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

Back to GetFilings.com

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, 2003
--------------------
OR
Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the transition period from to
------ -------

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

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

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

Registrant's telephone number, including area code (619)696-2000
--------------

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Name of each exchange
Title of each class on which registered
- ------------------- ---------------------
Preference Stock (Cumulative) American
Without Par Value (except $1.70 and $1.7625 Series)
Cumulative Preferred Stock, $20 Par Value
(except 4.60% Series)

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

Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months and (2) has been subject to
such filing requirements for the past 90 days.
Yes [ X ] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant's knowledge, in definitive proxy
or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. [ X ]

Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Exchange Act). Yes [ X ] No [ ]

Exhibit Index on page 88. Glossary on page 94.

Aggregate market value of the voting preferred stock held by non-
affiliates of the registrant as of January 31, 2004 was $24.8 million.

Registrant's common stock outstanding as of January 31, 2004 was wholly
owned by Enova Corporation.

DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Information Statement prepared for the May 2004 annual
meeting of shareholders are incorporated by reference into Part III.

2

TABLE OF CONTENTS

PART I
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . 3
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . 16
Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . . 17
Item 4. Submission of Matters to a Vote of Security Holders. . 17

PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . . 17
Item 6. Selected Financial Data. . . . . . . . . . . . . . . . 18
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . 18
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk . . . . . . . . . . . . . . . . . 33
Item 8. Financial Statements and Supplementary Data. . . . . . 34
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . 81
Item 9A. Controls and Procedures . . . . . . . . . . . . . . . 82

PART III
Item 10. Directors and Executive Officers of the Registrant . . 83
Item 11. Executive Compensation . . . . . . . . . . . . . . . . 83
Item 12. Security Ownership of Certain Beneficial Owners
and Management and related Stockholder Matters. . . . 84
Item 13. Certain Relationships and Related Transactions . . . . 84
Item 14. Principal Accountant Fees and Services . . . . . . . . 84

PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . . 84

Independent Auditors' Consent . . . . . . . . . . . . . . . . . 86

Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . 87

Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . 88

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

3

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

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

Forward-looking statements are necessarily based upon various
assumptions involving judgments with respect to the future and other
risks, including, among others, local, regional and national 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 status 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."

4

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
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.

RISK FACTORS

The following risk factors and all other information contained in this
report should be considered carefully when evaluating SDG&E. These risk
factors could affect the actual results of SDG&E and cause such results
to differ materially from those expressed in any forward-looking
statements of, or made by or on behalf of, SDG&E. Other risks and
uncertainties, in addition to those that are described below, may also
impair its business operations. If any of the following risks occurs,
SDG&E's business, cash flows, results of operations and financial
condition could be seriously harmed. These risk factors should be read
in conjunction with the other detailed information concerning SDG&E set
forth in the notes to Consolidated Financial Statements and in
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" herein.

SDG&E is subject to extensive regulation by state, federal and local
legislation and regulatory authorities, which may adversely affect the
operations, performance and growth of its business.

The 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, rates of return,
rates of depreciation, uniform systems of accounts, examination of
records and long-term resource procurement. The CPUC conducts various
reviews of utility performance (including reasonableness and prudency
reviews) and conducts audits and investigations into various matters
which may, from time to time, result in disallowances and penalties
adversely affecting earnings and cash flows. The CPUC also regulates
the relationship of utilities with their affiliates and is currently
conducting an investigation into this relationship. Various
proceedings involving the CPUC and relating to SDG&E's rates, costs,
incentive mechanisms, performance-based regulation and affiliate and
holding company rule compliance are discussed in the notes to
Consolidated Financial Statements and in "Management's Discussion and
Analysis of Financial Condition and Results of Operations" herein.

Periodically SDG&E's rates are approved by the CPUC based on forecasts
of capital and operating costs. If SDG&E's actual capital and
operating costs were to exceed the amount included in its base rates
approved by the CPUC, it would adversely affect earnings and cash
flows.

To promote efficient operations and improved productivity and to move
away from reasonableness reviews and disallowances, the CPUC adopted
Performance-Based Regulation (PBR) effective in 1994. Under PBR,

5

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.

Although SDG&E has received significant PBR rewards in the past, there
can be no assurance that SDG&E will receive rewards at similar levels
in the future, or at all. Additionally, if SDG&E fails to achieve
certain minimum performance levels established under the PBR
mechanisms, it may be assessed financial disallowances or penalties
which could adversely affect its earnings and cash flows.

The FERC regulates the transmission and wholesale sales of electricity
in interstate commerce, transmission access and other similar matters
involving SDG&E.

SDG&E may be impacted by new regulations, decisions, orders or
interpretations of the CPUC, FERC or other regulatory bodies. New
legislation, regulations, decisions, orders or interpretations could
change how SDG&E operates, could affect its ability to recover its
various costs through rates or adjustment mechanisms, or could require
SDG&E to incur additional expenses.

SDG&E may incur substantial costs and liabilities as a result of its
ownership of nuclear facilities.

SDG&E owns a 20% interest in the San Onofre Nuclear Generating Station
(SONGS), a 2,150 megawatt nuclear generating facility near San
Clemente, California. The Nuclear Regulatory Commission has broad
authority under federal law to impose licensing and safety-related
requirements for the operation of nuclear generation facilities.
SDG&E's ownership interest in SONGS subjects it to the risks of nuclear
generation, which include:

- -- the potential harmful effects on the environment and human
health resulting from the operation of nuclear facilities
and the storage, handling and disposal of radioactive
materials;

- -- limitations on the amounts and types of insurance
commercially available to cover losses that might arise in
connection with nuclear operations; and

- -- uncertainties with respect to the technological and
financial aspects of decommissioning nuclear plants at the
end of their licensed lives.

6

SDG&E's future results of operations, cash flows and financial
condition may be materially adversely affected by the outcome of
pending litigation against it.

Lawsuits filed in 2000 and currently consolidated in San Diego Superior
Court seek class-action certification and damages, alleging Sempra
Energy and the California Utilities, along with El Paso Energy Corp.
and several of its affiliates, unlawfully sought to control natural gas
markets. Similar lawsuits have been filed by the Attorneys General of
Arizona and Nevada and by others. Although the California Utilities
expect to prevail in these cases, they have expended or accrued
substantial amounts to pay the costs of defending these claims. If the
plaintiffs in these cases were to prevail in their claims, the future
results of operations, cash flows and financial condition of the
company may be materially adversely affected. In addition, various
other lawsuits are pending against SDG&E and other Sempra Energy
subsidiaries alleging that the companies unlawfully manipulated the
electric energy market.

In December 2002, the CPUC approved a settlement with SDG&E allocating
between SDG&E's customers and shareholders the profits from certain
intermediate-term power purchase contracts that SDG&E had entered into
during the early stages of California's electric utility industry
restructuring. As a result of the CPUC's decision, SDG&E recognized
additional after-tax income of $65 million in 2003. The Utility
Consumers' Action Network (UCAN) has appealed the decision and the
California Court of Appeals granted the petition for review.

These proceedings are discussed in the notes to Consolidated Financial
Statements and in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" herein.

SDG&E's cash flows, ability to pay dividends and ability to meet its
debt obligations largely depend on the performance of its utility
operations.

SDG&E's utility operations are its major source of liquidity. SDG&E's
cash flows, ability to meet its obligations to creditors and its
ability to pay dividends on its common stock are largely dependent upon
the sufficiency of utility earnings and cash flows in excess of utility
needs.

Natural disasters, catastrophic accidents or acts of terrorism could
materially adversely affect SDG&E's business, earnings and cash flows.

Like other major industrial facilities, SDG&E's SONGS nuclear facility,
electric transmission facilities, and natural gas pipelines may be
damaged by natural disasters, catastrophic accidents or acts of
terrorism. Any such incidents could result in severe business
disruptions, significant decreases in revenues and/or significant
additional costs to the company, which could have a material adverse
affect on SDG&E's earnings and cash flows. Given the nature and
location of these facilities, any such incidents also could cause
fires, leaks, explosions, spills or other significant damage to natural
resources and/or property belonging to third parties, or personal
injuries, which could lead to significant claims against the company
and its subsidiaries. Insurance coverage may become unavailable for

7

certain of these risks and the insurance proceeds received for any loss
of or damage to any of its facilities, or for any loss of or damage to
natural resources or property or personal injuries caused by its
operations, may be insufficient to cover the company's losses or
liabilities without materially adversely affecting the company's
financial condition, earnings and cash flows.

GOVERNMENT REGULATION

California Utility Regulation

The CPUC, which consists of five commissioners appointed by the
Governor of California for staggered six-year terms, regulates SDG&E's
rates and conditions of service, sales of securities, rate of return,
rates of depreciation, uniform systems of accounts, examination of
records, and long-term resource procurement. The CPUC conducts various
reviews of utility performance and conducts investigations into various
matters, such as deregulation, competition and the environment, to
determine its future policies. The CPUC also regulates the relationship
of 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.

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.

United States Utility Regulation

The FERC regulates the interstate sale and transportation of natural
gas, the transmission and wholesale sales of electricity in interstate
commerce, transmission access, the uniform systems of accounts, rates
of depreciation and electric rates involving sales for resale. Both the
FERC and the CPUC are currently investigating prices charged to the
California investor-owned utilities (IOUs) by various suppliers of
natural gas and electricity. See further discussion in Notes 10 and 11
of the notes to Consolidated Financial Statements herein.

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.

8

Local Regulation

SDG&E has electric franchises with the two counties and the 26 cities
in its electric service territory, and natural gas franchises with the
one county and the 18 cities in its natural gas service territory.
These franchises allow SDG&E to locate 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 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). The franchise agreement with the city of Chula Vista
expired during 2003 but continues on a month-to-month basis and a new
agreement is being negotiated.

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.

ELECTRIC OPERATIONS

Customers

At December 31, 2003 the company had 1.3 million meters consisting of
1,150,000 residential, 136,000 commercial, 450 industrial, 1,800 street
and highway lighting, 8,000 direct access and 24 off-system. The
company's service area covers 4,100 square miles. The company added
18,000 new customer meters in 2003 and 20,000 in 2002, representing
growth rates of 1.4% and 1.6% respectively.

Resource Planning and Power Procurement

SDG&E's resource planning, power procurement and related regulatory
matters are discussed below and in "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and in Note
10 to Consolidated Financial Statements herein.

9

Electric Resources

Based on CPUC-approved purchased-power contracts currently in place
with SDG&E's various suppliers and SDG&E's 20-percent share of a
generating plant, as of December 31, 2003, the supply of electric power
available to SDG&E is as follows:

Megawatts (MW)

Generation: SONGS 430
-----
Purchased power contracts:
Expiration
Supplier Source date
- -------------------------------------------------------------
Long-term contracts:
Portland General
Electric (PGE) Coal December 2013 84
-----
DWR-allocated contracts:
Williams Energy
Marketing & Trading Natural gas December 2010 1,875
Sunrise Power Co. LLC Natural gas June 2012 572
Other Natural gas/wind 2004 to 2013 328
-----
Total 2,775
-----
Other contracts with Qualifying Facilities (QFs):
Applied Energy Inc. Cogeneration November 2019 107
Yuma Cogeneration Cogeneration May 2024 57
Goal Line Limited
Partnership Cogeneration February 2025 50
Other (73 contracts) Cogeneration Various 16
Total -----
230
-----
Other contracts with renewable sources:
Various (9 contracts) Bio-gas 5-15 year terms
starting in 2003 28
Various (1 contract) Bio-mass 5 year term
starting in 2003 49
Various (5 contracts) Wind 10-15 year terms
starting in 2003 159
-----
Total sources 236
-----
Total generation and contracted 3,755
=====

Under the contract with PGE, SDG&E pays a capacity charge plus a
charge based on the amount of energy received and or PGE's costs.
Costs under the contracts with QFs are based on SDG&E's avoided
cost. Charges under the remaining contracts 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.

10

SONGS:

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

Unit 1 was removed from service in November 1992 when the CPUC issued a
decision to permanently shut it down. The storage and decommissioning
of Unit 1's spent nuclear fuel 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.

SDG&E has fully recovered its SONGS capital investment through December
31, 2003.

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, 11 and 12 of the notes to Consolidated Financial Statements
herein.

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
is expected to be adequate at least 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
$3 million per year. The DOE projects that it will not begin accepting
spent fuel until 2010 at the earliest.

To the extent not currently provided by the contracts, 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.

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 280 investor-owned and municipal utilities, state and
federal power agencies, energy brokers, and power marketers share power

11

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 Independent System Operator(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 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. In 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.

NATURAL GAS OPERATIONS

Resource Planning and Natural Gas Procurement and Transportation

SDG&E is engaged in the sale and distribution of natural gas. The
company's resource planning, natural gas procurement, contractual
commitments and related regulatory matters are discussed below and in
"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.

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 electric generation
(EG), wholesale, large commercial, industrial and enhanced oil recovery
customers.

12

Most core customers purchase natural gas directly from the company.
Core customers are permitted to aggregate their natural gas requirement
and purchase directly from brokers or producers. SDG&E continues to be
obligated to purchase reliable supplies of natural gas to serve the
requirements of the core customers.

Natural Gas Procurement and Transportation

Most of the natural gas purchased and delivered by SDG&E is produced
outside of California, primarily in the southwestern U.S. and Canada.
SDG&E purchases natural gas under short-term primarily based on monthly
spot-market prices.

SDG&E has long-term natural gas transportation contracts with various
interstate pipelines which expire on various dates through 2023. SDG&E
currently purchases natural gas on a spot basis to fill its long-term
pipeline capacity and purchases additional spot market supplies
delivered directly to California for its remaining requirements. SDG&E
continues to evaluate its long-term pipeline capacity portfolio,
including the release of a portion of this capacity to third parties.
All of SDG&E's natural gas is delivered through SoCalGas pipelines
under a short-term transportation agreement authorized by the CPUC. In
addition, under a separate agreement expiring March 2005, SoCalGas
provides SDG&E 8 bcf of storage inventory capacity with firm injection
and withdrawal rights.

According to "Btu's Daily Gas Wire," the annual average spot price of
natural gas at the California/Arizona border was $5.10 per million
British thermal unit (mmbtu) in 2003 ($5.59 in December 2003), compared
with $3.14 per mmbtu in 2002 and $7.27 per mmbtu in 2001. A number of
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 and in 2003. The following table
summarizes the average commodity costs of natural gas sold for the last
three years, which are above previous levels:

Years ended December 31,
-----------------------------------
2003 2002 2001
-----------------------------------
Cost of natural gas $ 274 $ 205 $ 457
Volumes delivered (bcf) 49 50 52
Average cost of natural gas
(dollars per bcf) $ 5.59 $ 4.10 $ 8.79

With improved delivery capacity to California, the company expects
adequate resources to be available at prices that generally will follow
national natural gas pricing trends and volatility.

Demand for Natural Gas

SDG&E faces competition in the residential and commercial customer
markets based on the customers' preferences for natural gas compared
with other energy products. The demand for natural gas by electric
generators is influenced by a number of factors. In the short-term,

13

natural gas use by EGs is impacted by the availability of alternative
sources of generation. The availability of hydroelectricity is highly
dependent on precipitation in the western United States. In addition,
natural gas use is impacted by the performance of other generation
sources in the western United States, including nuclear and coal, and
other natural gas facilities outside the service area. Natural gas use
is also impacted by changes in end-use electricity demand. For
example, natural gas use generally increases during summer heat waves.
Over the long-term, natural gas use will be greatly influenced by
additional factors such as the location of new power plant
construction. More generation capacity currently is being constructed
outside Southern California than within the utility service area. This
new generation will likely displace the output of older, less efficient
local generation, reducing EG natural gas use.

Effective March 31, 1998, electric industry restructuring provided out-
of-state producers the option to purchase energy for California utility
customers. 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 SDG&E'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 electric generation from SDG&E's service area.

Growth in the natural gas markets is largely dependent upon the health
and expansion of the Southern California economy and prices of other
energy products. External factors such as weather, the price of
electricity, electric deregulation, the use of hydroelectric power,
competing pipelines and general economic conditions can result in
significant shifts in demand and market price. The company added 11,000
and 14,000 new customer meters in 2003 and 2002, respectively,
representing growth rates of 1.4 percent and 1.8 percent, respectively.
The company expects that its growth rate for 2004 will approximate that
for 2003.

In the interruptible industrial market, customers are capable of
burning a fuel other than natural gas. Fuel oil is the most
significant competing energy alternative. The company's ability to
maintain its industrial market share is largely dependent on price.
The relationship between natural gas supply and demand has the greatest
impact on the price of the company's product. With the reduction of
natural gas production from domestic sources, the cost of natural gas
from non-domestic sources may play a greater role in the company's
competitive position in the future. The price of oil depends upon a
number of factors beyond the company's control, including the
relationship between supply and demand, and policies of foreign and
domestic governments.

The natural gas distribution business is seasonal in nature as
variations in weather conditions generally result in greater revenues
during the winter months when temperatures are colder. As is prevalent
in the industry, the company injects natural gas into storage during
the summer months (usually April through October) for withdrawal
storage during the winter months (usually November through March) when
customer demand is higher.

14

RATES AND REGULATION

Information concerning rates and regulations applicable to the company
is provided in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and in Notes 1, 10 and 11 of the
notes to Consolidated Financial Statements herein.

