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

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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[X] Annual report pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934 for the fiscal year ended December 31, 2004
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OR
[ ] Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the transition period from to
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SAN DIEGO GAS & ELECTRIC COMPANY
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(Exact name of registrant as specified in its charter)

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

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

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

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

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

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

Exhibit Index on page 90. Glossary on page 96.

Aggregate market value of the voting preferred stock held by non-affiliates of
the registrant as of January 31, 2005 was $23.7 million.

Registrant's common stock outstanding as of January 31, 2005 was wholly owned
by Enova Corporation.

DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Information Statement prepared for the May 2005 annual meeting
of shareholders are incorporated by reference into Part III.

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TABLE OF CONTENTS

PART I
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . 3
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . 17
Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . . 17
Item 4. Submission of Matters to a Vote of Security Holders. . 18

PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . . 18
Item 6. Selected Financial Data. . . . . . . . . . . . . . . . 19
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . 19
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk . . . . . . . . . . . . . . . . . 32
Item 8. Financial Statements and Supplementary Data. . . . . . 33
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . 83
Item 9A. Controls and Procedures. . . . . . . . . . . . . . . . 83
Item 9B. Other Information. . . . . . . . . . . . . . . . . . . 83

PART III
Item 10. Directors and Executive Officers of the Registrant . . 85
Item 11. Executive Compensation . . . . . . . . . . . . . . . . 86
Item 12. Security Ownership of Certain Beneficial Owners
and Management and Related Stockholder Matters. . . 86
Item 13. Certain Relationships and Related Transactions . . . . 86
Item 14. Principal Accountant Fees and Services . . . . . . . . 86

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

Consent of Independent Registered Public Accounting Firm. . . . 88

Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . 89

Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . 90

Glossary. . . . . . . . . . . . . . . . . . . . . . . . . . . . 96

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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,
the California State Legislature, the California Department of Water
Resources, and the Federal Energy Regulatory Commission and other
regulatory bodies in the United States; capital markets conditions,
inflation rates, interest rates and exchange rates; energy and trading
markets, including the timing and extent of changes in commodity
prices; the availability of natural gas; weather conditions and
conservation efforts; war and terrorist attacks; business, regulatory,
environmental and legal decisions and requirements; 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."

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Company Website

The company's website address is http://www.sdge.com/ and Sempra
Energy'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 California Public Utilities Commission (CPUC), which consists
of five commissioners appointed by the Governor of California for
staggered six-year terms, regulates SDG&E's rates (except
electric transmission rates, which are regulated by the Federal
Energy Regulatory Commission (FERC)) and conditions of service,
sales of securities, rates of return, rates of depreciation,
uniform systems of accounts, examination of records and long-term
resource procurement. The CPUC conducts various reviews of
utility performance (including reasonableness and prudency
reviews) and affiliate relationships 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. Various proceedings involving the CPUC
and relating to SDG&E's rates, costs, incentive mechanisms,
performance-based regulation and compliance with affiliate and
holding company rules 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.

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To promote efficient operations and improved productivity and to
move away from reasonableness reviews and disallowances, the CPUC
adopted Performance-Based Regulation (PBR) for the California
Utilities. Under PBR, regulators require future income potential
to be tied to achieving or exceeding specific performance and
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;
energy efficiency 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 their earnings and cash
flows.

The FERC regulates electric transmission rates, 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 their 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

The California Utilities' future results of operations and
financial condition may be materially adversely affected by the
outcome of pending litigation against them.
The California energy crisis of 2000 and 2001 has generated
numerous lawsuits, governmental investigations and regulatory
proceedings involving many energy companies, including Sempra
Energy and the California Utilities. They are the remaining
defendants in class action and individual antitrust and unfair
competition lawsuits scheduled for a jury trial to begin in
September 2005 in which the plaintiffs have asserted that they
are entitled to recover $24 billion in damages. Additional
lawsuits have been filed by the Attorney General of Nevada and by
others. They are also responding to an ongoing investigation
being conducted by the California Attorney General and an ongoing
CPUC proceeding related to the increase in natural gas prices at
the California-Arizona border in 2000-2001. The California
Utilities have expended and continue to expend substantial
amounts defending these lawsuits and in connection with related
investigations and regulatory proceedings. If these matters are
ultimately resolved unfavorably to the California Utilities,
their results of operations and financial condition and those of
Sempra Energy may be materially adversely affected.

