SAN DIEGO GAS & ELECTRIC CO - 10-K Annual Report

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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
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SAN DIEGO GAS & ELECTRIC COMPANY
- ---------------------------------------------------------------------
(Exact name of registrant as specified in its charter)

CALIFORNIA 1-3779 95-1184800
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(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
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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.

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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

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 California
Public Utilities Commission (CPUC), the California Legislature, the
California Department of Water Resources (DWR), and the Federal Energy
Regulatory Commission (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.

PART I

ITEM 1. BUSINESS

Description of Business

A description of San Diego Gas & Electric (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's website address is http://www.sempra.com/investor.htm. 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

SDG&E has electric franchises 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 allow SDG&E to locate facilities for the transmission
and distribution of electricity and/or natural gas in the streets and
other public places. The franchises do not have fixed terms, except for
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 State of California Legislature, from time to time, passes laws
that regulate SDG&E's operations. For example, in 1996 the legislature
passed an electric industry deregulation bill, and in subsequent years
passed additional bills aimed at addressing problems in the deregulated
electric industry. In addition, the legislature enacted a law in 1999
addressing natural gas industry restructuring.

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 utilities with their holding companies and is currently conducting
an investigation into this relationship.

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 CPUC are currently investigating prices charged to the
California investor-owned utilities (IOUs) by various suppliers of
natural gas and electricity.

The Nuclear Regulatory Commission (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.

Licenses and Permits

SDG&E obtains a number of 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. Both require periodic renewal, which
results in continuing regulation by the granting agency.

Other regulatory matters are described in Notes 10 and 11 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.

5

ELECTRIC OPERATIONS

Resource Planning

In 1996, California enacted legislation restructuring California's
investor-owned electric utility industry. The legislation and related
decisions of the CPUC were intended to stimulate competition 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 12 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

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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.

7

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.

8

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

9

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.

10

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.

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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.

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

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, and 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.

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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&E 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 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 from other sources, such as brokers or producers.
Noncore customers would also have to make arrangements to deliver their
purchases to the company's receipt points for delivery through the
company's transmission and distribution system. The proposed
implementation of the order has encountered significant opposition and
the CPUC is reconsidering its decision.

In 2002, 89 percent of the CPUC-authorized natural gas margin was
allocated to the core customers, with 11 percent allocated to the
noncore customers.

Although revenues from transportation throughput is less than 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, and with other fuels for large
industrial, commercial and UEG uses. Growth in the natural gas markets
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 residential 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

14

pipelines and general economic conditions can result in significant
shifts in demand and market price. The demand for natural gas by large
UEG customers is also greatly affected by the price and availability of
electric power generated in other areas.

Effective March 31, 1998, electric industry restructuring gave
California electric utilities the option of purchasing energy for their
customers from out-of-state producers. As a result, natural gas demand
for electric generation within southern 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 electricity 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 of the inspections complete at the
end of five years. Related to these inspections and potential
retrofits, the company estimates that it will have $0.5 million in
operating and maintenance expense each year.

Additional information concerning customer demand and other aspects of
natural gas operations is provided under "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and in Notes
11 and 12 of the notes to Consolidated Financial Statements herein.

RATES AND REGULATION

Electric Industry Restructuring

A flawed electric-industry restructuring plan, electricity
supply/demand imbalances, and legislative and regulatory responses have
significantly impacted the company's operations. Additional information
on electric-industry restructuring is provided above under "Electric
Operations," in "Management's Discussion and Analysis of Financial
Condition and Results of Operations," and 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 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 restructuring
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.

15

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 12 of the 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 on the third site is $1.5
million.

SDG&E sold 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.

17

At December 31, 2002, the company's estimated remaining investigation
and remediation liability related to hazardous waste sites, including
the manufactured gas sites, was $3 million, of which 90 percent is
authorized to be recovered through the Hazardous Waste Collaborative
mechanism. This estimated cost excludes remediation costs 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 the proximity of homes to certain power lines and equipment and
childhood leukemia. 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 has 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, the CPUC has
indicated that no health risk has been identified.

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 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

18

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 December 31, 2003, SONGS
mitigation costs are recovered through the Incremental Cost Incentive
Pricing mechanism. Costs thereafter are anticipated to be recovered in
customer rates.

OTHER MATTERS

Research, Development and Demonstration (RD&D)

For 2002, the CPUC authorized SDG&E to fund $1.2 million and $4.0
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.

Employees of Registrant

As of December 31, 2002 the company had 4,130 employees, compared to
3,106 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.

Labor Relations

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

ITEM 2. PROPERTIES

Electric Properties

SDG&E's generating capacity is described in "Electric Resources"
herein. At December 31, 2002, 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 and in Arizona, and consist of 1,802 miles
of transmission lines and 21,095 miles of distribution lines.
Periodically, various areas of the service territory require expansion
to accommodate customer growth.