ENVIRONMENTAL MATTERS

Discussions about environmental issues affecting the company are
included in Note 12 of the notes to Consolidated Financial Statements
herein. The following additional information should be read in
conjunction with those discussions.

Hazardous Substances

In 1994, the CPUC approved the Hazardous Waste Collaborative Memorandum
account, allowing California's IOUs to recover their hazardous waste
cleanup costs, including those related to Superfund sites or similar
sites requiring cleanup. 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.
Cleanup costs at sites related to electric generation were specifically
excluded from the collaborative by the CPUC.

During the early 1900s, SDG&E and its predecessors manufactured gas
from coal or oil. The manufactured-gas plants (MGPs) often have
become contaminated with the hazardous residues of the process. SDG&E
identified three former MGPs, 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, 2003 estimated remaining
remediation liability on the third site is $5.8 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. Total costs to perform the necessary remediation were
estimated at $11 million at the time of sale. 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 commenced in 2003 and is expected to be completed by 2005. In
2003, at a cost of $0.8 million, cleanup was completed at the site of
a power plant that was sold in 1999. Remaining costs to remediate
these sites are estimated at $8 million at December 31, 2003.

15

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

At December 31, 2003, the company's estimated remaining investigation
and remediation liability related to hazardous waste sites, including
the MGPs, was $6.8 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

16

air-quality standards. Costs to comply with these standards are
recovered in rates.

In connection with the issuance of operating permits, SDG&E and the
other owners of SONGS previously reached agreement with the California
Coastal Commission to mitigate the environmental damage to the marine
environment attributed to the cooling-water discharge from SONGS Units
2 and 3. This mitigation program includes an enhanced fish-protection
system, a 150-acre artificial kelp reef and restoration of 150 acres of
coastal wetlands. In addition, the owners must deposit $3.6 million
with the state for the enhancement of fish hatchery programs and pay
for monitoring and oversight of the mitigation projects. SDG&E's share
of the cost is estimated to be $34.0 million. These mitigation projects
are expected to be completed in 2007. Through December 31, 2003, SONGS
mitigation costs were recovered through the ICIP mechanism. SONGS
mitigation costs incurred after December 31, 2003, will be capitalized
and recovered from ratepayers over the remaining life of the SONGS
units, subject to CPUC approval in Edison's general rate case.
Additional information on SONGS cost recovery is provided in Note 10 of
the notes to Consolidated Financial Statements herein.

OTHER MATTERS

Research, Development and Demonstration (RD&D)

For 2003, the CPUC authorized SDG&E to fund $1.2 million and $5.6
million for its natural gas and electric RD&D programs, respectively,
including $5.6 million to the CEC for its PIER (Public Interest Energy
Research) Program. SDG&E's annual RD&D costs have averaged $5.7 million
over the past three years.

Employees of Registrant

As of December 31, 2003 the company had 4,441 employees, compared to
4,130 at December 31, 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 interest in SONGS is described in "Electric Resources" herein.
At December 31, 2003, 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 1,805 miles of transmission
lines and 21,353 miles of distribution lines. Periodically, various
areas of the service territory require expansion to accommodate
customer growth.

17

Natural Gas Properties

At December 31, 2003, 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, 7,806 miles of high and low pressure distribution mains, and
6,094 miles of service lines.

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.

The company 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 is 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.

18

ITEM 6. SELECTED FINANCIAL DATA

Since SDG&E is a wholly owned subsidiary of Enova Corporation, per
share data is not provided.

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

ITEM 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 2001 through 2003, 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
in this Financial Report.

The company is an operating public utility engaged in the electric and
natural gas businesses, and provides services to 3.2 million consumers.
It distributes electric energy, purchased from others or generated from
its 20 percent interest in a nuclear facility, through 1.3 million
electric meters in San Diego County and an adjacent portion of southern
Orange County, California. It also purchases and distributes natural
gas through 800,000 meters in San Diego County and transports

19

electricity and natural 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. SDG&E and an affiliate,
Southern California Gas Company (SoCalGas), are collectively referred
to herein as "the California Utilities."

RESULTS OF OPERATIONS

2003 was a successful year for the company. Net income was $340
million, a company record. This is discussed further in the following
pages.

The following chart shows net income for each of the last five years.

(Dollars in millions)
-------------------------------
Net Income
-------------
2003 $ 340
2002 $ 209
2001 $ 183
2000 $ 151
1999 $ 199

To understand the operations and financial results of the company, it
is important to understand the ratemaking procedures applicable to the
company.

The company is subject to various regulatory bodies and rules at the
national, state and local levels. The primary California body is the
California Public Utilities Commission (CPUC), which regulates utility
rates and operations. The primary national bodies are the Federal
Energy Regulatory Commission (FERC) and the Nuclear Regulatory
Commission (NRC). The FERC regulates interstate transportation of
natural gas and electricity and various related matters. The NRC
regulates nuclear generating plants. Local regulators and
municipalities govern the placement of utility assets, including
natural gas pipelines and electric lines.

California's electric utility industry was significantly affected by
California's restructuring of the industry during 2000-2001. Beginning
in mid-2000 and continuing into 2001, supply/demand imbalances and a
number of other factors resulted in abnormally high electric commodity
costs, leading to several legislative and regulatory responses,
including a ceiling imposed on the cost of the electric commodity that
SDG&E could pass on to its small-usage customers. To obtain adequate
supplies of electricity, beginning in February 2001 and continuing
through December 31, 2002, the Department of Water Resources (DWR)
began purchasing power to fulfill the full net short position of the
investor-owned utilities (IOUs), consisting of all electricity
requirements of the IOUs' customers other than that provided by their
existing generating facilities or their previously existing purchased-
power contracts.

20

Beginning on January 1, 2003, SDG&E and the other IOUs resumed their
electric commodity procurement function. In addition, the CPUC
established the allocation of the power purchased by the DWR under
long-term contracts for the IOUs' customers and the related cost
responsibility among the IOUs for that power. This is discussed further
in Note 10 of the notes to Consolidated Financial Statements.

The natural gas industry experienced an initial phase of restructuring
during the 1980s by deregulating natural gas sales to noncore
customers. Restructuring is again being considered, as discussed in
Note 11 of the notes to Consolidated Financial Statements.

See additional discussion of these matters under "Factors Influencing
Future Performance" and in Notes 10 and 11 of the notes to Consolidated
Financial Statements.

Electric Revenue and Cost of Electric Fuel and Purchased Power.
Electric revenues increased to $1.8 billion in 2003 from $1.3 billion
in 2002, and the cost of electric fuel and purchased power increased to
$0.5 billion in 2003 from $0.3 billion in 2002. Additionally, for the
fourth quarter electric revenues increased to $424 million in 2003 from
$332 million in 2002, and the cost of electric fuel and purchased power
increased to $113 million in 2003 from $76 million in 2002. These
changes were attributable to several factors, including the effect of
the DWR's purchasing the net short position of SDG&E during 2002,
higher electric commodity costs and volumes in 2003, and the increase
in authorized 2003 distribution revenue. In addition, the increase in
revenue was due to the recognition of $116 million related to the
approved settlement of intermediate-term purchase power contracts and
higher PBR awards during the third quarter or 2003. See discussion of
performance awards in Note 11 of the notes to Consolidated Financial
Statements.

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 purchasing SDG&E's net short position for a
full year in 2002 and the effect of lower electric commodity costs and
decreased off-system sales. For the fourth quarter, electric revenues
increased to $332 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
resulting from increased volumes, as well as additional revenues from
the Incremental Cost Incentive Pricing (ICIP) mechanism, while the
decrease in cost of electric fuel and purchased power was due primarily
to a decrease in average electric commodity costs. Refer to Note 10 of
the notes to Consolidated Financial Statements for further discussion
of ICIP and the San Onofre Nuclear Generating Station (SONGS).

Natural Gas Revenue and Cost of Natural Gas. Natural gas revenues
increased to $509 million in 2003 from $431 million in 2002, and the
cost of natural gas increased to $274 million in 2003 from $205 million
in 2002. Additionally, natural gas revenues increased to $138 million
for the three months ended December 31, 2003 from $122 million for the
corresponding period in 2002, and the cost of natural gas increased to
$75 million in 2003 from $56 million in 2002. These changes were

21

primarily attributable to natural gas price increases. For the year,
this was partially offset by reduced volumes.

Under the current regulatory framework, the cost of natural gas
purchased for customers and the variations in that cost are passed
through to the customers on a substantially concurrent basis. However,
SDG&E's natural gas procurement Performance-Based Regulation (PBR)
mechanism provides an incentive mechanism by measuring SDG&E's
procurement of natural gas against a benchmark price comprised of
monthly natural gas indices, resulting in shareholder rewards for costs
achieved below the benchmark and shareholder penalties when costs
exceed the benchmark. See further discussion in Notes 1 and 11 of the
notes to Consolidated Financial Statements.

Natural gas revenues decreased to $431 million in 2002 from $686
million in 2001, and the cost of natural gas 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 North Baja
pipeline's beginning of service in September 2002 and to the lower
level of electric generation demand.

22

The tables below summarize the components of electric and natural gas
volumes and revenues by customer class for the years ended December 31,
2003, 2002 and 2001.

ELECTRIC TRANSMISSION AND DISTRIBUTION
(Dollars in millions, volumes in million kilowatt hours)

NATURAL GAS SALES, TRANSPORTATION & EXCHANGE
(Dollars in millions, volumes in billion cubic feet)

23

As explained in Note 1 of the notes to Consolidated Financial
Statements commodity-related revenues from the DWR's purchasing of the
company's net short position or from the DWR's allocated contracts are
not included in revenue. However, the associated volumes and
distribution revenue are included herein.

Other Operating Expenses. Other operating expenses increased to $637
million in 2003 from $560 million in 2002 and increased to $209 million
in the fourth quarter of 2003 from $176 million in the fourth quarter
of 2002. The changes were due primarily to higher labor and employee
benefit costs, costs associated with the Southern California wildfires
and general operating cost increases, including litigation charges.
Other operating expenses increased to $560 million in 2002 from $491
million in 2001. For the fourth quarter, other operating expenses
increased to $176 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 SONGS.

Other Income. Other income and deductions, which primarily consist of
interest income and/or expense from short-term investments and
regulatory balancing accounts, was $32 million, $24 million and $54
million in 2003, 2002 and 2001, respectively. Other income for the
fourth quarter, was $21 million, $10 million and $38 million in 2003,
2002 and 2001, respectively. The increases in 2003 were due to higher
interest income resulting from the favorable $37 million before-tax
resolution of income-tax issues with the Internal Revenue Service
(IRS) and reduced balancing account interest expense in 2003. The
decreases in 2002 were primarily due to 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.

Interest Expense. Interest expense was $73 million, $77 million and
$92 million in 2003, 2002 and 2001, respectively. The decrease for the
year in 2003 was due primarily to lower interest incurred as the
result of lower average debt. The decrease in interest expense in
2002 was primarily due to lower average debt and lower interest rates
in 2002. For the fourth quarter, interest expense was $20 million, $18
million and $22 million in 2003, 2002, and 2001, respectively.
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.

Income Taxes. Income tax expense was $148 million, $91 million and $141
million for the years ended December 31, 2003, 2002 and 2001,
respectively. The effective income tax rates were 30.3 percent, 30.3
percent and 43.5 percent for the same years. The increased income tax
expense in 2003 compared to 2002 was due primarily to higher taxable
income while the low rate in 2003 was due primarily to a $57 million
favorable resolution of income-tax issues in the fourth quarter of
2003. In addition, income before taxes in 2003 included $37 million in
interest income arising from the income tax settlement, resulting in an
offsetting $15 million income tax expense. The lower income tax expense
in 2002 compared to 2001 was due to lower taxable income and a $25
million favorable resolution of prior years' income-tax issues in 2002,

24

while the low rate in 2002 was due to the $25 million favorable
resolution.

Net Income. SDG&E recorded net income of $340 million and $209 million
in 2003 and 2002, respectively, and net income of $130 million and $54
million for the fourth quarters of 2003 and 2002, respectively. The
increase for the year was primarily due to the favorable resolution of
income tax issues in the fourth quarter of 2003, which positively
affected earnings by $79 million, income of $65 million after-tax
related to the approved settlement of certain purchase power contracts
(see Note 10 of the notes to Consolidated Financial Statements), higher
earnings from PBR awards, and higher electric transmission and
distribution revenue. These factors were partially offset by higher
operating expenses (including litigation charges in the third quarter
of 2003), the end of sharing of the merger savings (which positively
impacted earnings by $8 million in 2002) and the $25 million favorable
resolution of prior years' income tax issues recorded in the second
quarter of 2002. The change for the quarter was due to the resolution
of the income tax issues and higher electric transmission and
distribution revenue, offset partially by the end of sharing of the
merger savings (which positively impacted earnings by $2 million for
the 2002 quarter).

Net income increased to $209 million in 2002 from $183 million in 2001.
The increase was primarily due to the $25 million after-tax benefit
noted above and lower interest expense in 2002, partially offset by
lower interest income in 2002 and the 2001 gain on the sale of SDG&E's
Blythe property. Net income increased to $54 million for the fourth
quarter of 2002, compared to $46 million for the corresponding period
in 2001, primarily due to higher natural gas income, an increase in
electric transmission and distribution revenues, and income tax
adjustments in 2002, partially offset by the 2001 Blythe gain.

CAPITAL RESOURCES AND LIQUIDITY

The company's operations are the major source of liquidity. At December
31, 2003, the company had $148 million in cash and $300 million in
available unused, committed lines of credit.

Management continues to regularly monitor the company's ability to
finance the needs of its operating, financing and investing activities
in a manner consistent with its intention to maintain strong,
investment-quality credit ratings.

CASH FLOWS FROM OPERATING ACTIVITIES

Net cash provided by operating activities totaled $581 million, $757
million and $557 million for 2003, 2002 and 2001, respectively.

The decrease in cash flows from operations in 2003 compared to 2002 was
attributable to a decrease in overcollected regulatory balancing
accounts and higher tax payments, partially offset by a reduction in
deferred income taxes and investment tax credits.

The increase in cash flows from operations in 2002 compared to 2001 was
attributable to higher customer refunds and payments of accounts
payable in 2001, partially offset by the decrease in overcollected

25

regulatory balancing accounts and higher deferred income taxes and
investment tax credits in 2002.

During 2003, the company made a pension plan contribution of $17
million for the 2003 plan year.

CASH FLOWS FROM INVESTING ACTIVITIES

Net cash used in investing activities totaled $319 million, $611
million and $310 million for 2003, 2002 and 2001, respectively.

The decrease in cash used in investing activities in 2003 compared to
2002 was primarily due to the $129 million repayment by Sempra Energy
in 2003 compared to $199 million of advances from SDG&E in 2002.
Advances to Sempra Energy are payable on demand.

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.

Capital Expenditures for Utility Plant

Capital expenditures were $444 million in 2003, compared to $400
million and $307 million in 2002 and 2001, respectively. The increase
in capital expenditures in 2003 was mainly due to the inclusion of $40
million of capital costs associated with the Southern California
wildfires in October 2003. Capital expenditures in 2002 were up due to
additions and improvements to the company's natural gas and electric
distribution systems.

Future Capital Expenditures

Significant capital expenditures in 2004 are expected to be for
additions to the company's natural gas and electric distribution
systems. These expenditures are expected to be financed by cash flows
from operations and security issuances.

Over the next five years, the company expects to make capital
expenditures of $2.7 billion, consisting of $400 million in 2004, $450
million in 2005, $1.0 billion in 2006, $400 million in 2007 and $450
million in 2008.

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.

CASH FLOWS FROM FINANCING ACTIVITIES

Net cash used in financing activities totaled $273 million, $309
million and $181 million for 2003, 2002 and 2001, respectively.

The cash used in financing activities decreased in 2003 due to lower
repayments on long-term debt in 2003.

26

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.

Long-Term and Short-Term Debt

Repayments on long-term debt in 2003 were for $66 million of rate-
reduction bonds.

Repayments on long-term debt in 2002 included $38 million of first-
mortgage bonds and $66 million of rate-reduction bonds.

In 2001, repayments on long-term debt consisted of $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.

See Notes 2 and 3 of the notes to Consolidated Financial Statements for
further discussion of debt activity and lines of credit.

Dividends

Dividends paid to Sempra Energy amounted to $200 million in 2003,
compared to $200 million in 2002 and $150 million in 2001.

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, 2003,
the company could have provided a total (combined loans and dividends)
of $290 million to Sempra Energy. At December 31, 2003, SDG&E had
actual loans, net of payables, to Sempra Energy of $75 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, 2003 was $2.2 billion. The debt-to-
capitalization ratio was 40 percent at December 31, 2003. Significant
changes in capitalization during 2003 included long-term borrowings and
repayments, income and dividends.

Commitments

The following is a summary of the company's principal contractual
commitments at December 31, 2003. 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 3, 4, 9 and 12 of the notes
to Consolidated Financial Statements.

27

Credit Ratings
Several credit ratings of the company declined in 2003, but remain
investment grade. As of January 31, 2004, credit ratings for SDG&E were
as follows:

S&P* Moody's** Fitch
- ----------------------------------------------------------------
Secured debt A+ A1 AA
Unsecured debt A- A2 AA-
Preferred stock BBB+ Baa1 A+
Commercial paper A-1 P-1 F1+
------------------------------------
* Standard & Poor's
** Moody's Investor Services, Inc.