These proceedings are discussed in the notes to Consolidated
Financial Statements and in "Management's Discussion and Analysis
of Financial Condition and Results of Operations" herein.
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 and storage
facilities may be damaged by natural disasters, catastrophic accidents
or acts of terrorism. Any such incidents could result in severe
business disruptions, significant decreases in revenues or significant
additional costs to the company, which could have a material adverse
effect on 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 or property belonging to third parties, or personal injuries,
which could lead to significant claims against the company. Insurance
coverage may become unavailable for certain of these risks and the
insurance proceeds received for any loss of or damage to any of its
facilities, or for any loss of or damage to natural resources or
property or personal injuries caused by its operations, may be

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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. This investigation is
discussed further in Note 11 of the notes to Consolidated Financial
Statements herein.

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

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. Further discussion is provided 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.

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Local Regulation

SDG&E has electric franchises with the two counties and the 26 cities
in its electric service territory, and natural gas franchises with the
one county and the 18 cities in its natural gas service territory.
These franchises allow SDG&E to locate, operate and maintain facilities
for the transmission and distribution of electricity and/or natural gas
in streets and other public places. The franchises do not have fixed
terms, except for the electric and natural gas franchises with the
cities of Encinitas (2012), San Diego (2021), Coronado (2028) and Chula
Vista (2014), and the natural gas franchises with the city of Escondido
(2036) and the county of San Diego (2030).

Licenses and Permits

SDG&E obtains numerous permits, authorizations and licenses in
connection with the transmission and distribution of natural gas and
electricity. They 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 UTILITY OPERATIONS

Customers

At December 31, 2004 the company had 1.3 million meters
consisting of 1,170,000 residential, 139,000 commercial, 460
industrial, 1,940 street and highway lighting, and 7,700 direct
access. The company's service area covers 4,100 square miles. The
company added 22,000 new electric customer meters in 2004 and
18,000 in 2003, representing growth rates of 1.7% and 1.4%
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 Notes 10, 11 and 12 herein.

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, 2004, the supply of electric power
available to SDG&E is as follows:

8

Under the contract with PGE, SDG&E pays a capacity charge plus a
charge based on the amount of energy received and/or PGE's non-
fuel costs. Costs under the contracts with QFs are based on
SDG&E's avoided cost. Charges under the remaining contracts are
for firm and 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. Decommissioning of
Unit 1 is now in progress and its spent nuclear fuel is being
stored on site.

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

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

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

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
approximately $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 and the
storage and movement of spent fuel is provided in Notes 10 and
12, respectively, of the notes to Consolidated Financial
Statements herein.

11

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 and information in order to increase
efficiency and competition in the bulk power market. Participants
are able to make power transactions on standardized terms that
have been pre-approved by the FERC.

Transmission Arrangements

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

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'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, discussed in
"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. The FERC approved the California IOUs'
transfer of operation and control of their transmission
facilities to the ISO in 1998. Additional information regarding
the FERC, ISO and transmission issues are provided in Note 11 of
the notes to Consolidated Financial Statements herein.

NATURAL GAS UTILITY OPERATIONS

Resource Planning and Natural Gas Procurement and Transportation

SDG&E is engaged in the purchase and distribution of natural gas.
The company's resource planning, power 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.

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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, wholesale, large commercial and industrial customers.

Most core customers purchase natural gas directly from the
company. Core customers are permitted to aggregate their natural
gas requirements 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
contracts. Short-term purchases are primarily based on monthly
spot-market prices.

