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