As of January 31, 2004, the company has a stable outlook rating from
all three credit rating agencies.

FACTORS INFLUENCING FUTURE PERFORMANCE

Performance of the company will depend primarily on the ratemaking and
regulatory process, electric and natural gas industry restructuring,
and the changing energy marketplace. These factors are discussed in
Notes 10 and 11 of the notes to Consolidated Financial Statements
herein.

Electric Industry Restructuring and Electric Rates

Subsequent to the electric capacity shortages of 2000-2001, SDG&E's
service territory had and continues to have an adequate supply of
electricity. However, various projections of electricity demand in
SDG&E's service territory indicate that, without additional electrical
generation and transmission, and reductions in electrical usage,
beginning in 2005 electricity demand could begin to outstrip available
resources. SDG&E has issued a request for proposals (RFP) to meet the
electric capacity shortfall, estimated at 69 megawatts (MW) in 2005 and
increasing annually by approximately 100 MW, and has filed a proposed

28

plan at the CPUC for meeting these capacity requirements. See Note 10
of the notes to Consolidated Financial Statements for additional
information regarding the RFP results.

Through December 31, 2003, the operating and capital costs of SONGS
Units 2 and 3 were recovered through the ICIP mechanism which allowed
SDG&E to receive 4.4 cents per kilowatt-hour for SONGS generation. Any
differences between these costs and the incentive price affected net
income. For the year ended December 31, 2003, ICIP contributed $53
million to SDG&E's net income. Beginning in 2004 the CPUC has provided
for traditional rate-making treatment, under which the SONGS ratebase
would start over at January 1, 2004, essentially eliminating earnings
from SONGS except from future increases in ratebase.

See additional discussion of this and related topics, including the
CPUC's adjustment to its plan for deregulation of electricity, in Note
10 of the notes to Consolidated Financial Statements.

Natural Gas Restructuring and Rates

In December 2001 the CPUC issued a decision related to natural gas
industry restructuring; however, implementation has been delayed. A
CPUC decision could be issued in the first quarter of 2004. With the
company's natural gas supply contracts nearing expiration, the company
believes that regulation needs to consider sufficiently the adequacy
and diversity of supplies to California, transportation infrastructure
and cost recovery thereof, hedging opportunities to reduce cost
volatility, and programs to encourage and reward conservation.
Additional information on natural gas industry restructuring is
provided in Note 11 of the notes to Consolidated Financial Statements.

CPUC Investigation of Compliance with Affiliate Rules

In February 2003, the CPUC opened an investigation of the business
activities of SDG&E, SoCalGas and Sempra Energy to ensure that they
have complied with statutes and CPUC decisions in the management,
oversight and operations of their companies. In September 2003, the
CPUC suspended the procedural schedule until it completes an
independent audit to evaluate energy-related holding company systems
and affiliate activities undertaken by Sempra Energy within the service
territories of SDG&E and SoCalGas. The audit will cover years 1997
through 2003, is expected to commence in March 2004 and should be
completed by the end of 2004. In accordance with existing CPUC
requirements, the California Utilities' transactions with other Sempra
Energy affiliates have been audited by an independent auditing firm
each year, with results reported to the CPUC, and there have been no
material adverse findings in those audits.
Cost of Service Filing

The California Utilities have filed cost of service applications with
the CPUC, seeking rate increases designed to reflect forecasts of 2004
capital and operating costs. SDG&E is requesting revenue increases of
$76 million. On December 19, 2003, settlements were filed with the CPUC
for SoCalGas and for SDG&E that, if approved, would resolve most of the
cost of service issues. A CPUC decision is likely in the second quarter
of 2004. The California Utilities have also filed for continuation
through 2004 of existing Performance-Based Regulation mechanisms for

29

service quality and safety that would otherwise expire at the end of
2003. In January 2004, the CPUC issued a decision that extended 2003
service and safety targets through 2004, but deferred action on
applying any rewards or penalties for performance relative to these
targets to a decision to be issued later in 2004 in a second phase of
these applications. This is discussed in Note 11 of the notes to
Consolidated Financial Statements.

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.

Sempra Energy has adopted corporate-wide policies governing its market
risk management activities. Assisted by Sempra Energy's Energy Risk
Management Group (ERMG), Sempra Energy's Energy Risk Management
Oversight Committee (ERMOC), consisting of senior officers, oversees
company-wide energy risk management activities and monitors the results
of activities to ensure compliance with the company's stated energy
risk management policies. Utility management receives daily information
on positions and the ERMG receives information detailing positions
creating market and 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, ERMOC
monitors energy price risk management 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, 2003, the total VaR of the
company's natural gas and power positions was not material.

The company uses electric and natural gas derivatives to manage price
risk associated with servicing their load requirements. The use of
derivative financial instruments is subject to certain limitations
imposed by company policy and regulatory requirements.

See the revenue recognition discussion in Note 1 and the additional
market risk information regarding derivative instruments 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, 2003 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

30

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,
intrastate transportation and storage activity. However, the company
may, at times, be exposed to market risk as a result of SDG&E's natural
gas PBR and electric procurement activities, 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 framework. As of December 31, 2003, the company's
exposure to market risk was not material. However, if commodity prices
rose too rapidly, it is likely that volumes would decline. This would
increase the per-unit fixed costs, which could lead to further volume
declines, leading to increased per-unit fixed costs and so forth.

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 costs are recovered in utility rates. As a result, some
recent debt offerings 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, 2003, the company had $996 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, 2003, SDG&E's fixed-rate debt had a one-year VaR
of $149 million and SDG&E's variable-rate debt had a one-year VaR of
$0.02 million.

At December 31, 2003, the company did not have any outstanding
interest-rate swap transactions. See Note 3 of the notes to
Consolidated Financial Statements for further information regarding
interest rate swap transactions.

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

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
performed by the ERMG and the company's credit department and overseen
by the ERMOC. Using rigorous models, the groups continuously calculate
current and potential credit risk to counterparties to monitor actual

31

balances in comparison to approved limits and reports this information
to the ERMG. The company avoids concentration of counterparties
whenever possible 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, the use of standardized agreements that
allow for the netting of positive and negative exposures associated
with a single counterparty and other security such as lock-box liens
and downgrade triggers.

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.

CRITICAL ACCOUNTING POLICIES AND KEY NON-CASH PERFORMANCE
INDICATORS

Certain accounting policies are viewed by management as critical
because their application is the most relevant, judgmental and/or
material to the company's financial position and results of
operations, and/or because they require the use of material
judgments and estimates.

The company's most significant accounting policies are described in
Note 1 of the notes to Consolidated Financial Statements. The most
critical policies, all of which are mandatory under generally accepted
accounting principles and the regulations of the Securities and
Exchange Commission, are the following:

Statement of Financial Accounting Standards (SFAS) No. 5
"Accounting for Contingencies," establishes the amounts and
timing of when the company provides for contingent losses.
Details of the company's issues in this area are discussed in
Note 12 of the notes to Consolidated Financial Statements.

SFAS 71 "Accounting for the Effects of Certain Types of
Regulation," has a significant effect on the way the California
Utilities record assets and liabilities, and the related revenues
and expenses, that would not be recorded absent the principles
contained in SFAS 71.

SFAS 109 "Accounting for Income Taxes," governs the way the
company provide for income taxes. Details of the company's issues
in this area are discussed in Note 5 of the notes to Consolidated
Financial Statements.

SFAS 123 "Accounting for Stock-Based Compensation" and SFAS 148
"Accounting for Stock-Based Compensation - Transition and
Disclosure," give companies the choice of recognizing a cost at
the time of issuance of stock options or merely disclosing what
that cost would have been and not recognizing it in its financial
statements. Sempra Energy, like most U.S. companies, has elected
the disclosure option for all options that are so eligible. The
subsidiaries record an expense for the plans to the extent that
subsidiary employees participate in the plans, or that

32

subsidiaries are allocated a portion of Sempra Energy's costs of
the plans. The effect of this is discussed in Note 1 of the notes
to Consolidated Financial Statements.

SFAS 133 "Accounting for Derivative Instruments and Hedging
Activities," SFAS 138 "Accounting for Certain Derivative
Instruments and Certain Hedging Activities" and SFAS 149
"Amendment of Statement 133 on Derivative Instruments and Hedging
Activities" have a significant effect on the balance sheets of
the company but have no significant effect on its 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 receivables, regulatory assets, deferred
tax assets and other assets.

The various assumptions used in actuarial calculations for
pension and other postretirement benefit plans.

The likelihood of recovery of various deferred tax assets.

The probable costs to be incurred in the resolution of
litigation.

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 receivables considers
the aging of the receivables, the creditworthiness of customers and the
enforceability of contracts, where applicable. The assumed
collectibility of regulatory assets considers legal and regulatory
decisions involving the specific items or similar items. The assumed
collectibility of other assets considers the nature of the item, the
enforceability of contracts where applicable, the creditworthiness of
the other parties and other factors. Costs to fulfill contracts that
are carried at fair value are based on prior experience. Actuarial
assumptions are based on the advice of the company's independent
actuaries. The likelihood of deferred tax recovery is based on analyses
of the deferred tax assets and the company's expectation of future
financial and/or taxable income, based on its strategic planning.

Choices among alternative accounting policies that are material to the
company's financial statements and information concerning significant
estimates have been discussed with the audit committee of the board of
directors.

Key non-cash performance indicators for the company include numbers of
customers and quantities of natural gas and electricity sold. The
information is provided in "Introduction" and "Results of Operations."

33

NEW ACCOUNTING STANDARDS

Relevant pronouncements that have recently become effective and have
had a significant effect on the company are SFAS 143, 148, 149 and 150,
and FIN 45. They are described in Note 1 of the notes to Consolidated
Financial Statements. Pronouncements that could have a material effect
on the company are described below.

SFAS 143, "Accounting for Asset Retirement Obligations": SFAS 143
requires entities to record the fair value of liabilities for legal
obligations related to asset retirements in the period in which they
are incurred. It also requires the company to reclassify amounts
recovered in rates for future removal costs not covered by a legal
obligation from accumulated depreciation to a regulatory liability.

SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities": SFAS 149 amends and clarifies accounting for
derivative instruments, including certain derivative instruments
embedded in other contracts, and for hedging activities under SFAS 133.
Under SFAS 149 natural gas forward contracts that are subject to
unplanned netting do not qualify for the normal purchases and normal
sales exception. The company has determined that all natural gas
contracts are subject to unplanned netting and as such, these contracts
will be marked to market. In addition, effective January 1, 2004, power
contracts that are subject to unplanned netting (see Note 1 of the
notes to Consolidated Financial Statements) and that do not meet the
normal purchases and normal sales exception under SFAS 149 will be
further marked to market. Implementation of SFAS 149 on July 1, 2003
did not have a material impact on reported net income.

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."

34

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, 2003 and 2002, 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, 2003. 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, 2003 and 2002, and
the results of their operations and their cash flows for each of the
three years in the period ended December 31, 2003, in conformity with
accounting principles generally accepted in the United States of
America.

As described in Note 1 to the financial statements, the Company
adopted Statement of Financial Accounting Standards No. 143,
Accounting for Asset Retirement Obligations, effective January 1,
2003.

/s/ DELOITTE & TOUCHE LLP

San Diego, California
February 23, 2004

35

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

36

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

37

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

38

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

39

SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
Years ended December 31, 2003, 2002 and 2001
(Dollars in millions)

40

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The Consolidated Financial Statements include the accounts of San
Diego Gas & Electric (SDG&E or the company) and its sole subsidiary,
SDG&E Funding LLC. All material intercompany accounts and transactions
have been eliminated.

As a subsidiary of Sempra Energy, the company receives certain
services therefrom, for which it is charged its allocable share of the
cost of such services. Management believes that cost is reasonable,
but probably less than if the company had to provide those services
itself.

Use of Estimates in the Preparation of the Financial Statements

The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of revenues and
expenses during the reporting period, and the reported amounts of
assets and liabilities and the disclosure of contingent assets and
liabilities at the date of the financial statements. Actual amounts can
differ significantly from those estimates.

Basis of Presentation

Certain prior-year amounts have been reclassified to conform to the
current year's presentation.

Regulatory Matters

Effects of Regulation

The accounting policies of the company conform with generally accepted
accounting principles for regulated enterprises and reflect the
policies of the California Public Utilities Commission (CPUC) and the
Federal Energy Regulatory Commission (FERC). SDG&E and its affiliate,
Southern California Gas Company (SoCalGas), are collectively referred
to herein as "the California Utilities."

The company prepares its financial statements in accordance with the
provisions of Statement of Financial Accounting Standards (SFAS) 71,
"Accounting for the Effects of Certain Types of Regulation," under
which a regulated utility records a regulatory asset if it is probable
that, through the ratemaking process, the utility will recover that
asset from customers. Regulatory liabilities represent reductions in
future rates for amounts due to customers. To the extent that portions
of the utility operations cease to be subject to SFAS 71, or recovery
is no longer probable as a result of changes in regulation or the
utility's competitive position, the related regulatory assets and
liabilities would be written off. In addition, SFAS 144, "Accounting
for the Impairment or Disposal of Long-Lived Assets" requires that a
loss must be recognized whenever a regulator excludes all or part of
utility plant or regulatory assets from ratebase. Information

41

concerning regulatory assets and liabilities is described in
"Revenues," "Regulatory Balancing Accounts," and "Regulatory Assets and
Liabilities."

Regulatory Balancing Accounts

The amounts included in regulatory balancing accounts at December 31,
2003, represent net payables (payables net of receivables) of $338
million and $394 million at December 31, 2003 and 2002, respectively.
The payables normally are returned by reducing future rates.

Balancing accounts provide a mechanism for charging utility customers
the amount actually incurred for certain costs, primarily commodity
costs. However, fluctuations in most operating and maintenance costs
and in consumption levels affect earnings. Additional information on
regulatory matters is included in Notes 10 and 11.

Regulatory Assets and Liabilities

In accordance with the accounting principles of SFAS 71, the company
records regulatory assets and regulatory liabilities as discussed
above.

Regulatory assets (liabilities) as of December 31 relate to the
following matters:

(Dollars in millions) 2003 2002
- ----------------------------------------------------------------------

Fixed-price contracts and other derivatives $ 560 $ 636
Recapture of temporary rate reduction* 259 326
Deferred taxes recoverable in rates 273 190
Unamortized loss on retirement of debt - net 44 49
Employee benefit costs 35 35
Cost of removal obligations** (846) (1,162)
Asset retirement obligations** (303) --
Other 24 7
------- --------
Total $ 46 $ 81
======= ========
- ----------------------------------------------------------------------
* In connection with electric industry restructuring, which is
described in Note 10, SDG&E temporarily reduced rates to its
small-usage customers. That reduction is being recovered in
rates through 2007.
** See discussion of SFAS 143 in "New Accounting Standards".

42

Net regulatory assets are recorded on the Consolidated Balance Sheets
at December 31 as follows:

(Dollars in millions) 2003 2002
- -----------------------------------------------------------------------

Current regulatory assets $ 140 $ 134
Noncurrent regulatory assets 1,056 1,111
Current regulatory liabilities* (23) (2)
Noncurrent regulatory liabilities (1,127) (1,162)
-------- --------
Total $ 46 $ 81
======== ========
- -----------------------------------------------------------------------
* Amount is included in Other Current Liabilities.

All of these assets either earn a return, generally at short-term
rates, or the cash has not yet been expended and the assets are offset
by liabilities that do not incur a carrying cost.

Cash and Cash Equivalents

Cash equivalents are highly liquid investments with maturities of three
months or less at the date of purchase.

Collection Allowances

The allowance for doubtful accounts was $2 million, $3 million and $5
million at December 31, 2003, 2002 and 2001, respectively. The company
recorded a provision for doubtful accounts of $1 million, $4 million
and $9 million in 2003, 2002 and 2001, respectively.

Inventories

At December 31, 2003, inventory shown on the Consolidated Balance
Sheets included natural gas of $21 million, and materials and supplies
of $39 million. The corresponding balances at December 31, 2002 were $9
million and $37 million, respectively. Natural gas is valued by the
last-in first-out (LIFO) method. When the inventory is consumed,
differences between the LIFO valuation and replacement cost are
reflected in customer rates. Materials and supplies at the company are
generally valued at the lower of average cost or market.

Property, Plant and Equipment

Utility plant primarily represents the buildings, equipment and other
facilities used by the company to provide natural gas and electric
utility services.

The cost of plant includes labor, materials, contract services and
related items. In addition, the cost of plant includes an allowance for
funds used during construction (AFUDC). The cost of most retired
depreciable utility plant, minus salvage value is charged to
accumulated depreciation.