SDG&E has long-term natural gas transportation contracts with
various interstate pipelines that expire on various dates between
2005 and 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 pipeline capacity portfolio, including the
release of a portion of this capacity to third parties. In
accordance with regulatory directives, SDG&E will reconfigure its
pipeline capacity portfolio by November 2005 to secure firm
transportation rights from a diverse mix of U.S. and Canadian
supply sources for its projected core customer natural gas
requirements. All of SDG&E's natural gas is delivered through
SoCalGas' pipelines under a short-term transportation agreement.
In addition, under a separate agreement expiring in March 2006,
SoCalGas provides SDG&E eight billion cubic feet of storage
capacity.

According to "Btu's Daily Gas Wire", the annual average spot
price of natural gas at the California/Arizona border was $5.53
per million British thermal unit (mmbtu) in 2004 ($6.35 per mmbtu
in December 2004), compared with $5.10 per mmbtu in 2003 and
$3.14 per mmbtu in 2002. Prices for natural gas increased toward
the end of 2002, 2003 and in 2004. The company's weighted average
cost (including transportation charges) per mmbtu of natural gas
was $6.11 in 2004, $5.14 in 2003 and $3.76 in 2002.

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.

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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, natural gas use by electric generators is
impacted by the availability of alternative sources of
generation. The availability of hydroelectricity is highly
dependent on precipitation in the western United States. In
addition, natural gas use is impacted by the performance of other
generation sources in the western United States, including
nuclear and coal, and other natural gas facilities outside the
service area. Natural gas use is also 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 SDG&E's service
area than within it. This new generation will likely displace the
output of older, less efficient local generation, reducing use of
natural gas for local electric generation.

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 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 12,000 and 11,000 natural gas new
customer meters in 2004 and 2003, respectively, representing
growth rates of 1.5 percent and 1.4 percent, respectively. The
company expects that its growth rate for 2005 will approximate
that for 2004.

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, including the

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relationship between worldwide supply and demand, and the
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 from
storage during the winter months (usually November through March) when
customer demand is higher.

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. Cleanup costs at sites related to electric
generation were specifically excluded from the collaborative by the
CPUC. Recovery of 90 percent of hazardous waste cleanup costs and
related third-party litigation costs, and 70 percent of the related
insurance-litigation expenses is permitted. In addition, the company
has the opportunity to retain a percentage of any insurance recoveries
to offset the 10 percent of costs not recovered in rates.

During the early 1900s, SDG&E and its predecessors manufactured gas
from coal or oil. The manufactured-gas plants (MGPs) often have become
contaminated with the hazardous residual by-products of the process.
SDG&E identified three former MGPs, two of which were remediated in
1998 and 2000, with closure letters being received. The estimated
remaining remediation liability on the third site is $1.8 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. Estimated costs to perform the necessary remediation are
$11 million. These costs were offset against the sales price for the

15

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 during 2005.
In 2003, cleanup was completed at the Encina power plant site at a cost
of $0.8 million. In 2004, cleanup was completed at two combustion
turbine sites at a cost of $0.7 million.

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.

The company and 10 other entities have been named potentially
responsible parties (PRPs) by the Department of Toxic Substance Control
(DTSC) as liable for any required corrective action regarding
contamination at an industrial waste disposal site in Pico Rivera,
California. DTSC has taken this action because SDG&E and others sold
used transformers to the site's owner. SDG&E and the other PRPs have
entered into a cost-sharing agreement to provide funding for the
implementation of a consent order between DTSC and the site owner for
the development of a cleanup plan. SDG&E's interim share under the
agreement is 10 percent, subject to adjustment based on allocations of
responsibility. The total estimate for all PRPs is $1 million for the
development of the cleanup plan and $2 million to $8 million for the
actual cleanup. Since inception, SDG&E's share of the cleanup expenses
and plan development was $0.2 million. Cleanup is expected to commence
in 2005.

At December 31, 2004, the company's estimated remaining investigation
and remediation liability related to hazardous waste sites, including
the MGPs, was $2.7 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

16

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. During 2004, the
CPUC instituted a rulemaking to re-examine its policies related to EMFs
and determine whether the current mitigation policies and utility
directives should be updated in light of science that has developed
over the last decade.

