASSETS:
Fair value of plan assets at January 1		569			538			39			34
Actual return on plan assets		44			65			2			2
Employer contributions		21			20			7			8
Transfer of assets from Sempra Energy		34			7			--			--
Benefit payments		(52	)		(61	)		(4	)		(5	)

Fair value of plan assets at December 31		616			569			44			39

Benefit obligation, net of plan assets at December 31		(171	)		(150	)		(80	)		(46	)
Unrecognized net actuarial loss		138			94			1			19
Unrecognized prior service cost		4			7			46			(7	)

Net recorded liability at December 31	$	(29	)	$	(49	)	$	(33	)	$	(34	)

WEIGHTED-AVERAGE ASSUMPTIONS USED
	TO DETERMINE NET PERIODIC BENEFIT
	COSTS FOR YEARS ENDED DECEMBER 31:
Discount rate		5.66%	6.00%	5.66%	6.00%
Expected return on plan assets		7.50%	7.50%	4.61%	4.76%
Rate of compensation increase		4.50%	4.50%	4.50%	4.50%

		2005			2004

ASSUMED HEALTH CARE COST
	TREND RATES AT DECEMBER 31:
Health-care cost trend rate		9.78	%	*	19.00	%	*
Rate to which the cost trend rate is assumed to
	decline (the ultimate trend)	5.50	%		5.50	%
Year that the rate reaches the ultimate trend		2008			2008

(Dollars in millions)		1% Increase		1% Decrease

Effect on total of service and interest cost components of net
	periodic postretirement health-care benefit cost	$	1	$	(1	)

Effect on the health-care component of the accumulated other
	postretirement benefit obligation	$	7	$	(6	)

		Target Allocation		Percentage of Plan Assets at December 31,
		Target Allocation		Percentage of Plan Assets at December 31,

Asset Category		2006		2005		2004


U.S. Equity		45	%	44	%	45	%
Foreign Equity		25		27		32
Fixed Income		30		29		23

	Total	100	%	100	%	100	%

	2005					2004
		Carrying			Fair		Carrying			Fair
(Dollars in millions)		Amount			Value		Amount			Value

Total long-term debt	$	1,522		$	1,544	$	1,088		$	1,179

Preferred stock of subsidiaries	$	98	*	$	96	$	100	*	$	100

					Call/
			Redemption			December 31,
					Price	2005		2004

Not subject to mandatory redemption:							(in millions)
	$20 par value, authorized 1,375,000 shares:
		5% Series, 375,000 shares outstanding		$	24.00	$	8	$	8
		4.5% Series, 300,000 shares outstanding		$	21.20		6		6
		4.4% Series, 325,000 shares outstanding		$	21.00		7		7
		4.6% Series, 373,770 shares outstanding		$	20.25		7		7
	Without par value:
		$1.70 Series, 1,400,000 shares outstanding		$	25.85		35		35
		$1.82 Series, 640,000 shares outstanding		$	26.00		16		16

		Total				$	79	$	79


Subject to mandatory redemption:
	Without par value: $1.7625 Series, 750,000 and 850,000
	shares outstanding at December 31, 2005
	and December 31, 2004, respectively			$	25.00	$	19*	$	21*

	Quarters ended
(Dollars in millions)	March 31		June 30		September 30			December 31

2005
Operating revenues	$	621	$	539		$	601		$	751
Operating expenses		553		487			497			692

Operating income	$	68	$	52		$	104		$	59


Net income	$	60	$	30		$	104		$	73
Dividends on preferred stock		1		1			2			1

Earnings applicable to common shares	$	59	$	29		$	102		$	72

2004
Operating revenues	$	580	$	536		$	550		$	608
Operating expenses		518		488			486			526

Operating income	$	62	$	48		$	64		$	82


Net income	$	51	$	31		$	62		$	69
Dividends on preferred stock		1		1			2			1

Earnings applicable to common shares	$	50	$	30		$	60		$	68

Name	Age*	Position*

Edwin A. Guiles	56	Chairman and Chief Executive Officer
Debra L. Reed	49	President and Chief Operating Officer
James P. Avery	49	Senior Vice President, Electric
Steven D. Davis	50	Senior Vice President, External Relations and Chief Financial Officer
William L. Reed	54	Senior Vice President, Regulatory and Strategic Planning
Anne S. Smith	52	Senior Vice President, Customer Service
Lee M. Stewart	60	Senior Vice President, Gas Operations
Robert M. Schlax	50	Vice President, Controller and Chief Accounting Officer


	Page in This Report
	Page in This Report


Management's Report on Internal Control over Financial Reporting	30

Reports of Independent Registered Public Accounting Firm	31

Statements of Consolidated Income for the years ended December 31, 2005, 2004 and 2003	34

Consolidated Balance Sheets at December 31, 2005 and 2004	35

Statements of Consolidated Cash Flows for the years ended December 31, 2005, 2004 and 2003	37

Statements of Consolidated Changes in Shareholders' Equity for the years ended December 31, 2005, 2004 and 2003	39

Notes to Consolidated Financial Statements	40