Natural Gas Properties

At December 31, 2002, SDG&E's natural gas facilities, which are located
in San Diego and Riverside counties, consisted of the Moreno and
Rainbow compressor stations, 166 miles of high pressure transmission
pipelines, 7,617 miles of high and low pressure distribution mains, and
6,079 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 owns or leases other 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 12 of the notes to
Consolidated Financial Statements or referred to elsewhere in this
Annual Report, neither the company nor its subsidiary are party to, nor
is their property the subject of, any material pending legal
proceedings other than routine litigation incidental to their
businesses.

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 declared is
included in the "Statements of Consolidated Changes in Shareholders'
Equity" set forth in Item 8 of this Annual Report herein.

20

ITEM 6. SELECTED FINANCIAL DATA

Since San Diego Gas & Electric Company 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 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

INTRODUCTION

This section includes management's discussion and analysis of operating
results from 2000 through 2002, and provides information about the
capital resources, liquidity and financial performance of San Diego Gas
& Electric (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.

The company is an operating public utility engaged in the electric and
natural gas businesses, which provides services to 3.1 million
customers. 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 789,000 meters in San Diego County and

21

transports electricity and gas for others. SDG&E's service area
encompasses 4,100 square miles, covering 26 cities. 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 3 of the
notes to Consolidated Financial Statements.

Business Combination

Sempra Energy (the Parent) was formed to serve as a holding company for
Pacific Enterprises (PE), the parent corporation of Southern California
Gas Company (SoCalGas), and Enova Corporation (Enova), the parent
corporation of SDG&E, in a tax-free business combination that became
effective on June 26, 1998.

RESULTS OF OPERATIONS

To understand the operations and financial results of the company, it
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 the responsibility of the CPUC to regulate
investor-owned utilities (IOUs) 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) and the
Independent System Operator (ISO). The PX served as a wholesale power
pool and the ISO scheduled power transactions and access to the
electric transmission system. Supply/demand imbalances 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, 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 to purchase power 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 issued
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.

22

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 Notes 10 and 11 of the notes to
Consolidated Financial Statements.

The tables 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)
for the years ended December 31

Although commodity-related revenues from the DWR's purchasing of the
company's net short position are not included in revenue, the
associated volumes and distribution revenue are included herein.

23

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

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. The
commodity costs associated with the DWR's purchases and the
corresponding sale to SDG&E's customers 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

24

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 discussion in Note 1 of the notes to
Consolidated Financial Statements.

Other Operating Expenses. Other operating expenses increased to
$531 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 property 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 2002 was primarily due to
lower interest incurred as 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 3 of the
notes to Consolidated Financial Statements. In addition, see further
discussion of rate-reduction bonds in Note 3.

25

Income Taxes. Income tax expense was $91 million and $141 million
for the years ended December 31, 2002 and 2001, respectively. The
effective income tax rates were 30.3 percent and 43.5 percent for the
same years. The decrease in income tax expense was primarily due to the
fact that SDG&E received 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 million
favorable resolution of prior year 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, 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 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 to
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

26

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
were due primarily to higher state tax depreciation in 2000 and the
2001 income tax issues.

Net Income. Net income increased to $183 million in 2001 from $151
million in 2000. The increase was 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 sale of the Blythe property.

CAPITAL RESOURCES AND LIQUIDITY

The company's operations are the major source 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
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 issued 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

27

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.

Management continues to regularly monitor the company's ability to
adequately meet the needs of its operating, financing and investing
activities.

CASH FLOWS FROM OPERATING ACTIVITIES

Net cash provided by operating activities totaled $757 million, $557
million and $174 million for 2002, 2001 and 2000, respectively. The
increase in cash flows from operations in 2002 compared to 2001 was
attributable to SDG&E's collection of a portion of prior purchased-
power costs (the remaining balance of which decreased to $392 million
at December 31, 2001, $215 million at December 31, 2002 and $183
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.

CASH FLOWS FROM INVESTING ACTIVITIES

Net cash provided by (used in) investing activities totaled $(611)
million, $(310) million and $288 million for 2002, 2001 and 2000,
respectively. The increase in cash used in investing activities in 2002
compared to 2001 was primarily due to increased capital expenditures
and advances to Sempra Energy, which are payable on demand.

28

For 2001, cash flows used in investing activities primarily consisted
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.
In addition, the increase in proceeds from sale of assets was due to
the sale of property in Blythe, California, for $42 million.

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 2003 are expected to include $400
million for additions to the company's natural gas and electric
distribution systems. These expenditures are expected to be financed by
operations and security issuances.

Over the next five years, the company expects to make capital
expenditures of approximately $2 billion.

Construction programs are periodically reviewed and revised by the
company in response to changes in economic conditions, competition,
customer growth, inflation, customer rates, the cost of capital, and
environmental and regulatory requirements.

The company's level of construction expenditures in the next few years
may vary substantially, and 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's strong investment-grade ratings and
capital structure. Smaller expenditures will be made by the use of
existing liquidity.

CASH FLOWS FROM FINANCING ACTIVITIES

Net cash used in financing activities totaled $309 million, $181
million and $543 million for 2002, 2001 and 2000, respectively.

Net cash used for financing activities increased in 2002 from 2001 due
primarily to higher dividend payments and the absence of debt issuances
in 2002.