Air and Water Quality

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

The transmission and distribution of natural gas require the operation
of compressor stations, which are subject to increasingly stringent
air-quality standards. Costs to comply with these standards are
recovered in rates.

In connection with the issuance of operating permits, SDG&E and the
other owners of SONGS previously reached agreement with the California
Coastal Commission to mitigate the environmental damage to the marine
environment attributed to the cooling-water discharge from SONGS Units
2 and 3. This mitigation program includes an enhanced fish-protection
system, a 150-acre artificial 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 million. These mitigation projects
are expected to be completed in 2008. Through December 31, 2003, SONGS
mitigation costs were recovered through the ICIP mechanism. SONGS
mitigation costs incurred after December 31, 2003, are being
capitalized and recovered from ratepayers over the remaining life of
the SONGS units, subject to CPUC approval in the Edison 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 2004, the CPUC authorized SDG&E to fund $1.2 million and $5.7
million for its natural gas and electric RD&D programs, respectively,
including $5.7 million to the CEC for its PIER (Public Interest Energy

17

Research) Program. SDG&E's annual RD&D costs have averaged $6.5 million
over the past three years.

Employees of Registrant

As of December 31, 2004, the company had 4,405 employees, compared to
4,441 at December 31, 2003.

Labor Relations

Certain employees at SDG&E are represented by the Local 465
International Brotherhood of Electrical Workers. The current contract
is in effect through August 31, 2008.

ITEM 2. PROPERTIES

Electric Properties

SDG&E's interest in SONGS is described in "Electric Resources" herein.
At December 31, 2004, 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 1,814 miles of transmission
lines and 21,433 miles of distribution lines. Periodically, various
areas of the service territory require expansion to accommodate
customer growth.

Natural Gas Properties

At December 31, 2004, 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, 7,969 miles of high and low pressure distribution mains, and
6,155 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

SDG&E and the County of San Diego are continuing to negotiate the
remaining terms of a settlement relating to alleged environmental law
violations by SDG&E and its contractors in connection with the
abatement of asbestos-containing materials during the demolition of a
natural gas storage facility in 2001. SDG&E expects that any settlement
with the County would involve payments by SDG&E of less than $750,000.
In January 2005, Sempra Energy and SDG&E received a grand jury subpoena
from the United States Attorney's Office in San Diego seeking documents
related to this matter. The companies are fully cooperating with the
investigation.

18

Except for the matters described above and 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.

19

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 of the 2004 Annual Report includes management's discussion
and analysis of operating results from 2002 through 2004, and provides
information about the capital resources, liquidity and financial
performance of SDG&E. 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 Annual
Report.

The company is an operating public utility engaged in the electric and
natural gas businesses, servicing 3.3 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

20

natural gas through 800,000 meters in San Diego County and transports
electricity and natural gas for others. SDG&E's service area
encompasses 4,100 square miles. SDG&E's only subsidiary is SDG&E
Funding LLC, which was formed to facilitate the issuance of SDG&E's
rate reduction bonds described in Note 3 of the notes to Consolidated
Financial Statements. SDG&E is a substantially wholly owned indirect
subsidiary of Sempra Energy. SDG&E and its sister utility, Southern
California Gas Company (SoCalGas), which distributes natural gas
throughout most of Southern California and a portion of central
California, are collectively referred to herein as "the California
Utilities."

RESULTS OF OPERATIONS

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

(Dollars in millions)
- ------------------------
2004 $ 213
2003 $ 340
2002 $ 209
2001 $ 183
2000 $ 151
- ------------------------

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

The company is subject to various regulatory bodies and rules at
national, state and local levels. The primary regulatory body is the
California Public Utilities Commission (CPUC), which regulates utility
rates and operations. The Federal Energy Regulatory Commission (FERC)
regulates interstate transportation of natural gas and electricity and
various related matters. The Nuclear Regulatory Commission regulates
nuclear generating plants. Municipalities and other local authorities
regulate the location 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 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.