43

Utility plant balances by major functional categories are as follows:

- -----------------------------------------------------------------------
Depreciation rates
Utility Plant for years ended
at December 31 December 31
- ----------------------------------------------------------------------
(Dollars in billions) 2003 2002 2003 2002 2001
- ----------------------------------------------------------------------

Natural gas operations $ 1.0 $ 1.0 3.63% 3.62% 3.71%
Electric distribution 3.2 3.0 4.70% 4.66% 4.67%
Electric transmission 0.9 0.9 3.09% 3.17% 3.19%
Other electric 0.7 0.5 9.53% 9.37% 8.46%
------ ------
Total $ 5.8 $ 5.4
====== ======
- -----------------------------------------------------------------------

Accumulated depreciation and decommissioning of natural gas and
electric utility plant in service were $0.3 billion and $1.4 billion,
respectively, at December 31, 2003, and were $0.3 billion and $1.3
billion, respectively, at December 31, 2002. See discussion of SFAS 143
under "New Accounting Standards." Depreciation expense is based on the
straight-line method over the useful lives of the assets or a shorter
period prescribed by the CPUC. See Note 10 for discussion of the sale
of generation facilities and industry restructuring. Maintenance costs
are expensed as incurred.

AFUDC, which represents the cost of funds used to finance the
construction of utility plant, is added to the cost of utility plant.
AFUDC also increases income, partly as an offset to interest charges
and partly as a component of Other Income - Net in the Statements of
Consolidated Income, although it is not a current source of cash.
AFUDC amounted to $17 million, $21 million and $9 million for 2003,
2002 and 2001, respectively.

Nuclear Decommissioning Liability

At December 31, 2002, in accordance with SFAS 71, the company had
recorded a $355 million regulatory liability representing its share of
the estimated future decommissioning costs of the San Onofre Nuclear
Generating Station (SONGS). In addition, Deferred Credits and Other
Liabilities included $139 million of accrued decommissioning costs
associated with SONGS. As of December 31, 2003, as the result of
implementing SFAS 143, "Accounting for Asset Retirement Obligations,"
the company had asset retirement obligations and related regulatory
liabilities of $316 million and $303 million, respectively. Additional
information on SONGS decommissioning costs is included below in "New
Accounting Standards."

Legal Fees

Legal fees that are associated with a past event and not expected to be
recovered in the future are accrued when it is probable that they will
be incurred.

44

Comprehensive Income

Comprehensive income includes all changes, except those resulting from
investments by owners and distributions to owners, in the equity of a
business enterprise from transactions and other events, including
foreign-currency translation adjustments, minimum pension liability
adjustments, and certain hedging activities. The components of other
comprehensive income are shown in the Statements of Consolidated
Changes in Shareholders' Equity.

Revenues

Revenues are primarily derived from deliveries of electricity and
natural gas to customers and changes in related regulatory balancing
accounts. Revenues from electricity and natural gas sales and services
are generally recorded under the accrual method and recognized upon
delivery. The portion of SDG&E's electric commodity that was procured
for its customers by the California Department of Water Resources (DWR)
and delivered by SDG&E is not included in SDG&E's revenues or costs.
For 2001, California Power Exchange (PX) and Independent System
Operator (ISO) power revenues have been netted against purchased-power
expense to avoid double-counting of power sold into and then
repurchased from the PX/ISO. During 2003, costs associated with long-
term contracts allocated to SDG&E from the DWR were also not included
in the Statements of Consolidated Income, since the DWR retains legal
and financial responsibility for these contracts. Refer to Note 10 for
a discussion of the electric industry restructuring. Operating revenue
includes amounts for services rendered but unbilled (approximately one-
half month's deliveries) at the end of each year.

Through 2003, operating costs of SONGS Units 2 and 3, including nuclear
fuel and related financing costs, and incremental capital expenditures
were recovered through the Incremental Cost Incentive Pricing (ICIP)
mechanism which allowed SDG&E to receive 4.4 cents per kilowatt-hour
for SONGS generation. Any differences between these costs and the
incentive price affected net income. For the year ended December 31,
2003, ICIP contributed $53 million to SDG&E's net income. Beginning in
2004 the CPUC has provided for traditional rate-making treatment, under
which the SONGS ratebase would start over at January 1, 2004,
essentially eliminating earnings from SONGS except from future
increases in ratebase.

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

Transactions with Affiliates

SDG&E has a promissory note receivable from Sempra Energy which bears a
variable interest rate based on short-term commercial paper rates, and
is due on demand. The note balance (net of intercompany payables) was
$96 million and $259 million at December 31, 2003 and 2002,
respectively. In addition, at December 31, 2003 and 2002, SDG&E had $55
million and $33 million due from affiliates, and at December 31, 2002
had $3 million due to affiliates. SDG&E also had $21 million and $16
million in non-current liabilities due to Sempra Energy at December 31,
2003 and 2002, respectively.

45

New Accounting Standards

SFAS 132 (revised 2003), "Employers Disclosures about Pensions and
Other Postretirement Benefits": This statement revised employers'
disclosures about pension plans and other postretirement benefit plans.
It requires disclosures beyond those in the original SFAS 132 about the
assets, obligations, cash flows and net periodic benefit cost of
defined benefit pension plans and other defined postretirement plans.
It does not change the measurement or recognition of those plans.

SFAS 143, "Accounting for Asset Retirement Obligations": SFAS 143,
issued in July 2001, addresses financial accounting and reporting for
obligations associated with the retirement of tangible long-lived
assets and the associated asset retirement costs. It applies to legal
obligations associated with the retirement of long-lived assets that
result from the acquisition, construction, development and/or normal
operation of long-lived assets, such as nuclear plants. It requires
entities to record the fair value of a liability for an asset
retirement obligation in the period in which it is incurred. When the
liability is initially recorded, the entity increases the carrying
amount of the related long-lived asset by the present value of the
future retirement cost. Over time, the liability is accreted to its
full value and paid, and the capitalized cost is depreciated over the
useful life of the related asset.

The adoption of SFAS 143 on January 1, 2003 resulted in the recording
of an addition to utility plant of $71 million, representing the
company's share of SONGS estimated future decommissioning costs (as
discounted to the present value at the dates the units began
operation), and accumulated depreciation of $41 million related to the
increase to utility plant, for a net increase of $30 million. In
addition, the company recorded a corresponding retirement obligation
liability of $309 million (which includes accretion of that discounted
value to December 31, 2002) and a regulatory liability of $215 million
to reflect that SDG&E has collected the funds from its customers more
quickly than SFAS 143 would accrete the retirement liability and
depreciate the asset. These liabilities, less the $494 million recorded
as accumulated depreciation prior to January 1, 2003 (which represents
amounts collected for future decommissioning costs), comprise the
offsetting $30 million. See further discussion of SONGS'
decommissioning and the related nuclear decommissioning trusts
in Note 4.

On January 1, 2003, the company recorded additional asset retirement
obligations of $10 million associated with the future retirement of a
former power plant.

46

The change in the asset retirement obligations for the year ended
December 31, 2003 is as follows (dollars in millions):

Balance as of January 1, 2003 $ --
Adoption of SFAS 143 319
Accretion expense 21
Payments (14)
------
Balance as of December 31, 2003 $ 326*
======

* The current portion of the obligation is included in Other Current
Liabilities on the Consolidated Balance Sheets.

Had SFAS 143 been in effect on January 1, 2002, the asset retirement
obligation liability would have been $354 million as of that date.

Except for the items noted above, the company has determined that there
is no other material retirement obligation associated with tangible
long-lived assets.

Implementation of SFAS 143 has had no effect on results of operations
and is not expected to have a significant effect in the future.

The company collects estimated removal costs in rates through
depreciation in accordance with regulatory treatment. SFAS 143 also
requires the company to reclassify estimated removal costs, which have
historically been recorded in accumulated depreciation, to a regulatory
liability. At December 31, 2003 and 2002, the estimated removal costs
recorded as a regulatory liability were $846 million and $1.2 billion,
respectively. The decrease in the amount during 2003 is due to SFAS 143
requiring further reclassification of those costs to a legal obligation
(primarily SONGS costs) to Asset Retirement Obligations.

SFAS 144, "Accounting for Impairment or Disposal of Long-Lived Assets":
In August 2001, the Financial Accounting Standards Board (FASB) issued
SFAS 144, which replaces SFAS 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." It
applies to all long-lived assets. Among other things, SFAS 144 requires
that those long-lived assets classified as held for sale be measured at
the lower of carrying amount (cost less accumulated depreciation) or
fair value less cost to sell. Adoption of this statement on January 1,
2002 had no impact on the company's financial statements.

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

Sempra Energy has elected to continue using the intrinsic value method
of accounting for stock-based compensation. Therefore, SFAS 148 will
not have any effect on the company's financial statements. See Note 7
for additional information regarding stock-based compensation.

47

SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities": Effective July 1, 2003, SFAS 149 amended and
clarified accounting for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging
activities under SFAS 133. Under SFAS 149 natural gas forward contracts
that are subject to unplanned netting generally do not qualify for the
normal purchases and normal sales exception. ("Unplanned netting"
refers to situations whereby contracts are settled by paying or
receiving money for the difference between the contract price and the
market price at the date on which physical delivery would have
occurred.) In addition, effective January 1, 2004, power contracts that
are subject to unplanned netting and that do not meet the normal
purchases and normal sales exception under SFAS 149 will continue to be
marked to market. Implementation of SFAS 149 did not have a material
impact on reported net income.

SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of Liabilities and Equity": This statement establishes
standards for how an issuer classifies and measures certain financial
instruments with characteristics of both liabilities and equity. SFAS
150 requires that certain mandatorily redeemable financial instruments
previously classified in the mezzanine section of the balance sheet be
reclassified as liabilities. The company adopted SFAS 150 beginning
July 1, 2003 by reclassifying $24 million of mandatorily redeemable
preferred stock to Deferred Credits and Other Liabilities and to Other
Current Liabilities on the Consolidated Balance Sheets.

Emerging Issues Task Force (EITF) 03-11, "Reporting Realized Gains and
Losses on Derivative Instruments that are Subject to FASB Statement No.
133, Accounting for Derivative Instruments and Hedging Activities and
Not 'Held for Trading Purposes' as Defined in EITF 02-3, Issues
Involved in Accounting for Derivative Contracts Held for Trading
Purposes and Contracts Involved in Energy Trading and Risk Management
Activities": During 2003, the EITF reached a consensus that determining
whether realized gains and losses on physically settled derivative
contracts not held for trading purposes should be reported in the
income statement on a gross or net basis is a matter of judgment that
depends on the relevant facts and circumstances. Adoption of EITF 03-11
in 2003 did not have a significant impact to the company's financial
statements and the company does not expect a significant impact in the
future.

FASB Interpretation No. (FIN) 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees": In November 2002, the FASB
issued FIN 45, which elaborates on the disclosures to be made in
interim and annual financial statements of a guarantor about its
obligations under certain guarantees that it has issued. It also
clarifies that a guarantor is required to recognize, at the inception
of a guarantee, a liability for the fair value of the obligation
undertaken in issuing a guarantee. As of December 31, 2003, the company
did not have any outstanding guarantees.

FASB Staff Position (FSP) 106-1, "Accounting and Disclosure
Requirements Related to the Medicare Prescription Drug, Improvement and
Modernization Act of 2003": Issued January 12, 2004, FSP 106-1 permits
a sponsor of a postretirement health care plan that provides a

48

prescription drug benefit to make a one-time election to defer
accounting for the effects of the Medicare Prescription Drug,
Improvement and Modernization Act of 2003 (the Act). The company has
elected to defer the effects of the Act as provided by FSP 106-1. Any
measure of the accumulated postretirement benefit obligation or net
periodic postretirement benefit cost in the financial statements or the
accompanying notes do not reflect the impact of the Act on the plans.
At this time, specific authoritative guidance on the accounting for the
federal subsidy provided by the Act is pending and that guidance could
require the company to change previously reported information.

Other Accounting Standards: During 2003 and 2002 the FASB and the EITF
issued several statements that are not applicable to the company but
could be in the future. In July 2001, the FASB issued SFAS 142,
"Goodwill and Other Intangible Assets." In April 2002, the FASB issued
SFAS 145, which rescinds SFAS 4, "Reporting Gains and Losses from
Extinguishment of Debt", and SFAS 64, "Extinguishments of Debt Made to
Satisfy Sinking-Fund Requirements." In June 2002, the FASB issued SFAS
146, "Accounting for Costs Associated with Exit or Disposal
Activities." SFAS 146 supersedes previous accounting guidance,
principally EITF 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (including
Certain Costs Incurred in a Restructuring)." In 2002, consensuses were
reached in EITF 02-3 and the rescission of EITF 98-10, both dealing
with mark-to-market accounting for energy-trading activities. In
January 2003, the FASB issued Interpretation 46, "Consolidation of
Variable Interest Entities an interpretation of ARB No. 51."

NOTE 2. SHORT-TERM BORROWINGS

Committed Lines of Credit

SDG&E and its affiliate SoCalGas have a combined revolving line of
credit, under which each utility individually may borrow up to $300
million, subject to a combined borrowing limit for both utilities of
$500 million. Borrowings under the agreement bear interest at rates
varying with market rates and SDG&E's credit rating. The revolving
credit commitment expires in May 2004, at which time outstanding
borrowings may be converted into a one-year term loan subject to any
requisite regulatory approvals related to long-term debt. The agreement
requires SDG&E to maintain a debt-to-total capitalization ratio (as
defined in the agreement) of not to exceed 60 percent. Borrowings under
the agreement are individual obligations of the borrowing utility and a
default by one utility would not constitute a default or preclude
borrowings by the other. These lines of credit have never been drawn
upon.

49

NOTE 3. LONG-TERM DEBT

- -------------------------------------------------------------------
December 31,
(Dollars in millions) 2003 2002
- -------------------------------------------------------------------
First Mortgage bonds
6.8% June 1, 2015 $ 14 $ 14
5.9% June 1, 2018 68 68
5.9% to 6.4% September 1, 2018 176 176
6.1% September 1, 2019 35 35
Variable rates (1.25% at
December 31, 2003) September 1, 2020 58 58
5.85% June 1, 2021 60 60
5.25% to 7% December 1, 2027 225 225
------------------------
636 636
------------------------
Other long-term debt
5.9% June 1, 2014 130 130
Variable rates (1.46% at
December 31, 2003) July 1, 2021 39 39
Variable rates (1.45% at
December 31, 2003) December 1, 2021 60 60
6.75% March 1, 2023 25 25
------------------------
254 254
------------------------
Rate-reduction bonds, 6.31% to 6.37% at
December 31, 2003 payable annually
through 2007 263 329
------------------------
1,153 1,219

Current portion of long-term debt (66) (66)
------------------------
Total $1,087 $1,153
- -------------------------------------------------------------------

Maturities of long-term debt are $66 million in 2004, 2005 and 2006,
$65 million in 2007 and $890 million thereafter. Holders of variable-
rate bonds may require the issuer to repurchase them prior to scheduled
maturity. However, since repurchased bonds would be remarketed and
funds for repurchase are provided by revolving credit agreements (which
are generally renewed upon expiration and which are described in Note
2), it is expected that the bonds will be held to the maturities stated
above.

Callable Bonds

At the company's option, certain bonds are callable at various dates.
Of SDG&E's callable bonds, $597 million are callable in 2004, $105
million in 2005 and $45 million thereafter.

50

First Mortgage Bonds

The first mortgage bonds are secured by a lien on SDG&E's utility
plant. SDG&E may issue additional first mortgage bonds upon compliance
with the provisions of its bond indenture, which requires, among other
things, the satisfaction of pro forma earnings-coverage tests on first
mortgage bond interest and the availability of sufficient mortgaged
property to support the additional bonds, after giving effect to prior
bond redemptions. The most restrictive of these tests (the property
test) would permit the issuance, subject to CPUC authorization, of an
additional $2.3 billion of first mortgage bonds at December 31, 2003.

During the first quarter of 2001, SDG&E remarketed $150 million of
variable-rate first mortgage bonds for various terms at a fixed rate of
7%. $45 million of these bonds came to term on December 1, 2003 and
were remarketed to maturity with a rate of 5.25%. At SDG&E's option,
the remaining bonds may be remarketed at a fixed or floating rate at
December 1, 2005, the expiration of the fixed terms.

In June 2002, SDG&E paid at maturity its $28 million 7.625% first
mortgage bonds. In July 2002 the company optionally redeemed its $10
million 8.5% first mortgage bonds.

Unsecured Long-term Debt

Various long-term obligations totaling $254 million are unsecured at
December 31, 2003.

In February 2001, SDG&E remarketed $25 million of variable-rate
unsecured bonds as 6.75 percent fixed-rate debt for a three-year term.

Rate-Reduction Bonds

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

Interest-Rate Swaps

The company periodically enters into interest-rate swap agreements to
moderate its exposure to interest-rate changes and to lower its overall
cost of borrowing. As of December 31, 2003, the company did not have
any outstanding swap agreements.

During 2002 and 2001, SDG&E had an interest-rate swap agreement that
effectively fixed the interest rate on $45 million of variable-rate
underlying debt at 5.4 percent. This floating-to-fixed-rate swap did
not qualify for hedge accounting and, therefore, the gains and losses
associated with the change in fair value are recorded in the Statements
of Consolidated Income. The effect on net income was a $1 million gain
in 2002 and a $1 million loss in 2001.