Net cash used in financing activities decreased in 2001 primarily due
to higher dividends paid to Sempra Energy in 2000 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

29

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 2001 and $400 million in 2000.

The payment 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 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, SDG&E had loans to Sempra Energy of $250
million.

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, 2002 was $2.1 billion. The debt-to-
capitalization ratio was 42 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

30

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

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. Additional
information concerning commitments is provided above and in Notes 4, 9
and 12 of the notes to Consolidated Financial Statements.

As of January 31, 2003, 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 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) 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
million and $215 million at December 31, 2000, 2001 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 utility
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 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.

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

32

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 11, 2001, the CPUC issued a decision adopting the following
provisions affecting the structure of the natural gas industry in
California, some of which could introduce additional volatility into
the earnings of the company and other market participants: a system for
shippers 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 in electric 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

33

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

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-
risk management and trading activities. Assisted by the company's
Energy Risk Management Group (ERMG), the company's Energy Risk
Management Oversight Committee, consisting of senior officers, oversees
company-wide energy risk management activities and monitors the results
of trading activities to ensure compliance with the company's stated
energy-risk management and trading policies. Utility management
receives daily information on positions and the ERMG receives
information on a delayed basis detailing positions creating market and

34

credit risk for the company, consistent with affiliate rules. The ERMG
independently measures and reports the market and credit risk
associated with these positions. In addition, 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.

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 ERMG for the company. Historical
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 derivatives to manage natural gas price risk
associated with servicing their load requirements. In addition, the
company makes limited use of natural gas derivatives for trading
purposes. These instruments can include forward contracts, futures,
swaps, options and other contracts. In the case of both price-risk
management and trading activities, the use of derivative financial
instruments is subject to certain limitations imposed by company policy
and regulatory requirements. See the continuing discussion below and
Note 8 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-risk exposures
as of December 31, 2002 includes a discussion of how these exposures
are managed.

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

The company's market risk exposure is limited due to CPUC authorized
rate recovery of electric procurement and natural gas purchase, sale
and storage activity. 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, which is discussed in Notes 10 and 11 of the
notes to Consolidated Financial Statements. The company manages its
risk within the parameters of the company's market-risk management and
trading framework. As of December 31, 2002, the company's exposure to
market risk was not material.

35

Interest-Rate Risk

The company is exposed to fluctuations in interest rates primarily as a
result of its long-term debt. The company historically has funded
operations through long-term debt issues with fixed interest rates and
these 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 recent debt offerings
have been selected with short-term maturities to take advantage of
yield curves, or have used a combination of fixed-rate and floating-
rate debt. Subject to regulatory constraints, interest-rate swaps may
be used to adjust interest-rate exposures when appropriate, based upon
market conditions.

At December 31, 2002, the company had $1,062 million of fixed-rate debt
and $157 million of 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'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 million.

At December 31, 2002, the company did not have any outstanding
interest-rate swap transactions. See Notes 3 and 8 of the notes to
Consolidated Financial Statements for further information regarding
these swap transactions.

In addition the company is ultimately subject to the effect of interest
rate fluctuation on the assets of its pension plan.

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,
assisted by the ERMG and the company's credit department. Using
rigorous models, the company's credit department continuously
calculates current and potential credit risk to counterparties to
ensure the risk stays within approved limits and reports this
information to the ERMG. The company avoids concentration of
counterparties and management believes its credit policies 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.

The company monitors credit risk through a credit-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.

36

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 parties 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

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) 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 133 "Accounting for Derivative Instruments and Hedging
Activities" and SFAS 138 "Accounting for Certain Derivative
Instruments and Certain Hedging Activities," have a significant
effect on the balance sheets of the California Utilities but have
no significant effect on their 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 collectibility of regulatory and other assets.

The likelihood of recovery of various deferred tax assets.

Differences between estimates and actual amounts have had significant
impacts in the past and are likely to do so 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 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 creditworthiness of the other parties and other
factors. Costs to fulfill marked-to-market contracts are based on prior

37

experience. 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.

NEW ACCOUNTING STANDARDS

New pronouncements by the 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. They are described
in Note 1 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. SFAS 143 requires accounting and disclosure
changes concerning legal obligations related to future asset
retirements. SFAS 144 supercedes SFAS 121 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 to the fair value method of accounting for stock-
based compensation. SFAS 149 establishes standards for accounting for
financial instruments with characteristics of liabilities and equity.
Interpretation 45 clarifies that a guarantor is required to recognize a
liability for the fair value of the 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 record the fair value of a liability
for an asset retirement obligation in the period in which it is
incurred. SFAS 143 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

38

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.

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."

39

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEPENDENT AUDITORS' REPORT

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, 2002 and 2001, and the related statements of consolidated
income, cash flows and changes in shareholders' equity for each of the
three years in the period ended December 31, 2002. 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 auditing standards
generally accepted in the United States of America. 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 & Electric Company and subsidiary as of December 31, 2002 and 2001,
and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 2002, in conformity
with accounting principles generally accepted in the United States of
America.