In 2003, 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. In addition,
the IOU's resumed their electric commodity procurement function for

21

power requirements in excess of that provided by the DWR's contracts
allocated to them. This is discussed further in Note 10 of the notes to
Consolidated Financial Statements and under "Factors Influencing Future
Performance."

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

Electric Revenue and Cost of Electric Fuel and Purchased Power.
Electric revenues decreased to $1,678 million in 2004 from $1,802
million in 2003, and the cost of electric fuel and purchased power
increased to $0.6 billion in 2004 from $0.5 billion in 2003. The
decrease in revenues was due to more power being provided to SDG&E's
customers by the DWR in 2004 as discussed in Note 10 of the notes to
Consolidated Financial Statements, offset partially by higher electric
commodity costs. Additionally, 2003 revenue included the recognition of
$116 million related to the approved settlement of intermediate-term
purchase power contracts in the third quarter of 2003 and higher
earnings from Performance-Based Regulation (PBR) awards. Performance
awards are discussed in Note 11 of the notes to Consolidated Financial
Statements. The increased costs were primarily attributable to the
higher electric commodity costs and higher volumes, offset partially by
the increased power being provided by the DWR.

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. The changes were

22

attributable to several factors, including the effect of the DWR's
purchasing the net short position of SDG&E during 2002, and higher
electric commodity costs and volumes. In addition, the increase in
revenue was due to the settlement of the intermediate-term purchase
power contracts and higher PBR awards in 2003 and the increase in
authorized distribution revenue.

Natural Gas Revenue and Cost of Natural Gas. Natural gas revenues
increased to $596 million in 2004 from $509 million in 2003, and the
cost of natural gas increased to $347 million in 2004 from $274 million
in 2003. The increases were primarily attributable to natural gas cost
increases, which are passed on to customers.

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 PBR mechanism provides an incentive
mechanism by measuring SDG&E's procurement of natural gas against a
benchmark price comprised of monthly natural gas indices, resulting in
shareholder rewards for costs achieved below the benchmark and
shareholder penalties when costs exceed the benchmark. Further
discussion is provided in Notes 1 and 11 of the notes to Consolidated
Financial Statements.

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. The change was primarily
attributable to natural gas price increases, partially offset by
reduced volumes.

The tables below summarize the components of electric and natural gas
volumes and revenues by customer class for the years ended December 31,
2004, 2003 and 2002.

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

23

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

Although commodity-related revenues from the DWR's purchasing of
SDG&E's net short position or from the DWR's allocated contracts are
not included in revenue (as explained in Note 1 of the notes to
Consolidated Financial Statements), the associated volumes and
distribution revenue are included herein.

Other Operating Expenses. Other operating expenses were $593 million,
$637 million and $560 million in 2004, 2003 and 2002, respectively. The
decrease in 2004 was due primarily to the favorable resolution of
regulatory issues offset partially by higher litigation costs in 2004.
The increase in 2003 compared to 2002 was 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 Income. Other income and deductions consist primarily of
interest income from short-term investments, interest income/expense
from regulatory balancing accounts and allowance for equity funds used
during construction. Excluding the impact of income taxes on non-
operating income, other income was $43 million, $58 million and $22
million in 2004, 2003 and 2002, respectively. The decrease in 2004 was

24

due to higher interest income in 2003 resulting from the favorable $37
million before-tax resolution of income-tax issues with the Internal
Revenue Service (IRS), offset partially by interest earned on income
tax receivables during 2004. The increase in 2003 compared to 2002 was
due to the higher interest income and lower balancing account interest
expense in 2003.

Income Taxes. Income tax expense was $148 million for the years ended
December 31, 2004 and 2003 and was $91 million for the year ended
December 31, 2002. The effective income tax rates were 41.1 percent,
30.3 percent and 30.3 percent for the same years. The lower effective
income tax rates in 2003 and 2002 were due primarily to the favorable
resolution of income tax issues in both years. 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.