51

NOTE 4. FACILITIES UNDER JOINT OWNERSHIP

SONGS and the Southwest Powerlink transmission line are owned jointly
with other utilities. The company's interests at December 31, 2003, are
as follows:

(Dollars in millions) Southwest
Project SONGS Powerlink
- --------------------------------------------------------------------
Percentage ownership (1) 20% 89%
Utility plant in service $ 11 $237
Accumulated depreciation and amortization $ 5 $141
Construction work in progress $ -- $ 27
- --------------------------------------------------------------------
(1) SDG&E's 20% ownership in SONGS has been fully recovered and is no
longer included under utility plant and accumulated depreciation.

The amounts specified above for SONGS represent wholly owned substation
equipment. As of December 31, 2003, the company has fully recovered its
interest in SONGS through the ICIP mechanism, which ended in December
31, 2003. Additional information concerning the ICIP mechanism is
provided in Note 10.

The company and the other owners each hold its interest as an undivided
interest as tenants in common. Each owner is responsible for financing
its share of each project and participates in decisions concerning
operations and capital expenditures.

The company's share of operating expenses is included in the Statements
of Consolidated Income.

SONGS Decommissioning

Objectives, work scope and procedures for the dismantling and
decontamination of the SONGS units must meet the requirements of the
Nuclear Regulatory Commission, the Environmental Protection Agency, the
CPUC and other regulatory bodies.

The company's share of decommissioning costs for the SONGS units is
estimated to be $316 million in 2003 dollars. Cost studies are updated
every three years, with the next update expected to be submitted to the
CPUC for its approval in 2005. Rate recovery of decommissioning costs is
allowed until the time that the costs are fully recovered, and is subject
to adjustment every three years based on the costs allowed by regulators.
Collections are authorized to continue until 2013, but may be extended by
CPUC approval until 2022, at which time the SONGS' operating license ends
and the decommissioning of SONGS 2 and 3 would be expected to begin.
Payments to the nuclear decommissioning trusts (described in "Nuclear
Decommissioning Trusts") are expected to continue until 2013 at which time
sufficient funds are expected to be collected to fully decommission SONGS.
If funds are not sufficient, additional future rate recovery is expected
to occur.

52

The amounts collected in rates are invested in the externally managed
trust funds. The securities held by these trusts are considered
available for sale. These trusts are shown on the Consolidated Balance
Sheets at market value. At December 31, 2003, these trusts reflected
unrealized gains of $159 million with the offsetting credits recorded
on the Consolidated Balance Sheets to Asset Retirement Obligations and
the related regulatory liabilities. At December 31, 2002, these trusts
reflected unrealized gains of $95 million with the offsetting credits
recorded to Deferred Credits and Other Liabilities and the related
regulatory liabilities.

Unit 1 was permanently shut down in 1992, and physical decommissioning
began in January 2000. Several structures, foundations and large
components have been dismantled, removed, and disposed of. Preparations
have been made for the remaining major work to be performed in 2004 and
beyond. That work will include dismantling, removal and disposal of all
remaining Unit 1 equipment and facilities (both nuclear and non-nuclear
components), decontamination of the site and completion of an on-site
storage facility for Unit 1 spent fuel. These activities are expected
to be completed in 2008.

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

Nuclear Decommissioning Trusts

SDG&E has established a Nonqualified Nuclear Decommissioning Trust and
a Qualified Nuclear Decommissioning Trust to provide funds for the
decommissioning of SONGS as described above. Amounts held by these
trusts are invested in accordance with CPUC regulations that establish
maximum amounts for investments in equity securities (50 percent of the
qualified trust and 60 percent of the nonqualified trust),
international equity securities (20 percent) and securities of electric
utilities having ownership interests in nuclear power plants (10
percent). Not less than 50 percent of the equity portion of these
trusts must be invested passively.

At December 31, 2003 and 2002, trust assets were allocated as follows
(dollars in millions):

Qualified Trust Nonqualified Trust
-----------------------------------------
2003 2002 2003 2002
------------- ------------------
Domestic equity $ 163 $ 143 $ 43 $ 36
Foreign equity 88 69 -- --
----- ----- ---- ----
Total equity 251 212 43 36
Total fixed income 249 220 27 26
----- ----- ---- ----
Total $ 500 $ 432 $ 70 $ 62
===== ===== ==== ====

Customer contribution amounts are determined by estimates of after-tax
investment returns, decommissioning costs and decommissioning cost
escalation rates. Lower actual investment returns or higher actual

53

decommissioning costs would result in an increase in customer
contributions.

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

NOTE 5. INCOME TAXES

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

Years ended December 31,
2003 2002 2001
- -----------------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Depreciation 3.9 2.3 5.9
State income taxes - net of
federal income tax benefit 6.4 6.1 5.8
Tax credits (0.6) (0.9) (0.9)
Settlement of Internal Revenue Service audit (11.7) (8.6) --
Other - net (2.7) (3.6) (2.3)
--------------------------
Effective income tax rate 30.3% 30.3% 43.5%
- -----------------------------------------------------------------------

The components of income tax expense are as follows:

(Dollars in millions) 2003 2002 2001
- ---------------------------------------------------------------------
Current
Federal $ 122 $ 164 $ 120
State 33 41 30
-----------------------
Total current taxes 155 205 150
-----------------------
Deferred
Federal (9) (93) 7
State 5 (18) (13)
------------------------
Total deferred taxes (4) (111) (6)
------------------------
Deferred investment tax credits (3) (3) (3)
------------------------
Total income tax expense $ 148 $ 91 $ 141
- ----------------------------------------------------------------------

On the Statements of Consolidated Income, federal and state income
taxes are allocated between operating income and other income.

SDG&E is included in the consolidated income tax return of Sempra
Energy and is allocated income tax expense from Sempra Energy in an
amount equal to that which would result from SDG&E's having always
filed a separate return.

54

Accumulated deferred income taxes at December 31 relate to the
following:

(Dollars in millions) 2003 2002
- ----------------------------------------------------------------------
Deferred tax liabilities:
Differences in financial and
tax bases of utility plant $ 699 $ 552
Regulatory balancing accounts 189 212
Loss on reacquired debt 19 22
Other 10 85
--------------------
Total deferred tax liabilities 917 871
--------------------
Deferred tax assets:
Investment tax credits 29 29
Unbilled revenue -- 29
Deferred compensation 76 46
Contingent liabilities 44 44
State income taxes 24 20
Federal benefit of state income taxes 29 24
Other 15 24
--------------------
Total deferred tax assets 217 216
--------------------
Net deferred income tax liability $ 700 $ 655
- ----------------------------------------------------------------------

The net deferred income tax liability is recorded on the Consolidated
Balance Sheets at December 31 as follows:

Dollars in millions) 2003 2002
- ----------------------------------------------------------------------
Current liability $ 83 $ 53
Noncurrent liability 617 602
--------------------
Total $ 700 $ 655
- ----------------------------------------------------------------------

Resolution of Certain Internal Revenue Service Matters

The company favorably resolved matters related to various prior years'
returns during 2003. The primary issue involving the treatment of
utility balancing accounts for the company was resolved following the
issuance of an IRS Revenue Ruling and resolution of factual issues
involving these claims with the IRS. The total after-tax earnings and
future cash flows for all IRS issues was $79 million.

NOTE 6. EMPLOYEE BENEFIT PLANS

Pension and Other Postretirement Benefits

The company has funded and unfunded noncontributory defined benefit
plans that together cover substantially all of its employees. The
plans provide defined benefits based on years of service and final
average salary.

55

The company also has other postretirement benefit plans covering
substantially all of its employees. The life insurance plans are
noncontributory and the health care plans are contributory, with
participants' contributions adjusted annually. Other postretirement
benefits include retiree life insurance, medical benefits for retirees
and their spouses.

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

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

There were no amendments to the company's pension and other
postretirement benefit plans in 2003.

December 31 is the measurement date for the pension and other
postretirement benefit plans.

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

56

The following table provides the amounts recognized on the Consolidated
Balance Sheets (in Deferred Credits and Other Liabilities) at
December 31:

At December 31, 2003, the company's pension plan had benefit
obligations in excess of its plan assets. The following table provides
certain information for that plan at December 31:

The following table provides the components of net periodic benefit
costs (income) for the years ended December 31:

57

The significant assumptions related to the company's pension and other
postretirement benefit plans are as follows:

The expected long-term rate of return on plan assets is derived from
historical returns for broad asset classes consistent with
expectations from a variety of sources, including pension consultants
and investment advisors.

58

Pension Plan Investment Strategy

The asset allocation for the Sempra Energy's pension trust (which
includes SDG&E's pension plan and other postretirement benefit plans,
except for the plans described below) at December 31, 2003 and 2002
and the target allocation for 2004 by asset categories are as follows:

The company's goal is to stay fully invested at all times and maintain its
strategic asset allocation, keeping the investment structure relatively
simple. The equity portfolio is balanced to maintain risk characteristics
similar to the S&P 1500 with respect to market capitalization, industry and
sector exposures. The foreign equity portfolios are managed to track the MSCI
Europe, Pacific Rim and Emerging Markets indexes. Bond portfolios are
managed with respect to the Lehman Aggregate Index. The plan does not invest
in Sempra Energy securities.

Investment Strategy for Postretirement Health Plans

The asset allocation for the company's postretirement health plans at
December 31, 2003 and 2002, and the target allocation for 2004 by
asset categories are as follows:

The company's postretirement health plans, which also are distinct from
other postretirement benefit plans included in Sempra Energy's pension
trust (see above), pay premiums to the health maintenance organization
and point-of-service plans from company and participant contributions.
The company's investment strategy is to match the long-term growth rate
of the liability primarily through the use of tax-exempt California
municipal bonds.

59

Future Payments

The company expects to contribute $23 million to its pension plan and
$7 million to its other postretirement benefit plans in 2004.

The following table reflects the total benefits expected to be paid to
current employees and retirees from the plans or from the company's
assets, including both the company's share of the benefit cost and,
where applicable, the participants' share of the costs, which is
funded by participant contributions to the plans.

Savings Plan

The company offers trusteed savings plan to all eligible employees.
Eligibility to participate in the plan is immediate for salary
deferrals. Employees may contribute, subject to plan provisions, from
one percent to 25 percent of their regular earnings. After one year of
completed service, the company begins to make matching contributions.
Employer contributions are equal to 50 percent of the first six
percent of eligible base salary contributed by employees and, if
certain company goals are met, an additional amount related to
incentive compensation payments.

Employer contributions are invested in Sempra Energy common stock and
must remain so invested until termination of employment or until the
employee's attainment of age 55, when they may be transitioned into
other investments. At the direction of the employees, the employees'
contributions are invested in Sempra Energy stock, mutual funds, or
institutional trusts. Company contributions to the savings plan were
$8 million in 2003, $7 million in 2002 and $5 million in 2001.

NOTE 7. STOCK-BASED COMPENSATION

Sempra Energy has stock-based compensation plans intended to align
employee and shareholder objectives related to the long-term growth of
the company. The plans permit a wide variety of stock-based awards,
including nonqualified stock options, incentive stock options,
restricted stock, stock appreciation rights, performance awards, stock
payments and dividend equivalents.

In 1995, SFAS 123, "Accounting for Stock-Based Compensation," was
issued. It encourages a fair-value-based method of accounting for
stock-based compensation. As permitted by SFAS 123, Sempra Energy and
its subsidiaries adopted only its disclosure requirements and continue
to account for stock-based compensation in accordance with the

60

provisions of Accounting Principles Board Opinion 25. See additional
discussion of SFAS 148, the amendment to SFAS 123, in Note 1.

Sempra Energy's subsidiaries record an expense for the plans to the
extent their employees participate in the plans, or that subsidiaries
are allocated a portion of Sempra Energy's costs of the plans. SDG&E
recorded expenses of $7 million, $1 million and $2 million in 2003,
2002 and 2001, respectively.

NOTE 8. FINANCIAL INSTRUMENTS

Fair Value

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

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

Accounting for Derivative Instruments and Hedging Activities

The company follows the guidance of SFAS 133 and related amendments
SFAS 138 and 149 (collectively SFAS 133) to account for its derivative
instruments and hedging activities. Derivative instruments and related
hedges are recognized as either assets or liabilities on the balance
sheet, measured at fair value. Changes in the fair value of derivatives
are recognized in earnings in the period of change unless the
derivative qualifies as an effective hedge that offsets certain
exposure.

SFAS 133 provides for hedge accounting treatment when certain criteria
are met. For derivative instruments designated as fair value hedges,
the gain or loss is recognized in earnings in the period of change
together with the offsetting gain or loss on the hedged item

61

attributable to the risk being hedged. For derivative instruments
designated as cash flow hedges, the effective portion of the derivative
gain or loss is included in other comprehensive income, but not
reflected in the Statements of Consolidated Income until the
corresponding hedged transaction is settled. The ineffective portion is
reported in earnings immediately. There was no effect on other
comprehensive income for the years ended December 31, 2003 and 2002. In
instances where derivatives do not qualify for hedge accounting, gains
and losses are recorded in the Statements of Consolidated Income.

The company utilizes energy and natural gas derivatives to manage
commodity price risk associated with servicing their load requirements.
These contracts allow the company to predict with greater certainty the
effective prices to be received by the company and the prices to be
charged to its customers. The use of derivative financial instruments
is subject to certain limitations imposed by company policy and
regulatory requirements. The company classifies its forward contracts
as follows:

Contracts that meet the definition of normal purchase and sales
generally are long-term contracts that are settled by physical delivery
and, therefore, are eligible for the normal purchases and sales
exception of SFAS 133. The contracts are accounted for under accrual
accounting and recorded in Revenues or Cost of Sales in the Statement
of Consolidated Income when physical delivery occurs. Due to the
adoption of SFAS 149, the company has determined that its natural gas
contracts entered into after June 30, 2003 generally do not qualify for
the normal purchases and sales exception.

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

62

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

(Dollars in millions) 2003 2002
- ---------------------------------------------------------------------
Fixed-priced contracts and other derivatives:
Current liabilities $ 59 $ 59
Noncurrent liabilities 502 579
----- -----
Total 561 638
Current assets (1) (2)
----- -----
Net liabilities $ 560 $ 636
===== =====
Regulatory assets and liabilities:
Current regulatory assets $ 59 $ 59
Noncurrent regulatory assets 502 579
----- -----
Total 561 638
Current regulatory liabilities (1) (2)
----- -----
Net regulatory assets $ 560 $ 636
===== =====

The above had no impact on net income during 2003 and a $1 million
impact in 2002.

Market Risk

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 instruments are
with major exchanges and other firms believed to be credit-worthy. The
use of these instruments exposes the company to market and credit risk,
which may at times be concentrated with certain counterparties,
although counterparty nonperformance is not anticipated.

Interest-Rate Risk Management

The company periodically enters into interest-rate swap agreements to
moderate exposure to interest-rate changes and to lower the overall
cost of borrowing. This is described in Note 3.

Energy Contracts

SDG&E records transactions for natural gas and electric energy
contracts in Cost of Natural Gas and Cost of Electric Fuel and
Purchased Power, respectively, in the Statements of Consolidated
Income. For open contracts not expected to result in physical delivery,
changes in market value of the contracts are recorded in these accounts
during the period the contracts are open, with an offsetting entry to a
regulatory asset or liability. The majority of the company's contracts
result in physical delivery. There was no impact on the Statements of
Consolidated Income for changes in the fair value of derivative
instruments, other than the $1 million gain for the year ended December
31, 2002 due to an interest-rate swap as discussed in Note 3.

63

NOTE 9. PREFERRED STOCK

All series of SDG&E's preferred stock have cumulative preferences as to
dividends. The $20 par value preferred stock has two votes per share on
matters being voted upon by shareholders of SDG&E and a liquidation
value at par, whereas the no-par-value preferred stock is nonvoting and
has a liquidation value of $25 per share, plus any unpaid dividends.
SDG&E is authorized to issue 10,000,000 shares of no-par-value
preferred stock (both subject to and not subject to mandatory
redemption). All series are callable at December 31, 2003. The $1.7625
Series has a sinking fund requirement to redeem 50,000 shares at $25
per share per year from 2004 to 2007; the remaining 750,000 shares must
be redeemed in 2008. On January 15, 2004, SDG&E redeemed 50,000 shares
at $25 per share.

NOTE 10. ELECTRIC INDUSTRY REGULATION

Background

The restructuring of California's electric utility industry has
significantly affected the company's electric utility operations, and
the power crisis of 2000-2001 caused the CPUC to significantly modify
its plan for restructuring the electricity industry. Supply/demand
imbalances and a number of other factors resulted in abnormally high
electric-commodity prices beginning in mid-2000 and continuing into
2001. This caused SDG&E's customer bills to be substantially higher
than normal. These higher prices were initially passed through to
customers and resulted in bills that in most cases were double or
triple those from 1999 and early 2000. This resulted in several
legislative and regulatory responses, including California Assembly
Bill (AB) 265. AB 265 imposed a ceiling on the cost of the electric

64

commodity that SDG&E could pass on to its small-usage customers from
June 1, 2000 to December 31, 2002.

SDG&E accumulated the amount that it paid for electricity in excess of
the ceiling rate in an interest-bearing balancing account (the AB 265
undercollection) and began recovering these amounts in rates charged
to customers following the end of the rate-ceiling period. At December
31, 2003, the AB 265 undercollection was $63 million (included in
Regulatory Balancing Accounts - Net on the Consolidated Balance
Sheets) and is being recovered in current rates.