/s/ DELOITTE & TOUCHE LLP

San Diego, California
February 14, 2003

40

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

41

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

42

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

43

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

44

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)

45

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SIGNIFICANT ACCOUNTING POLICIES

Business Combination

Sempra Energy was formed as a holding company for Enova Corporation
(Enova), the parent corporation of San Diego Gas & Electric (SDG&E),
and Pacific Enterprises (PE), the parent corporation of Southern
California Gas Company (SoCalGas), in connection with a business
combination of Enova and PE that was completed on June 26, 1998.

Principles of Consolidation

The Consolidated Financial Statements include the accounts of SDG&E 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.

Use of Estimates in the Preparation of the Financial Statements

The preparation of financial statements in conformity with generally
accepted accounting principles 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. 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 principles for regulated enterprises and reflect the
policies of the California Public Utilities Commission (CPUC) and the
Federal Energy Regulatory Commission (FERC).

The company prepares its financial statements in accordance with the
provisions of Statement of Financial Accounting Standards (SFAS) 71,
"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

46

liabilities would be written off. In addition, SFAS 144, "Accounting
for the Impairment or Disposal of Long-Lived Assets" affects utility
plant and regulatory assets such that a loss must be recognized
whenever a regulator excludes all or part of an asset's cost from
ratebase. The application of SFAS 144 continues to be evaluated in
connection with industry restructuring. Information concerning
regulatory assets and liabilities is described below in "Revenues",
"Regulatory Balancing Accounts," and "Regulatory Assets and
Liabilities," and industry restructuring is described in Notes 10 and
11.

Regulatory Balancing Accounts

The amounts included in regulatory balancing accounts at December 31,
2002, represent net payables (payables net of receivables) of $394
million 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 balancing accounts - net" at December 31, 2002.

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 certain costs and consumption levels that had been
balanced now affect earnings from electric operations. In addition,
fluctuations in certain costs and consumption levels affect earnings
for SDG&E's natural gas operations. Additional information on
regulatory matters is included in Notes 10 and 11.

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.

Regulatory assets (liabilities) as of December 31 consist of 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

* In connection with electric industry restructuring, which is
described in Note 10, 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 anticipated to be recovered in rates before the end of 2005 and are
included in regulatory balancing accounts - net at December 31, 2002.

Net regulatory assets 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
======= =======
- -----------------------------------------------------------------------
* Included in other current liabilities

All the assets earn a return 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.

Collection Allowance

The allowance for doubtful accounts receivable was $3 million, $5
million and $5 million at December 31, 2002, 2001 and 2000,
respectively. The company recorded a provision for doubtful accounts of
$4 million, $9 million and $6 million in 2002, 2001 and 2000,
respectively.

Inventories

At December 31, 2002, inventory included natural gas of $9 million, and
materials and supplies of $37 million. The corresponding balances at
December 31, 2001 were $34 million and $36 million, respectively.
Natural gas is valued by the last-in first-out (LIFO) method. When the
inventory is consumed, differences between this LIFO valuation and
replacement cost will be reflected in customer rates. Materials and
supplies at SDG&E are generally valued at the lower of average cost or
market.

Utility Plant

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, and 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
====== ======
- -----------------------------------------------------------------------

Accumulated depreciation and decommissioning of natural gas and
electric utility plant in service were $0.6 billion and $2.2 billion,
respectively, at December 31, 2002, and were $0.5 billion and $2.1
billion, respectively, at December 31, 2001. 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 for discussion
of the sale of generation facilities and industry restructuring.
Maintenance costs are expensed as incurred.

AFUDC, which represents the cost of funds used to finance the
construction of utility plant, is added to the cost of utility plant.
AFUDC also increases income, partly as an offset to interest charges
and partly as a component of other income, shown in the Statements of
Consolidated Income, although it is not a current source of cash.
AFUDC amounted to $21 million, $9 million and $8 million for 2002, 2001
and 2000, 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".

49

Nuclear-Decommissioning Liability

At December 31, 2002 and 2001, deferred credits and other liabilities
include $139 million and $151 million, respectively, of accrued
decommissioning costs associated with the company's interest in 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".

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 are shown in the
Statements of Consolidated Changes in Shareholders' Equity.

Revenues

Revenues are 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) is not included in SDG&E's revenues or costs. For
2001, California Power Exchange (PX) 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 to Note 10 for 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 Unconsolidated Affiliates

SDG&E has a promissory note receivable from Sempra Energy which bears a
variable interest rate based on short-term commercial paper rates, and
is due on demand. The note balance was $250 million and $52 million at
December 31, 2002 and 2001, respectively. 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, SDG&E had $42 million
due from and $3 million due to Sempra Energy affiliates. SDG&E also
had $16 million and $5 million in non-current liabilities due to Sempra
Energy at December 31, 2002 and 2001, respectively.