Net Income. SDG&E recorded net income of $213 million, $340 million and
$209 million, in 2004, 2003, and 2002, respectively. The decrease in
2004 was primarily due to the favorable resolution of income tax issues
in 2003, which positively affected 2003 earnings by $79 million, income
of $65 million after-tax in 2003 related to the approved settlement of
intermediate-term purchase power contracts (discussed in Note 10 of the
notes to Consolidated Financial Statements); the 2003 Incremental Cost
Incentive Pricing income for the San Onofre Nuclear Generation Station
(SONGS) ($53 million after-tax) and higher performance awards in 2003,
offset by higher electric transmission and distribution margin in 2004
and the resolution of the 2004 cost of service proceeding, which
favorable impacted net income by $21 million.

The increase in 2003 compared to 2002 was primarily due to more
reductions in income tax expense in 2003 than in 2002 from favorable
resolution of income tax issues, the approved settlement of the
intermediate-term purchase power contracts, higher earnings from PBR
awards, and higher electric transmission and distribution revenue.
These factors were partially offset by the litigation costs and other
operating expenses in 2003 and the end of sharing of the merger savings
(which positively impacted earnings by $8 million in 2002).

CAPITAL RESOURCES AND LIQUIDITY

The company's operations are the major source of liquidity. In
addition, working capital requirements can be met through the issuance
of short-term and long-term debt. Cash requirements primarily consist
of capital expenditures for utility plant.

At December 31, 2004, the company had $9 million in unrestricted cash
and $300 million in available unused, committed lines of credit.
Management believes that these amounts and cash flows from operations
and new security issuances will be adequate to finance capital
expenditures and meet liquidity requirements and other commitments.
Forecasted capital expenditures for the next five years are discussed
in "Future Capital Expenditures for Utility Plant."

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

25

investment-quality credit ratings. Rating agencies and others that
evaluate a company's liquidity generally consider a company's capital
expenditures and working capital requirements in comparison to cash from
operations, available credit lines and other sources available to meet
liquidity requirements.

CASH FLOWS FROM OPERATING ACTIVITIES

Net cash provided by operating activities totaled $445 million, $581
million and $757 million for 2004, 2003 and 2002, respectively.

The decrease in net cash provided by operating activities was primarily
due to lower net income in 2004.

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

During 2004, the company made pension plan and other postretirement
benefit plan contributions of $20 million and $8 million, respectively.

CASH FLOWS FROM INVESTING ACTIVITIES

Net cash used in investing activities totaled $299 million, $319
million and $611 million for 2004, 2003 and 2002, respectively. The
decrease in cash used in investing activities in 2004 was due to
greater than normal capital expenditures in 2003 as a result of the
2003 Southern California wildfires. 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, offset by the effects of the
wildfires. Advances to Sempra Energy are payable on demand.

Future Capital Expenditures for Utility Plant

Significant capital expenditures in 2005 are expected to include $550
million 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 $3.2 billion, including $550 million in 2005, $1.0
billion in 2006, $450 million in 2007, $600 million in 2008 and $600
million in 2009. The 2006 amount includes $500 million for Palomar,
which SDG&E will purchase from Sempra Generation after construction is
completed.

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 $285 million, $273
million and $309 million for 2004, 2003 and 2002, respectively.

26

The cash used in financing activities decreased in 2003 from 2002 due
to lower repayments on long-term debt in 2003.

Long-Term and Short-Term Debt

In June 2004, the company issued $251 million of first mortgage bonds
and applied the proceeds in July to refund an identical amount of first
mortgage bonds and related tax-exempt industrial development bonds of a
shorter maturity. The bonds secure the repayment of tax-exempt
industrial development bonds of an identical amount, maturity and
interest rate issued by the City of Chula Vista, the proceeds of which
were loaned to the company and which are repaid with payments on the
first mortgage bonds. The bonds were initially issued as auction-rate
securities, but the company entered into floating-for-fixed interest-
rate swap agreements that effectively changed the bonds' interest rates
to fixed rates in September 2004. The swaps are set to expire in 2009.

Repayments on long-term debt in 2004 included $251 million of SDG&E's
first mortgage bonds and $66 million of rate-reduction bonds.