Another legislative response to the power crisis resulted in the
purchase by the DWR of a substantial portion of the power requirements
of California's electricity users. Since early 2001, the DWR has
procured power for the utility procurement customers of each of the
California investor-owned utilities (IOUs) and the CPUC has
established the allocation of the power and its related cost
responsibility among the IOUs. Beginning on January 1, 2003, the IOUs
resumed some of its electric commodity procurement, whereas previously
the DWR had been purchasing the IOUs' entire net short position.

Department of Water Resources

The DWR's operating agreement with SDG&E, approved by the CPUC, governs
SDG&E's administration of the allocated DWR contracts. The agreement
provides that SDG&E is acting as a limited agent on behalf of the DWR in
undertaking energy sales and natural gas procurement functions under the
DWR contracts allocated to SDG&E's customers. Legal and financial risks
associated with these activities will continue to reside with the DWR.
Therefore, the revenues and costs associated with the contracts were not
included in the Statements of Consolidated Income during 2003. From
February 2001 until December 2002, the DWR was purchasing similar
amounts of power for SDG&E; the cost of that power was not included in
the Statements of Consolidated Income in 2001 or 2002. The
reasonableness of the IOU's administration and dispatch of the allocated
contracts will be reviewed by the CPUC in an annual proceeding.

In September 2003, the CPUC approved a $1 billion refund to consumers
of the three major California IOUs as a result of the DWR's lowering
its revenue requirement for 2003. The refund was returned to customers
in the form of a one-time bill credit. SDG&E's portion was 13.51
percent or about $135 million. The bill credit had no effect on SDG&E's
net income and net cash flows because customer savings are coming from
lower charges by the DWR, and SDG&E is merely transmitting the
electricity from the DWR to the customers, without taking title to the
electricity.

On January 8, 2004, the CPUC issued a decision on the final true-up of
DWR's 2001/2002 energy costs among California's three major investor-
owned electric utilities, resulting in SDG&E's customers being
allocated $59 million of additional costs. The amount from this true-up
is recoverable from ratepayers and will be included with SDG&E's
allocated share of DWR's 2004 Revenue Requirement and incorporated into
electric charges for 2004, which are expected to be decided in the
first half of 2004. This true-up will have a short-term effect on
SDG&E's cash flow but will not otherwise affect its results of

65

operations, since SDG&E merely passes through the costs to its
customers.

In October 2003, the CPUC initiated a proceeding to consider a
permanent methodology for allocating DWR's Revenue Requirement
beginning in 2004 through the remaining life of the DWR contracts. An
interim allocation based on the current 2003 methodology was utilized
beginning January 1, 2004, and is in effect until a decision is reached
on a permanent methodology (expected in the second quarter of 2004).
Once a permanent methodology is established, the impacts of the
decision will be applied retroactively back to January 1, 2004. This
delay could have an effect on SDG&E's rates and cash flows, but not on
its net income.

Power Procurement

In October 2001, the CPUC initiated an Order Instituting Ratemaking
(OIR) to establish ratemaking mechanisms that would enable California
investor-owned electric utilities to resume purchasing electric energy
and related services and hedging instruments to fulfill their
obligation to serve and meet the needs of their customers. In so doing,
the CPUC acknowledged that the utilities desired assurance of more
timely regulatory review and cost recovery for their procurement
activities and costs. In connection therewith, the CPUC OIR directed
the IOUs to resume electric commodity procurement to cover their net
short energy requirements by January 1, 2003. The net short position is
the difference between the amount of electricity needed to cover a
utility's customer demand and the power provided by owned generation
and existing contracts, including the long-term DWR power contracts
allocated to the customers of each IOU by the CPUC (see above).

The OIR also implemented recent legislation regarding procurement and
renewables portfolio standards and establishes a process for review
and approval of the IOUs' long-term (20-year) procurement plans. In
December 2002, the CPUC adopted SDG&E's 2003 short-term procurement
plan. That plan addressed SDG&E's procurement activities in 2003,
authorized contract terms for up to five years for transactions
entered into under the plans, and allowed for the hedging of first
quarter 2004 residual net short positions with transactions entered
into in 2003. SDG&E was required to purchase approximately 10 percent
of its customer requirements in 2003, based on the allocation of the
DWR power approved by the CPUC in December 2002. The CPUC authorized
SDG&E to acquire a variety of resource types and demand side
resources. A semi-annual cost review and rate revision mechanism is
established, and a trigger is established for more frequent changes if
undercollected commodity costs exceed five percent of annual, non-DWR
generation revenues, to provide for timely recovery of any
undercollections. Approval of SDG&E's 2003 short-term procurement plan
provided for SDG&E's return to procurement of its customers' needs on
January 1, 2003, consistent with the intent of the legislature and the
CPUC.

SDG&E filed its 20-year long-term resource plan covering its
anticipated procurement needs between 2004 and 2023 and its short-term
procurement plans for its anticipated procurement activities in 2004.
In decisions issued in December 2003 and January 2004, the CPUC

66

approved the 2004 procurement plan and provided policy guidance for
the filing of an updated 20-year resource plan in the spring of 2004.

On December 18, 2003, the CPUC issued a decision adopting SDG&E's
procurement plan for 2004. The decision delayed until 2004 further
CPUC direction on comprehensive policy guidance for the IOUs' long-
term resource plans. In the decision, the CPUC continued its
moratorium (subject to certain exceptions) on the IOUs' ability to
deal with their own affiliates in procurement transactions.

SDG&E's 20-year resource plan identified the near-term need for firm
capacity resources within its service territory to support transmission
grid reliability. As a result, SDG&E issued a Request for Proposals
(RFP) for the years 2005-2007 of 69 megawatts (MW) in 2005 increasing
to 291 MWs in 2007.

In October 2003, SDG&E filed a motion in the Procurement OIR that now
requests the CPUC to authorize SDG&E to enter into five new electric
resource contracts. They include:

The 550-megawatt combined-cycle Palomar power plant
in Escondido, California, to be constructed by Sempra
Energy Resources, an affiliate, for completion in
2006.

The 45-MW Ramco combustion turbine which SDG&E is
proposing to acquire as a turnkey project and intends
to use for intermediate load requirements beginning
June 2005.

(SDG&E will not take ownership of these two
facilities unless appropriate cost recovery and
ratemaking mechanisms are instituted by the CPUC to
ensure that SDG&E recovers all reasonable costs of,
and a reasonable return on, the investments.)

A power purchase agreement (PPA) to buy up to 570
megawatts over ten years starting in 2008 from a
power plant that Calpine Corporation (Calpine) would
complete on its site within SDG&E's service
territory. (SDG&E would recommend the Calpine PPA
only if the CPUC orders the implementation of certain
critical conditions intended to make the Calpine PPA
a positive economic benefit to SDG&E's customers.)

One contract each for a demand-response resource and
a renewable resource.

The capital cost related to the five contracts proposed by
SDG&E is $640 million. Hearings concluded on February 20,
2004, and a decision is expected in May 2004. Given the
CPUC's prior denial of the company's request for approval
of additional transmissions facilities, the company
believes that customer requirements for electricity could
not be met without the requested resources or similar
additions.

67

A June 2003 CPUC decision in the Procurement OIR directed each IOU to
procure from renewable sources at least one percent of its 2003 total
energy sales, increasing to 20 percent by 2017. SDG&E procured four
percent of its 2003 total energy sales from renewable sources and
existing contracts will increase this to five percent in 2004 and nine
percent in 2007. A 2002 CPUC resolution permits the company to credit
toward future years' compliance any excess over its one-percent annual
requirement.

SONGS

Through December 31, 2003, the operating and capital costs of SONGS
Units 2 and 3 were recovered through the ICIP mechanism which allowed
SDG&E to receive 4.4 cents per kilowatt-hour for SONGS generation. Any
differences between these costs and the incentive price affected net
income. For the year ended December 31, 2003, ICIP contributed $53
million to SDG&E's net income. Beginning in 2004, the CPUC has provided
for traditional rate-making treatment, under which the SONGS ratebase
would start over at January 1, 2004, essentially eliminating earnings
from SONGS except from future increases in ratebase.

FERC Actions

Refund Proceedings

The FERC is investigating prices charged to buyers in the PX and ISO
markets by various electric suppliers. The FERC is seeking to determine
the extent to which individual sellers have yet to be paid for power
supplied during the period of October 2, 2000 through June 20, 2001 and
to estimate the amounts by which individual buyers and sellers paid and
were paid in excess of competitive market prices. Based on these
estimates, the FERC could find that individual net buyers, such as
SDG&E, are entitled to refunds and individual net sellers are required
to provide refunds. To the extent any such refunds are actually
realized by SDG&E, they would reduce SDG&E's rate-ceiling balancing
account.

In December 2002, a FERC Administrative Law Judge (ALJ) issued
preliminary findings indicating that the California PX and ISO owe
power suppliers $1.2 billion (the $3.0 billion that the California PX
and ISO still owe energy companies less $1.8 billion that the energy
companies charged California customers in excess of the preliminarily
determined competitive market clearing prices). On March 26, 2003, the
FERC largely adopted the ALJ's findings, but expanded the basis for
refunds by adopting a staff recommendation from a separate
investigation to change the natural gas proxy component of the
mitigated market clearing price that is used to calculate refunds. The
March 26 order estimates that the replacement formula for estimating
natural gas prices will increase the refund obligations from $1.8
billion to more than $3 billion. The FERC recently released its final
instructions, and ordered the ISO and PX to recalculate the precise
number through their settlement models. California is seeking $8.9
billion in refunds from its electricity suppliers and has appealed the
FERC's preliminary findings and requested rehearing of the March 26
order.

68

Manipulation Investigation

The FERC is also investigating whether there was manipulation of short-
term energy markets in the West that would constitute violations of
applicable tariffs and warrant disgorgement of associated profits. In
this proceeding, the FERC's authority is not confined to the October 2,
2000 through June 20, 2001 period relevant to the refund proceeding. In
May 2002, the FERC ordered all energy companies engaged in electric
energy trading activities to state whether they had engaged in various
specific trading activities in violation of the PX and ISO tariffs
(generally described as manipulating or "gaming" the California energy
markets).

On June 25, 2003, the FERC issued several orders requiring various
entities to show cause why they should not be found to have violated
California ISO and PX tariffs. FERC directed 43 entities, including
SDG&E, to show cause why they should not disgorge profits from certain
transactions between January 1, 2000 and June 20, 2001 that are
asserted to have constituted gaming and/or anomalous market behavior
under the California ISO and/or PX tariffs. SDG&E and the FERC resolved
the matter by SDG&E's paying $28 thousand into a FERC-established fund.

On June 25, 2003, the FERC also determined that it was appropriate to
initiate an investigation into possible physical and economic
withholding in the California ISO and PX markets. For the purpose of
investigating economic withholding, the FERC used an initial screen of
all bids exceeding $250 per MW between May 1, 2000 and October 2, 2001.
SDG&E has received data requests from the FERC staff and has provided
responses. The FERC staff will prepare a report to the FERC, which will
be the basis to decide whether additional proceedings are warranted.
SDG&E believes that its bids and bidding procedures were consistent
with ISO and PX tariffs and protocols and applicable FERC price caps.
On August 1, 2003, the FERC staff issued an initial report that
determined there was no need to further investigate particular entities
for physical withholding of generation.

NOTE 11. OTHER REGULATORY MATTERS

Natural Gas Industry Restructuring

In December 2001 the CPUC issued a decision related to natural gas
industry restructuring (GIR), with implementation anticipated during
2002. On January 12, 2004, after many delays and changes, an ALJ issued
a proposed decision that would implement the 2001 decision. The
proposed decision would result in revising noncore balancing account
treatment to exclude the balancing of SoCalGas' transmission costs;
other noncore costs/revenues would continue to be fully balanced until
the decision in the next Biennial Cost Allocation Proceeding (BCAP)
(see below). On February 11, 2004, a member of the CPUC issued an
alternative decision that would vacate the December 2001 decision and
defer GIR matters to the Natural Gas Market OIR (see below). A CPUC
decision could be issued in March 2004.

Natural Gas Market OIR

The Natural Gas Market OIR was approved on January 22, 2004, and will
be addressed in two concurrent phases. The schedule calls for a Phase I

69

decision by summer 2004 and a Phase II decision by the end of 2004. In
Phase I the CPUC's objective is to develop a process enabling the CPUC
to review and pre-approve new interstate capacity contracts before they
are executed. In addition, the California Utilities must submit
proposals on any LNG project to which interconnection is planned,
providing costs and terms, including access to the pipelines in Mexico.
Phase II will primarily address emergency reserves and ratemaking
policies. The OIR invites proposals on how utilities should provide
emergency reserves consisting of slack intrastate pipeline capacity,
contracts for additional capacity on the interstate pipelines and an
emergency supply of natural gas storage. The CPUC's objective in the
ratemaking policy component of Phase II is to identify and propose
changes to policies that create incentives that are consistent with the
goal of providing adequate and reliable long-term supplies and that do
not conflict with energy efficiency programs. The focus of the Gas OIR
is 2006 to 2016. Since GIR (see above) would end in August 2006 and
there is overlap between GIR and the Gas OIR issues, a number of
parties (including SoCalGas) are advising the CPUC not to implement
GIR.

The company believes that regulation needs to consider sufficiently the
adequacy and diversity of supplies to California, transportation
infrastructure and cost recovery thereof, hedging opportunities to
reduce cost volatility, and programs to encourage and reward
conservation.

Cost of Service

The California Utilities have filed cost of service applications with
the CPUC, seeking rate increases reflecting forecasts of 2004 capital
and operating costs. SDG&E is requesting revenue increases of $76
million. The CPUC's Office of Ratepayer Advocates (ORA) filed its
prepared testimony on the applications in August 2003, recommending
numerous rate decreases that would reduce annual revenues by $41
million from their current level. The Utility Consumers' Action Network
(UCAN), a consumer-advocacy group, has proposed rates for SDG&E that
would reduce annual revenues by $88 million from their current level.
Hearings concluded in November 2003. On December 19, 2003, settlements
were filed with the CPUC that, if approved, would resolve most of the
cost of service issues. The SDG&E settlement was signed by SDG&E, ORA
and other parties, but not by UCAN, the City of Chula Vista and other
parties. The CPUC adopted a schedule for briefing and commenting on the
proposed settlements that concluded on February 19, 2004. The SDG&E
settlement would reduce its electric rates by $19.6 million from 2003
rates and increase its natural gas rates by $1.8 million from 2003
rates. As part of the proposed settlement, SDG&E and the ORA would
resolve their dispute concerning the allocation of the gain on sale of
SDG&E's surplus property in Blythe, California, by increasing SDG&E's
forecast of miscellaneous revenues by $1.3 million annually, thereby
lowering its retail revenue requirement by that amount. The CPUC may
accept one or both of the settlements or may adopt an outcome differing
from both of the settlements. Resolution is likely in the second
quarter of 2004.

On December 18, 2003, the CPUC issued a decision that creates
memorandum accounts as of January 1, 2004, to record the difference
between actual revenues and those that are later authorized in the

70

CPUC's final decision in this case. The difference would then be
amortized in rates. The California Utilities have also filed for
continuation through 2004 of existing performance-based regulation
(PBR) mechanisms for service quality and safety that would otherwise
expire at the end of 2003. In January 2004, the CPUC issued a decision
that extended 2003 service and safety targets through 2004, but
deferred action on applying any rewards or penalties for performance
relative to these targets to a decision to be issued later in 2004 in a
second phase of these applications discussed below.

The CPUC has established a procedural schedule for the second phase of
these applications, addressing issues related to PBR (see below). The
procedural schedule calls for hearings to be held in June 2004, with a
decision during 2004. The scope of the second phase includes: (a) a
formula for setting authorized cost of service for 2005 and succeeding
years until the next full Cost of Service proceeding is scheduled; (b)
whether and how rates should be adjusted if earned returns vary from
authorized returns; and (c) prospective targets and rewards/penalties
for service quality and safety.

An October 2001 decision denied the California Utilities' request to
continue equal sharing between ratepayers and shareholders of the
estimated savings for the 1998 business combination that created Sempra
Energy and, instead, ordered that all of the estimated 2003 merger
savings go to ratepayers. In 2002, merger savings to shareholders for
the fourth quarter and for the year were $2 million and $8 million,
respectively. Pursuant to the decision, SDG&E will return the 2003
merger savings related to natural gas operations of $15 million to
ratepayers over a twelve-month period beginning January 1, 2004. The
merger savings related to electric operations were previously returned
to ratepayers.

Performance-Based Regulation

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.

PBR consists of three primary components. The first is a mechanism to
adjust rates in years between general rate cases or cost of service
cases. Similar to the pre-PBR Attrition Proceeding, it annually
adjusts general rates from those of the prior year to provide for
inflation, changes in the number of customers and efficiencies.

The second component is a mechanism whereby any earnings in excess of
those authorized plus a narrow band above that are shared with
customers in varying degrees depending upon the amount of the
additional earnings.

The third component consists of a series of measures of utility
performance. Generally, if performance is outside of a band around the

71

specified benchmark, the utility is rewarded or penalized certain
dollar amounts.