New Accounting Standards

SFAS 143, "Accounting for Asset Retirement Obligations": 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 fair value of a liability for an asset
retirement obligation in the period in which it is incurred. When the
liability is initially recorded, the entity increases the carrying
amount of the related long-lived asset by the present value of the
future retirement cost. Over time, 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 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 to the values they would have been had this
standard been employed from the in-service dates of the plants. Upon
adoption of SFAS 143 in 2003, the company will record an addition of
$70 million to utility plant, representing the company's share of SONGS
estimated future decommissioning costs (as discounted to the present
value at the date the various units began operation), and a
corresponding retirement obligation liability of $309 million. The
nuclear decommissioning trusts' balance of $494 million at December 31,
2002 represents amounts collected for future decommissioning costs 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 million to

51

reflect that SDG&E has collected the funds from its customers more
quickly than SFAS 143 would accrete the retirement liability and
depreciate the asset. See further discussion of SONGS' decommissioning
and the related nuclear decommissioning trusts in Note 4.

As of January 1, 2003, the company had additional 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
Impairment of Long-Lived Assets and for Long-Lived Assets to Be
Disposed Of." SFAS 144 applies to all long-lived assets, 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 at 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 rest of the entity and that will be
eliminated from the ongoing operations of the entity in a disposal
transaction. The company has identified no material effects to the
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
methods to do so. In addition, the 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
standards for accounting for financial instruments with characteristics
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.

52

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 be 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 ending 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," 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, "Consolidation of Variable Interest Entities," which
addresses consolidation by business enterprises of variable interest
entities.

NOTE 2. SHORT-TERM BORROWINGS

At December 31, 2002, SDG&E and its affiliate, SoCalGas, had a combined
revolving line of credit, under which each utility individually could
borrow up to $300 million, subject to a combined borrowing limit for
both utilities of $500 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 at
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

53

subject to any requisite regulatory approvals related to long-term
debt. This agreement requires SDG&E 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. These lines of credit were unused at December 31, 2002. At
December 31, 2002, SDG&E had no commercial paper outstanding.

NOTE 3. LONG-TERM DEBT

- -------------------------------------------------------------------
December 31,
(Dollars 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
- -------------------------------------------------------------------

Maturities of long-term debt are $66 million in 2003, $66 million in
2004, $66 million in 2005, $66 million in 2006, $66 million in 2007 and
$889 million thereafter. Holders of variable-rate bonds may require the
issuer to repurchase them prior to scheduled maturity. However, since
repurchased bonds would be remarketed and funds for repurchase are

54

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-mortgage Bonds

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

During the first quarter of 2001, SDG&E remarketed $150 million of
variable-rate first-mortgage bonds for a five-year term at a fixed rate
of 7%. At SDG&E's option, the bonds may be remarketed at a fixed or
floating rate at December 1, 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.

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. These
bonds were issued to facilitate the 10% rate reduction mandated by
California's electric-restructuring law, which is described in Note 10.
These bonds are being repaid over ten years by SDG&E's residential and
small-commercial customers via 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

55

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

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, SDG&E had an interest-rate
swap agreement that matured in 2002 that effectively fixed the interest
rate on $45 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 the Statements of Consolidated Income. The effect
on income was a $1 million gain in 2002 and a $1 million loss in 2001.
See additional discussion of interest-rate swaps in Note 8.

Financial Covenants

SDG&E's first-mortgage bond indenture requires 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.

NOTE 4. 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, are
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
- --------------------------------------------------------------------

The company and the other owners each hold its interest as an undivided
interest as tenants in common. 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, the Environmental Protection Agency, the
CPUC and other regulatory bodies.

The company's share of decommissioning costs for the SONGS units is
estimated to be $309 million in 2002 dollars, based on a 2001 cost
study completed and filed with the CPUC in 2002. At this time, the
cost study and resulting contributions are expected to be finalized and
approved or disapproved by the CPUC in April of 2003. Cost studies are
updated every three years and approved by the CPUC. The next such
update is expected to occur 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 costs allowed by
regulators. The amount accrued each year is currently being collected
in rates. Currently, collections are authorized to continue until 2013,
but may be extended upon request to the CPUC until 2022. The requested
amount is considered sufficient to cover the company's share of future
decommissioning costs. Payments to the nuclear decommissioning trusts
(described below under "Nuclear Decommissioning Trusts") are expected
to continue until sufficient funds have been collected to fully
decommission SONGS, which is not 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.

The amounts collected in rates are invested in externally managed trust
funds (described below under "Nuclear Decommissioning Trusts"). The
securities held by the trust 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, 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
also establish maximum amounts for investments in equity securities (50
percent of the qualified trust and 60 percent of the 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 shall be invested passively.

57

At December 31, 2002 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. 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
customer contributions.

Additional information regarding SONGS is included in Notes 10 and 12.

NOTE 5. INCOME TAXES

The reconciliation of the statutory federal income tax rate to the
effective income tax rate is 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

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 and state income taxes are allocated between operating income
and other income. SDG&E 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 having always
filed a separate return.

Accumulated deferred income taxes at December 31 consist of 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
- ----------------------------------------------------------------------

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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
- --------------------------------------------------------------------

NOTE 6. EMPLOYEE BENEFIT PLANS

Pension and Other Postretirement Benefits

The company sponsors several qualified and nonqualified 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.