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 May 2004, the California Utilities obtained a combined $500 million
three-year syndicated revolving credit facility to replace their
expiring 364-day facility of a like amount. No amounts were outstanding
under this facility at December 31, 2004.

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

Dividends

Common dividends paid to Sempra Energy were $205 million in 2004,
compared to $200 million in each of 2003 and 2002.

The payment and amount of future dividends 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, 2004, the
company could have provided a total (combined loans and dividends) of
$160 million to Sempra Energy.

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, 2004 was $2.3 billion. The debt-to-
capitalization ratio was 39 percent at December 31, 2004.

Commitments

The following is a summary of the company's principal contractual
commitments at December 31, 2004. Liabilities reflecting fixed-price

27

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, 6, 9 and 12 of the notes
to Consolidated Financial Statements.

Credit Ratings

Credit ratings of the company remained at investment grade levels in
2004. As of January 31, 2005, credit ratings for SDG&E were as follows:

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

As of January 31, 2005, 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.

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.

28

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, the 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, 2004, the total VaR of the
company's natural gas and power positions was not material.

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

Revenue recognition is discussed in Note 1 and the additional market
risk information regarding derivative instruments is discussed 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, 2004 includes a discussion of how these exposures
are managed.

Commodity Price Risk

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

The company's market risk exposure is limited due to CPUC-authorized
rate recovery of electric procurement and natural gas purchase, sale,
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 Note
11 of the notes to Consolidated Financial Statements. If commodity

29

prices were to rise too rapidly, it is likely that volumes would
decline. This would increase the per-unit fixed costs, which could lead
to further volume declines. The company manages its risk within the
parameters of the company's market risk management framework. As of
December 31, 2004, the company's exposure to market risk was not
material.

Interest Rate Risk

The company is exposed to fluctuations in interest rates primarily as a
result of its long-term debt. The company historically has funded
operations through long-term debt issues with fixed interest rates and
these interest rates are recovered in utility rates. 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.

At December 31, 2004, the company had $1.1 billion of fixed-rate debt
and no 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, 2004, SDG&E's fixed-rate debt had a one-year VaR of $138 million.

At December 31, 2004, the notional amount of interest-rate swap
transactions totaled $251 million. Note 3 of the notes to Consolidated
Financial Statements provides 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 ERMG and the company calculate
current and potential credit risk to counterparties on a daily basis
and monitor actual balances in comparison to approved limits. The
company avoids concentration of counterparties whenever possible, and
management believes its credit policies associated with 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.

30

The company periodically enters into interest-rate swap agreements to
moderate exposure to interest-rate changes and to lower the overall
cost of borrowing. The company would be exposed to interest-rate
fluctuations on the underlying debt should counterparties to the
agreement not perform. Additional information regarding the company's
use of interest-rate swap agreements is provided above under "Interest
Rate Risk."

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

Statement of Financial Accounting Standards (SFAS) 5, "Accounting
for Contingencies," establishes the amounts and timing of when
the company provides for contingent losses. Details of the
company's issues in this area are discussed in Note 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 provides 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 has elected the disclosure option for
all options that are so eligible. The effect of this is discussed
in Note 1 of the notes to Consolidated Financial Statements.

SFAS 123R, "Share-Based Payment" requires public companies to
measure and record the cost of employee services received in
exchange for an award of equity instruments based on the grant-
date fair value of the awards and gives companies three methods
to do so. This statement is effective for Sempra Energy on July
1, 2005. Further discussion is provided in Note 1 of the notes to
Consolidated Financial Statements.

31

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 calculation of fair or realizable values.

The collectibility of receivables, regulatory assets, deferred
tax assets and other assets.

The resolution of various income-tax issues between the company
and the various taxing authorities.

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

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 have significant impacts in the
future.