The three areas that are eligible for PBR rewards or penalties 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 or penalties. The CPUC is also considering a new
reward/penalty related to electricity procurement, now that the
utilities are resuming this activity. However, as noted under "Cost of
Service," Phase II of the California Utilities' current cost of
service proceeding is not scheduled for completion until late 2004. As
a result, it is possible that some or all of the safety, reliability
and customer satisfaction incentive mechanisms (i.e., those that are
reviewed in the Cost of Service proceeding) would not be in effect for
2004. Even if that were to occur, it is not expected that the effect
would be other than a one-year moratorium on the mechanisms.

In July 2003, the CPUC issued a decision relative to SDG&E's Year 11
natural gas PBR application, which will permanently extend the PBR
mechanism with some modification. The decision approved the Joint
Parties' Motion for an Order Adopting Settlement Agreement filed by
SDG&E and the ORA, which will apply to Year 10 and beyond. The effect
of the modifications is to reduce slightly the potential size of future
PBR rewards or penalties.

Since the 1990s, IOUs have been eligible to earn awards for
implementing and administering energy conservation and efficiency
programs. The California Utilities have offered these programs to
customers and have consistently achieved significant earnings from the
program. On October 16, 2003, the CPUC issued a decision that the pre-
1998 DSM earnings proceeding would not be reopened, leaving the
earnings mechanism unchanged. The CPUC may adjust amounts determined
pursuant to the earnings mechanism consistent with the application of
known, standard measurement and verification protocols.

The CPUC has consolidated the 2000, 2001 and 2002 award applications.
The 2003 award applications were filed on May 1, 2003. On May 2, 2003,
the CPUC released RFPs to conduct a review of the IOUs' studies and
reported program milestones/accomplishments used as the basis for the
awards claims and program expenditures. The review should be completed
in the second quarter of 2004. Additionally, the low-income awards
will be subject to an independent review expected to commence in 2005.
The majority of the outstanding claims are on hold pending completion
of the independent review.

72

Incentive Awards Approved in 2003

PBR rewards are not included in the company's earnings before CPUC
approval is received. The following table reflects awards approved in
2003 (dollars in millions):

Program
-----------------------------------
Natural gas PBR Year 9 $ (1.4)
Natural gas PBR Year 8 6.7
Distribution PBR 2001 12.2
Distribution PBR 2002 6.0
-----------------------------------
Total $ 23.5
===================================

Pending Incentive Awards

At December 31, 2003, the following performance incentives were
pending CPUC approval and, therefore, were not included in the
company's earnings (dollars in millions):

Program
-----------------------------------
Natural gas PBR Year 10 $ 1.9
DSM/Energy Efficiency* 35.6
-----------------------------------
Total $ 37.5
===================================

* Dollar amounts shown do not include interest, franchise fees
or uncollectible amounts.

Cost of Capital

Effective January 1, 2003, SDG&E's authorized rate of return on equity
(ROE) is 10.9 percent and its return on ratebase is 8.77 percent, for
SDG&E's electric distribution and natural gas businesses. The
electric-transmission cost of capital is determined under a separate
FERC proceeding (see below). These rates will continue to be effective
until market interest-rate changes are large enough to trigger an
automatic adjustment or until the CPUC orders a periodic review.

The objective of SDG&E's market-indexed capital adjustment mechanism
is to revise SDG&E's rates to reflect changes in the six-month average
of double-A rated utility bond rates, without lengthy CPUC
proceedings. The benchmark average is currently 7.24 percent, the six-
month average at September 30, 2002, the year of SDG&E's last cost of
capital proceeding. If in any year the difference between the current
six-month average at September 30th and the benchmark exceeds 100
basis points, SDG&E's authorized ROE is adjusted by one-half of the
difference, and the embedded costs of debt and preferred equity are
adjusted to current levels. In addition, the triggering six-month
average becomes the new benchmark until another automatic adjustment
occurs. The six-month average was 6.32 percent at September 30, 2003
and, therefore, no triggering has occurred. The rate has not changed
significantly since then.

73

Border Price Investigation

In November 2002, the CPUC instituted an investigation into the
Southern California natural gas market and the price of natural gas
delivered to the California-Arizona border between March 2000 and May
2001. If the investigation determines that the conduct of any party to
the investigation contributed to the natural gas price spikes, the
CPUC may modify the party's natural gas procurement incentive
mechanism, reduce the amount of any shareholder award for the period
involved, and/or order the party to issue a refund to ratepayers.
Hearings are scheduled to begin in late March 2004 with a decision
expected by late 2004. The company believes that the CPUC will find
that SoCalGas acted in the best interests of its core customers.

Biennial Cost Allocation Proceeding

The BCAP determines the allocation of authorized costs between
customer classes for natural gas transportation service provided by
the company and adjusts rates to reflect variances in customer demand
as compared to the forecasts previously used in establishing
transportation rates. SDG&E filed with the CPUC its 2005 BCAP
application in September 2003, requesting updated transportation rates
effective January 1, 2005. The most recent BCAP decision allocating
the California Utilities non-commodity natural gas costs of service
and revising their respective natural gas transportation rates and
rate designs was issued in April 2000 and is still in effect. In
November 2003, an Assigned Commissioner Ruling delayed the current
BCAP applications until a decision is issued in the GIR implementation
proceeding discussed above. As a result, SDG&E is required to amend
its BCAP application 28 days after a decision in the GIR.

CPUC Investigation of Energy-Utility Holding Companies

The CPUC has initiated an investigation into the relationship between
California's IOUs and their parent holding companies. Among the
matters to be considered in the investigation are utility dividend
policies and practices and obligations of the holding companies to
provide financial support for utility operations under the agreements
with the CPUC permitting the formation of the holding companies. In
January 2002 the CPUC issued a decision to clarify under what
circumstances, if any, a holding company would be required to provide
financial support to its utility subsidiaries. The CPUC broadly
determined that it would require the holding company to provide cash
to a utility subsidiary to cover its operating expenses and working
capital to the extent they are not adequately funded through retail
rates. This would be in addition to the requirement of holding
companies to cover their utility subsidiaries' capital requirements,
as the IOUs have previously acknowledged in connection with the
holding companies' formations. In January 2002 the CPUC ruled on
jurisdictional issues, deciding that it had jurisdiction to create the
holding company system and, therefore, retains jurisdiction to enforce
conditions to which the holding companies had agreed. The company's
request for rehearing on the issues was denied by the CPUC and the
company subsequently filed appeals in the California Court of Appeal.
On November 26, 2003 the California Court of Appeal agreed to hear the
company's appeal. Oral argument is set for March 5, 2004.

74

CPUC Investigation of Compliance with Affiliate Rules

In February 2003, the CPUC opened an investigation of the business
activities of SDG&E, SoCalGas and Sempra Energy to determine if they
have complied with statutes and CPUC decisions in the management,
oversight and operations of their companies. In September 2003, the
CPUC suspended the procedural schedule until it completes an
independent audit to evaluate energy-related holding company systems
and affiliate activities undertaken by Sempra Energy within the service
territories of SDG&E and SoCalGas. The audit will cover years 1997
through 2003, is expected to commence in March 2004 and should be
completed by the end of 2004. The scope of the audit will be broader
than the annual affiliate audit. In accordance with existing CPUC
requirements, the California Utilities' transactions with other Sempra
Energy affiliates have been audited by an independent auditing firm
each year, with results reported to the CPUC, and there have been no
material adverse findings in those audits.

FERC Standards of Conduct

On November 25, 2003, the FERC established standards of conduct
governing the relationship between transmission providers and their
energy affiliates. They broaden the definition of an energy affiliate.
Under the standards, SDG&E is a transmission provider and SoCalGas is
an energy affiliate of SDG&E. The standards require transmission
providers to offer service to all customers on a non-discriminatory
basis.

FERC Transmission Cost of Service

On May 2, 2003, the FERC accepted SDG&E's request for modification of
its Transmission Owner Tariff to adopt a transmission rate formula that
would allow SDG&E to recover its actual prudent costs for transmission
service. New transmission rates, which are subject to refund based on
the FERC's final order, became effective October 1, 2003.

On December 18, 2003, the FERC approved the transmission formula, with
rates effective October 1, 2003, whereby SDG&E's rates would be
adjusted annually to cover actual prudent costs, including an ROE of
11.25 percent on its actual equity as of December 31 of the prior year.
SDG&E's revenue requirements for its retail customers for the initial
12-month period beginning October 1, 2003, will be $142.1 million.
SDG&E will fully recover its cancelled Valley-Rainbow Project costs of
$19 million over a ten-year amortization period, with no return
component. The transmission rate formula will be in effect through June
30, 2007.

Recovery of Certain Disallowed Transmission Costs

In August 2002 the FERC issued Opinion No. 458, which effectively
disallowed SDG&E's recovery of the differentials between certain
payments to SDG&E by its co-owners of the Southwest Powerlink under the
Participation Agreements and charges assessed to SDG&E under the ISO
FERC tariff for transmission line losses and grid management charges
related to energy schedules of Arizona Public Service Co. (APS) and the
Imperial Irrigation District (IID), its Southwest Powerlink co-owners.

75

As a result, SDG&E is incurring unreimbursed costs of $4 million to $8
million per year. On November 17, 2003, SDG&E petitioned the United
States Court of Appeals for review of these FERC orders and argued that
the disallowed costs should be allowed for recovery through the
Transmission Revenue Balancing Account Adjustment. On February 12,
2004, on the FERC's motion, the court remanded the case back to the
FERC for further consideration, "based on the FERC's representation
that it intends to act expeditiously on remand." The FERC has not yet
issued further orders in this matter.

In a separate but related matter, on July 6, 2001 SDG&E filed an
arbitration claim against the ISO claiming the ISO should not charge
SDG&E for the transmission losses attributable to energy schedules on
the APS and IID shares of the Southwest Powerlink. As of October 2003
amounts under the claim totaled $22 million, including interest. The
independent arbitrator found in SDG&E's favor on this matter. The ISO
appealed this result to the FERC and a FERC decision is expected in
2004. SDG&E has also commenced a private arbitration to reform the
Participation Agreements to remove prospectively SDG&E's obligation to
provide services giving rise to unreimbursed ISO tariff charges.

Southern California Fires

Several major wildfires that began on October 26, 2003 severely damaged
some of SDG&E's infrastructure, causing a significant number of
customers to be without utility services. On October 27, 2003, Governor
Gray Davis declared a "state of emergency" for counties within SDG&E's
service territory.

The declaration of a state of emergency authorizes a public utility to
establish a catastrophic event memorandum account (CEMA) to record all
incremental costs (costs not already included in rates) associated with
the repair of facilities and the restoration of service. Electric
distribution and natural gas related costs are recovered through the
CEMA. Electric transmission related costs are recovered through the
annual true-up FERC proceeding. The CEMA related costs are recoverable
in rates separate from ordinary costs currently recovered in rates. The
CPUC is required to hold expedited hearings in response to the
utilities' request for recovery. Total fire-related costs are estimated
to be $70 million with $60 million incurred during 2003, the majority
of which were capital related. At December 31, 2003, the CEMA account
included $14 million of incremental operating and maintenance costs.
The company expects to file a CEMA application sometime in 2004. The
company expects no significant effect on earnings from the fires.

NOTE 12. COMMITMENTS AND CONTINGENCIES

Natural Gas Contracts

SDG&E buys natural gas under short-term contracts. Short-term purchases
are from various Southwest U.S. and Canadian suppliers and are
primarily based on monthly spot-market prices. SDG&E transports natural
gas under long-term firm pipeline capacity agreements that provide for
annual reservation charges, which are recovered in rates.

SDG&E has long-term natural gas transportation contracts with various
interstate pipelines that expire on various dates between 2004 and

76

2023. SDG&E currently purchases natural gas on a spot basis to fill its
long-term pipeline capacity and purchases additional spot market
supplies delivered directly to California for its remaining
requirements. SDG&E continues its ongoing assessment of its long-term
pipeline capacity portfolio, including the release of a portion of this
capacity to third parties.

All of SDG&E's natural gas is delivered through SoCalGas' pipelines
under a short-term transportation agreement. In addition, under a
separate agreement expiring in March 2005, SoCalGas provides SDG&E
eight billion cubic feet of storage capacity.

At December 31, 2003, the future minimum payments under natural gas
storage and transportation contracts were:

(Dollars in millions)
- ----------------------------------------------------------------
2004 $ 20
2005 23
2006 16
2007 14
2008 14
Thereafter 142
------
Total minimum payments $ 229
- ----------------------------------------------------------------

Total payments under natural gas contracts were $274 million in 2003,
$205 million in 2002 and $457 million in 2001.

Purchased-Power Contracts

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

For 2004, SDG&E expects to receive 49 percent of its customer power
requirement from DWR allocations. Of the remaining requirements, SONGS
is expected to account for 21 percent, long-term contracts for 19
percent and spot market purchases for 11 percent. The contracts expire
on various dates through 2025. Prior to January 1, 2001, the cost of
these contracts was recovered by bidding them into the PX and receiving
revenue from the PX for bids accepted. As of January 1, 2001, in
compliance with a FERC order prohibiting sales to the PX, SDG&E no
longer bids those contracts into the PX. Those contracts are now used
to serve customers in compliance with a CPUC order. In addition, during

77

2002 SDG&E entered into contracts which will provide five percent of
its 2004 total energy sales from renewable sources. These contracts
expire on various dates through 2021.

At December 31, 2003, the estimated future minimum payments under the
long-term contracts (not including the DWR allocations) were:

(Dollars in millions)
- --------------------------------------------------------------------
2004 $ 214
2005 224
2006 233
2007 240
2008 218
Thereafter 2,235
--------
Total minimum payments $ 3,364
- --------------------------------------------------------------------

The payments represent capacity charges and minimum energy purchases.
SDG&E is required to pay additional amounts for actual purchases of
energy that exceed the minimum energy commitments. Excluding DWR-
allocated contracts, total payments under the contracts were $396
million in 2003, $235 million in 2002 and $512 million in 2001.

Leases

SDG&E has operating leases on real and personal property expiring at
various dates from 2004 to 2045. Certain leases on office facilities
contain escalation clauses requiring annual increases in rent ranging
from 3 percent to 6 percent. The rentals payable under these leases are
determined on both fixed and percentage bases, and most leases contain
extension options which are exercisable by SDG&E. SDG&E terminated its
capital lease agreement for nuclear fuel in mid-2001 and now owns its
nuclear fuel.

At December 31, 2003, the minimum rental commitments payable in future
years under all noncancellable leases were as follows:

(Dollars in millions)
- ------------------------------------------------------------
2004 $ 17
2005 16
2006 13
2007 11
2008 6
Thereafter 23
-----
Total future rental commitments $ 86
- ------------------------------------------------------------

Rent expense totaled $28 million in 2003, $27 million in 2002 and $21
million in 2001.

78

Environmental Issues

The company's operations are subject to federal, state and local
environmental laws and regulations governing hazardous wastes, air and
water quality, land use, solid waste disposal and the protection of
wildlife. These laws and regulations require that the company
investigate and remediate the effects of the release or disposal of
materials at sites associated with past and present operations,
including sites at which the company has been identified as a
Potentially Responsible Party (PRP) under the federal Superfund laws
and comparable state laws. Costs incurred to operate the facilities in
compliance with these laws and regulations generally have been
recovered in customer rates.

Significant costs incurred to mitigate or prevent future environmental
contamination or extend the life, increase the capacity, or improve the
safety or efficiency of property utilized in current operations, are
capitalized. The company's capital expenditures to comply with
environmental laws and regulations were $5 million in 2003, $4 million
in 2002 and $1 million in 2001. The cost of compliance with these
regulations over the next five years is not expected to be significant.

Costs that relate to current operations or an existing condition caused
by past operations are generally recorded as a regulatory asset due to
the expectation that these costs will be recovered in rates.

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

Environmental liabilities are recorded when the company's liability is
probable and the costs are reasonably estimable. In many cases,
however, investigations are not yet at a stage where the company has
been able to determine whether it is liable or, if the liability is
probable, to reasonably estimate the amount or range of amounts of the
cost or certain components thereof. Estimates of the company's
liability are further subject to other uncertainties, such as the
nature and extent of site contamination, evolving remediation standards
and imprecise engineering evaluations. The accruals are reviewed
periodically and, as investigations and remediation proceed,
adjustments are made as necessary. At December 31, 2003, the company's
accrued liability for environmental matters was $17.3 million, of which
$5.8 million related to manufactured-gas sites, $10.5 million to
cleanup at SDG&E's former fossil-fueled power plants, $0.9 million to
waste-disposal sites used by the company (which has been identified as
a PRP) and $0.1 million to other hazardous waste sites. These accruals
are expected to be paid ratably over the next two years.

79

Nuclear Insurance

SDG&E and the other owners of SONGS have insurance to respond to
nuclear liability claims related to SONGS. The insurance policy
provides $300 million in coverage, which is the maximum amount
available. In addition to this primary financial protection, the Price-
Anderson Act provides for up to $10.6 billion of secondary financial
protection if the liability loss exceeds the insurance limit. Should
any of the licensed/commercial reactors in the United States experience
a nuclear liability loss which exceeds the $300 million insurance
limit, all utilities owning nuclear reactors could be assessed under
the Price-Anderson Act to provide the secondary financial protection.
SDG&E and the other co-owners of SONGS could be assessed up to $201
million under the Price-Anderson Act. SDG&E's share would be $40
million unless a default was to occur by any other SONGS co-owner. In
the event the secondary financial protection limit were insufficient to
cover the liability loss, the Price-Anderson Act provides for Congress
to enact further revenue-raising measures to pay claims. These measures
could include an additional assessment on all licensed reactor
operators.