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The following tables provide a reconciliation of the changes in the
plans' projected benefit obligations and the fair value of assets over
the two years, and a statement of the funded status as of each year
end:

61

The following table provides the components of net periodic benefit
cost (income) for the plans:

Assumed health-care cost trend rates have a significant effect on the
amounts reported for the health-care plans. A one-percent change in
assumed health-care cost trend rates would have the following effects:

- -----------------------------------------------------------------------
(Dollars in millions) 1% Increase 1% Decrease
- -----------------------------------------------------------------------
Effect on total of service and interest cost
components of net periodic postretirement
health-care benefit cost $ -- $ --

Effect on the health-care component of the
accumulated other postretirement
benefit obligation $ 3 $ (2)
- -----------------------------------------------------------------------

The company's funded pension plan had plan assets less than accumulated
benefit obligations. The projected benefit obligation and accumulated
benefit obligation were $613 million and $575 million, respectively, 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.

Savings Plans

The company offers savings plans, administered by plan trustees, to all
eligible employees. Eligibility to participate in the plans is
immediate for salary deferrals. Employees may contribute, subject to

62

plan provisions, from one percent to 25 percent of their regular
earnings. After one year of 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
invested in Sempra Energy common stock and must remain so invested
until termination of employment. At the direction of the employees, the
employees' contributions are invested in Sempra Energy stock, mutual
funds, or institutional trusts. Company contributions to the savings
plans were $7 million in 2002, $5 million in 2001 and $5 million 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.

NOTE 7. 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 encourages 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 continue
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 discussion of SFAS 148, the
amendment to SFAS 123, in Note 1.

The subsidiaries record an expense for the plans to the extent that
subsidiary employees participate in the plans, or that subsidiaries are
allocated a portion of Sempra Energy's costs of the plans. SDG&E
recorded expenses of $1 million, $2 million and $1 million in 2002,
2001 and 2000, respectively.

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NOTE 8. FINANCIAL INSTRUMENTS

Fair Value

The fair values of certain of the company's financial instruments
(cash, temporary investments, and customer deposits) approximate the
carrying amounts. The following table provides the carrying amounts and
fair values of the remaining financial instruments at December 31:

The fair values of long-term debt and preferred stock were estimated
based on quoted market prices for them or for similar issues.

Accounting for Derivative Instruments and Hedging Activities

SFAS 133 "Accounting for Derivative Instruments and Hedging
Activities," as amended by SFAS 138, "Accounting for Certain Derivative
Instruments and Certain Hedging Activities" recognizes all derivatives
as either assets or liabilities 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.

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Electric and Natural Gas Purchases and Sales: The unrealized gains and
losses related to these forward contracts are reflected 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.

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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.

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NOTE 9. PREFERRED STOCK

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 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). The $1.7625 Series has a sinking fund requirement to
redeem 50,000 shares per year from 2003 to 2007; the remaining 750,000
shares must be redeemed in 2008.

NOTE 10. 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 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 September 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

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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) resulted in the cessation 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 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 early 2001, the DWR has procured power for each of the California
IOUs and the CPUC has established the allocation of the power and the
related cost responsibility among the IOUs for that power. SDG&E's
allocation results in its overall rates being comparable to those of
the other two California electric IOUs, Southern California Edison
(Edison) and Pacific Gas and Electric (PG&E). On December 17, 2002, the
CPUC issued a decision allocating the cost of the DWR's revenue
requirement for its 2003 power purchases. The decision pools 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 on January 1, 2003 (see discussion below).

The CPUC's objective was for the IOUs to take the 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

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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 recent legislation regarding procurement
and renewables portfolio standards addressed in AB 57 and Senate Bill
1078. The decision established a process for review and approval of the
utilities' updated 2003 and long-term (20-year) procurement plans. The
CPUC approved SDG&E's 2003 procurement plan in December 2002 and
approval of the long-term plan is expected during 2003. The CPUC has
authorized the utilities to use derivatives to manage procurement risk
and to acquire a variety 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

69

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 before the end of 2005. Also 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 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

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exit fees with an interim cap of 2.7 cents per kWh, effective January
1, 2003. This decision will have no effect on SDG&E's cash flows or
results of operations, because any shortfall due to the cap on the exit
fees will be funded by bundled customers 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 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 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.

FERC Actions

The FERC is investigating prices charged to buyers in the California PX
and ISO markets by various electric suppliers. It is seeking to
determine the extent to which individual sellers have yet to be paid
for power supplied during the period of October 2, 2000 through June
20, 2001 and to estimate the amounts by which individual buyers and
sellers paid and were paid in excess of competitive market prices.
Based on these estimates, 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 height
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. 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

71

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 much of a
settlement that had been submitted in 2000 by SDG&E and approximately
30 other parties representing all segments of 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 rejected 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

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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.
These incentive rewards are not included in the company's earnings
before they are approved by the CPUC.

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 in electric 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,

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2001 (Year 8) was approved by the CPUC on January 30, 2003. As part of
the reward calculation is based on California-Arizona natural gas
border price indices, the decision reserved the right to revise the
reward 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 recompute the amount
of the DSM rewards. The California Utilities have opposed such a
recalculation. The issue is still pending before the CPUC.

Pending Incentive Awards

At December 31, 2002, the following performance incentives were pending
CPUC approval and therefore, were not included in the company's
earnings (dollars 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 results in an
annual revenue requirement increase of $2.4 million ($1.9 million
electric and $0.5 million natural gas) and increases SDG&E's overall

74

rate of return from 8.75 percent to 8.77 percent. These rates remain in
effect through 2003. The electric-transmission cost of capital is
determined under a separate FERC proceeding.

Border Price Investigation

On 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) border during the period of
March 2000 through May 2001. The CPUC intends to examine the possible
reasons for and issues potentially related to the elevated border
prices that affected California consumers during this period.

SDG&E is included among the respondents to the investigation. If the
investigation determines that the conduct of any respondent contributed
to the natural gas price spikes at the CA-AZ border during this period,
the CPUC may modify the respondent's applicable natural gas procurement
incentive mechanism, reduce the amount of any shareholder award for the
period involved, or order the respondent to issue a refund to
ratepayers to offset the higher rates paid. SDG&E is fully cooperating
with the CPUC in the investigation and believe that the CPUC will
ultimately determine that they were not responsible for the high border
prices during this period.

Biennial Cost Allocation Proceeding (BCAP)

The BCAP determines the allocation of authorized costs between customer
classes and the rates and rate design applicable to such classes for
natural gas transportation service. SDG&E filed its 2003 BCAP on
October 5, 2001. In February 2003, a CPUC Administrative Law Judge
granted a motion 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 levels 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, 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 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 effective
operations.

75

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 Border Price
Investigation referred to above.

CPUC Investigation of Energy-Utility Holding Companies

The CPUC has initiated an investigation into 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 CPUC had jurisdiction to create the holding company system
and, therefore, retains jurisdiction to enforce conditions to which the
holding companies had agreed. The company's request for rehearing on
the issues was denied by the CPUC and the company subsequently filed
appeals in the California Court of Appeal, which are still 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 ($20 million
through December 31, 2002) in a FERC filing to be made in February
2003.

NOTE 12. COMMITMENTS AND CONTINGENCIES

Natural Gas Contracts

SDG&E buys natural gas under short-term and long-term contracts. Short-
term purchases are from various Southwest U.S. 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 that 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 of natural
gas is tied to the California border spot-market price. SDG&E 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 gas for its own use and the release of a portion of this
capacity to third parties.

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.

At December 31, 2002, the future minimum payments under natural gas
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
- --------------------------------------------------------------------

Total payments under natural gas contracts were $205 million in 2002,
$457 million in 2001 and $273 million in 2000.

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, SDG&E expects to receive 43 percent of its customer power
requirement from DWR allocations. Of the remaining requirements that
SDG&E must provide, SONGS will account for 21 percent, long-term
contracts for 26 percent and spot market purchases for 10 percent. As
of January 2003, SDG&E has approximately 90 percent of its electric
power requirements met by a combination of 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.

77

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.

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

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

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. Total payments under
the contracts were $235 million in 2002, $512 million in 2001 and $257
million in 2000.

Leases

SDG&E has operating leases on real and personal property expiring at
various dates from 2003 to 2045. Certain leases on office facilities
contain escalation clauses requiring annual increases in rent ranging
from 3 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.

At December 31, 2002, 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
- ------------------------------------------------------------

Rent expense for operating leases totaled $27 million in 2002, $21
million in 2001 and $32 million in 2000.

78

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 laws 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. 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 million in 2002, $1 million
in 2001 and $2 million in 2000. 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 assurance that these costs will be recovered in rates.

The environmental issues currently facing the company or resolved
during the latest three-year period include investigation and
remediation of its manufactured-gas sites (three completed as of
December 31, 2002 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), 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. At December 31, 2002, the company's
accrued liability for environmental matters was $14.8 million, of which
$1.5 million related to manufactured-gas sites, $12.1 million to
cleanup at SDG&E's former fossil-fueled power plants, $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 accruals
are expected to be paid ratably over the next three years.

Nuclear Insurance

SDG&E and the other co-owners of SONGS have insurance to respond to any
nuclear liability claims related to SONGS. The insurance policy
provides $200 million in coverage, which is the maximum amount
available. In addition to this primary financial protection, the Price-
Anderson Act provides for up to $9.25 billion of secondary financial
protection if the liability loss exceeds the insurance limit. Should
any of the licensed/commercial reactors in the United States experience
a nuclear liability loss which exceeds the $200 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 share would be $36
million unless default occurs by any other SONGS co-owner. In the
event the secondary financial protection limit is insufficient to cover
the liability loss, the Price-Anderson Act provides for Congress to
enact further revenue raising measures to pay claims. These measures
could include an additional assessment on all licensed reactor
operators.