SDG&E and the other owners of SONGS have $2.75 billion of nuclear
property, decontamination and debris removal insurance. The coverage
also provides the SONGS owners up to $490 million for outage
expenses/replacement power incurred because of accidental property
damage. This coverage is limited to $3.5 million per week for the first
52 weeks, and $2.8 million per week for up to 110 additional weeks.
There is a deductible waiting period of 12 weeks prior to receiving
indemnity payments. The insurance is provided through a mutual
insurance company owned by utilities with nuclear facilities. Under the
policy's risk sharing arrangements, insured members are subject to
retrospective premium assessments if losses at any covered facility
exceed the insurance company's surplus and reinsurance funds. Should
there be a retrospective premium call, SDG&E could be assessed up to
$7.4 million.

Both the nuclear liability and property insurance programs include
industry aggregate limits for terrorism-related SONGS losses, including
replacement power costs.

Litigation

During 2003, the company recorded $11 million of after-tax charges
against income for litigation costs and possible resolution of certain
cases. Management believes that none of these matters will have further
material adverse effect on the company's financial condition or results
of operations. Except for the matters referred to below, neither the
company nor its subsidiary is party to, nor is its property the subject
of, any material pending legal proceedings other than routine
litigation incidental to its businesses.

Antitrust Litigation

Class-action and individual lawsuits filed in 2000 and currently
consolidated in San Diego Superior Court seek damages, alleging that
Sempra Energy, SoCalGas and SDG&E, along with El Paso Energy Corp. (El
Paso) and several of its affiliates, unlawfully sought to control

80

natural gas and electricity markets. In March 2003, plaintiffs in these
cases and the applicable El Paso entities announced that they had
reached a $1.5 billion settlement, of which $125 million is allocated
to customers of the California Utilities. The Court approved that
settlement in December 2003. The proceeding against Sempra Energy and
the California Utilities has not been settled and continues to be
litigated.

Natural Gas Cases: Similar lawsuits have been filed by the Attorneys
General of Arizona and Nevada, alleging that El Paso and certain Sempra
Energy subsidiaries unlawfully sought to control the natural gas market
in their respective states. In April 2003, Sierra Pacific Resources and
its utility subsidiary Nevada Power filed a lawsuit in U.S. District
Court in Las Vegas against major natural gas suppliers, including
Sempra Energy, the California Utilities and other company subsidiaries,
seeking damages resulting from an alleged conspiracy to drive up or
control natural gas prices, eliminate competition and increase market
volatility, breach of contract and wire fraud. On January 27, 2004, the
U.S. District Court dismissed the Sierra Pacific Resources case against
all of the defendants, determining that this is a matter for the FERC.

Electricity Cases: Various lawsuits, which seek class-action
certification, allege that Sempra Energy and certain company
subsidiaries, including SDG&E, unlawfully manipulated the electric-
energy market. In January 2003, the applicable federal court granted a
motion to dismiss a similar lawsuit on the grounds that the claims
contained in the complaint were subject to the Filed Rate Doctrine and
were preempted by the Federal Power Act. That ruling has been appealed
in the Ninth Circuit Court of Appeals, which is expected to hear the
appeal in the first quarter of 2004. Similar suits filed in Washington
and Oregon were voluntarily dropped by the plaintiffs without court
intervention in June 2003.

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

FERC Actions

Information regarding FERC actions related to the company is provided
in Note 10 of the notes to Consolidated Financial Statements.

Department Of Energy Nuclear Fuel Disposal

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

81

Electric Distribution System Conversion

Under a CPUC-mandated program, the cost of which is included in utility
rates, and through franchise agreements with various cities, SDG&E is
committed, in varying amounts, to converting overhead distribution
facilities to underground. As of December 31, 2003, the aggregate
unexpended amount of this commitment was $90 million. Capital
expenditures for underground conversions were $28 million in 2003, $33
million in 2002 and $12 million in 2001.

Concentration Of Credit Risk

The company grants credit to customers and counterparties,
substantially all of whom are located in its service territories, which
covers all of San Diego County and an adjacent portion of Orange
County.

NOTE 13. QUARTERLY FINANCIAL DATA (UNAUDITED)

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

None.

82

ITEM 9A. CONTROLS AND PROCEDURES

The company has designed and maintains disclosure controls and
procedures to ensure that information required to be disclosed in
the company's reports under the Securities Exchange Act of 1934
is recorded, processed, summarized and reported within the time
periods specified in the rules and forms of the Securities and
Exchange Commission and is accumulated and communicated to the
company's management, including its Chief Executive Officer and
Chief Financial Officer, as appropriate, to allow timely
decisions regarding required disclosure. In designing and
evaluating these controls and procedures, management recognizes
that any system of controls and procedures, no matter how well
designed and operated, can provide only reasonable assurance of
achieving the desired objectives and necessarily applies judgment
in evaluating the cost-benefit relationship of other possible
controls and procedures.

Under the supervision and with the participation of management,
including the Chief Executive Officer and the Chief Financial
Officer, the company as of December 31, 2003 has evaluated the
effectiveness of the design and operation of the company's
disclosure controls and procedures. Based on that evaluation, the
company's Chief Executive Officer and Chief Financial Officer
have concluded that the controls and procedures are effective.

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

83

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information required on Identification of Directors is
incorporated by reference from "Election of Directors" in the
Information Statement prepared for the May 2004 annual meeting of
shareholders. The information required on the company's executive
officers is provided below.

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

Edwin A. Guiles 54 Chairman and Chief Executive Officer

Debra L. Reed 47 President and Chief Financial Officer

James P. Avery 47 Senior Vice President, Electric
Transmission

Steven D. Davis 47 Senior Vice President, Customer
Service and External Relations

Margot A. Kyd 50 Senior Vice President, Corporate
Business Solutions

Roy M. Rawlings 59 Senior Vice President, Distribution
Operations

William L. Reed 51 Senior Vice President, Regulatory
Affairs

Lee M. Stewart 58 Senior Vice President, Gas
Transmission

Terry M. Fleskes 47 Vice President and Controller

* As of December 31, 2003.

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

ITEM 11. EXECUTIVE COMPENSATION

The information required by Item 11 is incorporated by reference from
"Election of Directors" and "Executive Compensation" in the Information
Statement prepared for the May 2004 annual meeting of shareholders.

84

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The security ownership information required by Item 12 is
incorporated by reference from "Share Ownership" in the
Information Statement prepared for the May 2004 annual meeting of
shareholders.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

None.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information regarding principal accountant fees and services as
required by Item 14 is incorporated by reference from "Proposal
3: Ratification of Independent Auditors" in the Proxy Statement
prepared for the May 2004 annual meeting of shareholders.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K

(a) The following documents are filed as part of this report:

1. Financial statements
Page in
This Report

Independent Auditors' Report . . . . . . . . . . . . . . 34

Statements of Consolidated Income for the years
ended December 31, 2003, 2002 and 2001 . . . . . . . . 35

Consolidated Balance Sheets at December 31,
2003 and 2002. . . . . . . . . . . . . . . . . . . . . 36

Statements of Consolidated Cash Flows for the
years ended December 31, 2003, 2002 and 2001 . . . . . 38

Statements of Consolidated Changes in
Shareholders' Equity for the years ended
December 31, 2003, 2002 and 2001 . . . . . . . . . . . 39

Notes to Consolidated Financial Statements . . . . . . . 40

2. Financial statement schedules

Other schedules for which provision is made in Regulation S-X are
not required under the instructions contained therein, are
inapplicable or the information is included in the Consolidated
Financial Statements and notes thereto.

85

3. Exhibits

See Exhibit Index on page 88 of this report.

(b) Reports on Form 8-K

The following reports on Form 8-K were filed after September 30,
2003:

Current Report on Form 8-K filed November 6, 2003, filing as an
exhibit Sempra Energy's press release of November 6, 2003, giving
the financial results for the three months ended September 30,
2003.

Current Report on Form 8-K filed December 31, 2003, to update
information on the August 25, 2003 CPUC decision regarding the
allocation of profits from intermediate-term purchase power
contracts. Updates when the Court of Appeals will have a decision
on the petition submitted by an advocacy group for small
consumers.

Current Report on Form 8-K filed February 24, 2004, filing as an
exhibit Sempra Energy's press release of February 24, 2004, giving
the financial results for the three months ended December 31, 2003.

86

INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in
Registration Statement Numbers 33-45599, 33-52834, 333-
52150, and 33-49837 on Form S-3 of our report dated
February 23, 2004, appearing in the Annual Report on Form
10-K of San Diego Gas and Electric Company for the year
ended December 31, 2003.

/S/ DELOITTE & TOUCHE LLP

San Diego, California
February 24, 2004

87

SIGNATURES

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

SAN DIEGO GAS & ELECTRIC COMPANY

By: /s/ Edwin A. Guiles
.
Edwin A. Guiles
Chairman and Chief Executive Officer

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

88

EXHIBIT INDEX

The Forms 8-K, 10-K and 10-Q referred to herein were filed under
Commission File Number 1-3779 (SDG&E), Commission File Number 1-
11439 (Enova Corporation), Commission File Number 1-14201 (Sempra
Energy) and/or Commission File Number 333-30761, (SDG&E Funding
LLC).

Exhibit 1 -- Underwriting Agreements

1.01 Underwriting Agreement dated December 4, 1997 (Incorporated by
reference from Form 8-K filed by SDG&E Funding LLC on
December 23, 1997 (Exhibit 1.1)).

Exhibit 3 -- Bylaws and Articles of Incorporation

Bylaws

3.01 Restated Bylaws of San Diego Gas & Electric as of November 6,
2001. (2001 Form 10-K Exhibit 3.01)

Articles of Incorporation

3.02 Amended and Restated Articles of Incorporation of San Diego Gas
& Electric Company (Incorporated by reference from the SDG&E
Form 10-Q for the three months ended March 31, 1994
(Exhibit 3.1)).

Exhibit 4 -- Instruments Defining the Rights of Security Holders,
Including Indentures

The Company agrees to furnish a copy of each such instrument to the
Commission upon request.

4.01 Mortgage and Deed of Trust dated July 1, 1940. (Incorporated
by reference from SDG&E Registration No. 2-49810, Exhibit 2A.)

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

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

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

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

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

89

Exhibit 10 -- Material Contracts

10.01 Operating Agreement between San Diego Gas & Electric and the
California Department of Water Resources dated April 17, 2003
(2003 Sempra Energy Form 10-K, Exhibit 10.06).

10.02 Servicing Agreement between San Diego Gas & Electric and the
California Department of Water Resources dated December 19, 2002
(2003 Sempra Energy Form 10-K, Exhibit 10.07).

10.03 Transition Property Purchase and Sale Agreement dated December
16, 1997 (Incorporated by reference from Form 8-K filed by
SDG&E Funding LLC on December 23, 1997, Exhibit 10.1).

10.04 Transition Property Servicing Agreement dated December 16, 1997
(Incorporated by reference from Form 8-K filed by SDG&E Funding
LLC on December 23, 1997, Exhibit 10.2).

Compensation

10.05 2003 Sempra Energy Executive Incentive Plan B (2003 Sempra Energy
Form 10-K, Exhibit 10.10).

10.06 2003 Executive Incentive Plan (June 30, 2003 Sempra Energy
Form 10-Q Exhibit 10.1)

10.07 Amended 1998 Long-Term Incentive Plan (June 30, 2003 Sempra
Energy Form 10-Q Exhibit 10.2)

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

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

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

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

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

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

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

90

Financing

10.15 Loan agreement with the City of Chula Vista in connection
with the issuance of $25 million of Industrial Development
Bonds, dated as of October 1, 1997 (Enova 1997 Form 10-K,
Exhibit 10.34).

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

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

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

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

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

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

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

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

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

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

91

Nuclear

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

10.27 Amendment No. 1 to the Qualified CPUC Decommissioning Master
Trust Agreement dated September 22, 1994 (see Exhibit 10.26
herein)(1994 SDG&E Form 10-K, Exhibit 10.56).

10.28 Second Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station
(see Exhibit 10.26 herein)(1994 SDG&E Form 10-K, Exhibit 10.57).

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

10.30 Fourth Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station
(see Exhibit 10.26 herein)(1996 Form 10-K, Exhibit 10.60).

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

10.32 Sixth Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station
(see Exhibit 10.26 herein)(1999 Form 10-K, Exhibit 10.27).

10.33 Seventh Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station
(see Exhibit 10.26 herein)(2003 Sempra Energy Form 10-K,
Exhibit 10.42).

10.34 Nuclear Facilities Non-Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station,
approved November 25, 1987 (1992 SDG&E Form 10-K, Exhibit 10.8).

10.35 First Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Non-Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station
(see Exhibit 10.34 herein)(1996 Form 10-K, Exhibit 10.62).

10.36 Second Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Non-Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station
(see Exhibit 10.34 herein)(1996 Form 10-K, Exhibit 10.63).

92

10.37 Third Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Non-Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station
(see Exhibit 10.34 herein)(1999 Form 10-K, Exhibit 10.31).

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

10.39 Fifth Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Non-Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station
(see Exhibit 10.34 herein)(2003 Sempra Energy Form 10-K,
Exhibit 10.48).

10.40 Second Amended San Onofre Operating Agreement among Southern
California Edison Company, SDG&E, the City of Anaheim and
the City of Riverside, dated February 26, 1987 (1990 SDG&E
Form 10-K, Exhibit 10.6).

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

Natural Gas Transportation and Storage

10.42 Master Services Contract (Intrastate Transmission Service),
dated August 1, 2003(month to month) to August 1, 2005 between
San Diego Gas & Electric Company and Southern California Gas Company.
(1998 10-K, Exhibit 10.64)

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

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

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

Other

10.46 Lease agreement dated as of March 25, 1992 with CarrAmerica
Development and Construction as lessor of an office
complex at Century Park (1994 SDG&E Form 10-K, Exhibit 10.70).

93

Exhibit 12 -- Statement Re: Computation Of Ratios

12.01 Computation of Ratio of Earnings to Combined Fixed Charges
and Preferred Stock Dividends for the years ended
December 31, 2003, 2002, 2001, 2000, and 1999.

Exhibit 21 - Subsidiaries

21.01 Schedule of Subsidiaries at December 31, 2003.

Exhibit 23 - Independent Auditors' Consent, page 86.

Exhibit 31 -- Section 302 Certifications

31.1 Statement of Registrant's Chief Executive Officer pursuant
to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

31.2 Statement of Registrant's Chief Financial Officer pursuant
to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

Exhibit 32 -- Section 906 Certifications

32.1 Statement of Registrant's Chief Executive Officer pursuant
to 18 U.S.C. Sec. 1350.

32.2 Statement of Registrant's Chief Financial Officer pursuant
to 18 U.S.C. Sec. 1350.

94

GLOSSARY

AB California Assembly Bill

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

AFUDC Allowance for Funds Used During Construction

ALJ Administrative Law Judge

APS Arizona Public Service Co.

BCAP Biennial Cost Allocation Proceeding

Bcf One Billion Cubic Feet (of natural gas)

Calpine Calpine Corporation

CEC California Energy Commission

CEMA Catastrophic Event Memorandum Act

CPUC California Public Utilities Commission

DOE Department of Energy

DSM Demand-Side Management

DWR Department of Water Resources

Edison Southern California Edison Company

EG Electric Generation

EITF Emerging Issues Task Force

El Paso El Paso Energy Corp.

EMFs Electric and Magnetic Fields

Enova Enova Corporation

ERMG Energy Risk Management

ERMOC Energy Risk Management Oversight Committee

EPA Environmental Protection Agency

FASB Financial Accounting Standards Board

FERC Federal Energy Regulatory Commission

FIN FASB Interpretation No.

FSP FASB Staff Position

95

GIR Gas Industry Restructuring

ICIP Incremental Cost Incentive Mechanism

IID Imperial Irrigation District

Intertie Pacific Intertie

IOUs Investor-Owned Utilities

IRS Internal Revenue Service

ISO Independent System Operator

LIFO Last in first out inventory costing method

LNG Liquefied Natural Gas

MGP Manufactured-Gas Plants

mmbtu Million British Thermal Units (of natural gas)

Moody's Moody's Investor Service, Inc.

MW Megawatt

NRC Nuclear Regulatory Commission

OIR Order Instituting Ratemaking

ORA Office of Ratepayers Advocates

PBR Performance-Based Ratemaking/Regulation

PG&E Pacific Gas and Electric Company

PGE Portland General Electric Company

PIER Public Interest Energy Research

PPA Purchase Power Agreement

PRPs Potentially Responsible Parties

PX Power Exchange

QFs Qualifying Facilities

RD&D Research, Development and Demonstration

RFP Requests For Proposals

ROE Return on Equity

S&P Standard & Poor's

96

SDG&E San Diego Gas & Electric Company

SFAS Statement of Financial Accounting Standards

SoCalGas Southern California Gas Company

SONGS San Onofre Nuclear Generating Station

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

UCAN Utility Consumers Action Network

VaR Value at Risk