SDG&E and the other co-owners of SONGS have $2.75 billion of nuclear
property, decontamination and debris removal insurance. The coverage
also provides the SONGS owners up to $490 million for outage expenses
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, 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, 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, SDG&E could be assessed up to $7.6 million.

Both the nuclear liability and property insurance programs include
industry aggregate limits for SONGS losses resulting from acts of
terrorism.

Department Of Energy Decommissioning

The Energy Policy Act of 1992 established a fund for 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.

80

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 to 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.

81

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.

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 service territories, which covers 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. QUARTERLY FINANCIAL DATA (UNAUDITED)

The sum of the quarterly amounts does not necessarily equal the annual
totals due to rounding.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES

None.

83

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.

84

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. CONTROLS AND PROCEDURES.

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, the company has investments in
unconsolidated entities that it does not control or manage and,
consequently, its disclosure controls and procedures with respect to
these entities are necessarily substantially more limited than those it
maintains with respect to its consolidated subsidiaries.

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. Based on that evaluation,
the company's Chief Executive Officer and Chief Financial Officer have
concluded that the controls and procedures are effective.

There have been no significant changes in the company's internal controls or
in other factors that could significantly affect the internal controls
subsequent to the date the company completed its evaluation.

85

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

2. Financial statement schedules

Other 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 89 of this report.

(b) Reports on Form 8-K

The following reports on Form 8-K were filed after September 30, 2002:

None.

86

INDEPENDENT AUDITORS' CONSENT
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
report dated February 14, 2003, appearing in this Annual Report on Form
10-K of San Diego Gas and Electric Company for the year ended December
31, 2002.

/S/ DELOITTE & TOUCHE LLP

San Diego, California
February 25, 2003

87

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

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.

88

EXHIBIT INDEX

The Forms 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,
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.

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 Company 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 No. 2-49810, Exhibit 2A.)

4.02 Second Supplemental Indenture dated as of March 1, 1948.
(Incorporated by reference from SDG&E Registration No. 2-49810,
Exhibit 2C.)

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

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

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

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

Exhibit 10 -- Material Contracts
10.01 Restated Letter Agreement between San Diego Gas & Electric
Company and the California Department of Water Resources dated
April 5, 2001 (2001 Sempra Energy Form 10-K, Exhibit 10.04).

89

10.02 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 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
10.04 Sempra Energy Executive Incentive Plan effective January 1, 2003
(2002 Sempra Energy Form 10-K, Exhibit 10.09).

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

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

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

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

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

10.10 Sempra Energy 1998 Long Term Incentive Plan (Incorporated by
reference from the Registration Statement on Form S-8 Sempra
Energy Registration No. 333-56161 dated June 5, 1998(Exhibit
4.1)).

Financing
10.11 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 Form 10-K,
Exhibit 10.34).

10.12 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 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).

90

10.15 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 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 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 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 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 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
(1991 SDG&E Form 10-K, Exhibit 10.11).

Nuclear
10.22 Uranium enrichment services contract between the U.S.
Department of Energy (DOE assigned its rights to the U.S.
Enrichment Corporation, a U.S. government-owned corporation,
on July 1, 1993) and Southern California Edison Company, as
agent for SDG&E and others; Contract DE-SC05-84UEO7541,
dated November 5, 1984, effective June 1, 1984, as amended
(1991 SDG&E Form 10-K, Exhibit 10.9).

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

10.25 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)(1994 SDG&E Form 10-K, Exhibit 10.57).

91

10.26 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)(1996 Form 10-K, Exhibit 10.59).

10.27 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)(1996 Form 10-K, Exhibit 10.60).

10.28 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)(1999 Form 10-K, Exhibit 10.26).

10.29 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)(1999 Form 10-K, Exhibit 10.27).

10.30 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 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)(1996 Form 10-K, Exhibit 10.62).

10.32 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)(1996 Form 10-K, Exhibit 10.63).

10.33 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)(1999 Form 10-K, Exhibit 10.31).

10.34 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)(1999 Form 10-K, Exhibit 10.32).

10.35 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 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 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 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 Firm Transportation Service Agreement, dated October 13, 1994
between Pacific Gas Transmission Company and San Diego Gas
& Electric Company (1997 Enova Corporation Form 10-K, Exhibit
10.60).

Other
10.42 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, 2002, 2001, 2000, 1999 and 1998.

Exhibit 21 - Subsidiaries

21.01 Schedule of Subsidiaries at December 31, 2002.

Exhibit 23 - Independent Auditors' Consent, page 87.

93

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

94

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

SFAS Statement of Financial Accounting Standards

SoCalGas Southern California Gas Company

SONGS San Onofre Nuclear Generating Station

Southwest Powerlink A transmission line connecting San Diego to
Phoenix and intermediate points.

TCBA Transition Cost Balancing Account

TURN The Utility Reform Network

UEG Utility Electric Generation

VaR Value at Risk

95

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 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):

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. Guiles
Chief Executive Officer
96

I, Debra L. Reed, 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 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):

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/ Debra L. Reed
Debra L. Reed
Chief Financial Officer

97