As discussed elsewhere herein, the company uses exchange quotations or
other third-party pricing to estimate fair values whenever possible.
When no such data is available, it uses internally developed models and
other techniques. The assumed collectibility of receivables considers
the aging of the receivables, the credit-worthiness of customers and
the enforceability of contracts, where applicable. The assumed
collectibility of regulatory assets considers legal and regulatory
decisions involving the specific items or similar items. The assumed
collectibility of other assets considers the nature of the item, the
enforceability of contracts where applicable, the credit-worthiness of
the other parties and other factors. The anticipated resolution of
income-tax issues considers past resolution of the same or similar
issue, the status of any income-tax examination in progress and
positions taken by taxing authorities with other taxpayers with similar
issues. Actuarial assumptions are based on 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.

32

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."

NEW ACCOUNTING STANDARDS

Relevant pronouncements that have recently become effective and have
had a significant effect on the company's financial statements are SFAS
132 (revised 2003), 143 and 150, and FIN 46. They are described in Note
1 of the notes to Consolidated Financial Statements. Pronouncements of
particular importance to the company's financial statements 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.

FIN 46, "Consolidation of Variable Interest Entities, an interpretation
of ARB No. 51": In January 2003, the FASB issued FIN 46 to strengthen
existing accounting guidance that addresses when a company should
consolidate a VIE in its financial statements.

Contracts under which SDG&E acquires power from generation facilities
otherwise unrelated to SDG&E could result in a requirement for SDG&E to
consolidate the entity that owns the facility. As permitted by the
interpretation, SDG&E is continuing the process of determining whether
it has any such situations and, if so, gathering the information that
would be needed to perform the consolidation. The effects of this, if
any, are not expected to significantly affect the financial position of
SDG&E and there would be no effect on results of operations or
liquidity.

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."

33

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

34

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

35

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

36

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

37

SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
Years ended December 31, 2004, 2003 and 2002
(Dollars in millions)

38

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 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. To the extent that recovery is
no longer probable as a result of changes in regulation or the
utility's competitive position, the related regulatory assets would be
written off. In addition, SFAS 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, requires that a loss be recognized
whenever a regulator excludes all or part of utility plant or
regulatory assets from ratebase. Regulatory liabilities represent
reductions in future rates for amounts due to customers. Information
concerning regulatory assets and liabilities is provided below in
"Revenues," "Regulatory Balancing Accounts" and "Regulatory Assets and
Liabilities."

39

Regulatory Balancing Accounts

The amounts included in regulatory balancing accounts at December 31,
2004, represent net payables (payables net of receivables) that are
returned by reducing future rates.

Except for certain costs subject to balancing account treatment,
fluctuations in most operating and maintenance accounts affect utility
earnings. Balancing accounts provide a mechanism for charging utility
customers the amount actually incurred for certain costs, primarily
commodity costs. The CPUC has also approved balancing account treatment
for variances between forecast and actual for SDG&E's commodity costs
and volumes, eliminating the impact on earnings from any throughput and
revenue variances from adopted forecast levels. 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) 2004 2003
- ---------------------------------------------------------------------

Fixed-price contracts and other derivatives $ 500 $ 560
Recapture of temporary rate reduction* 183 259
Deferred taxes recoverable in rates 278 271
Unamortized loss on retirement of debt, net 46 44
Employee benefit costs 160 35
Cost of removal obligation** (913) (846)
Asset retirement obligation** (333) (303)
Other 29 24
---------------------
Total $ (50) $ 44
- ---------------------------------------------------------------------
* 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.

** This is related to SFAS 143, Accounting for Asset Retirement
Obligations, which is discussed below in "New Accounting Standards."

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

(Dollars in millions) 2004 2003
- ---------------------------------------------------------------------
Current regulatory assets $ 132 $ 140
Noncurrent regulatory assets 1,067 1,054
Current regulatory liabilities* (3) (1)
Noncurrent regulatory liabilities (1,246) (1,149)
---------------------
Total $ (50) $ 44
- ---------------------------------------------------------------------
* Included in Other Current Liabilities.

40

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, $2 million and $3
million at December 31, 2004, 2003 and 2002, respectively. The company
recorded a provision for doubtful accounts of $3 million, $1 million
and $4 million in 2004, 2003 and 2002, respectively.

Inventories

At December 31, 2004, inventory shown on the Consolidated Balance Sheets
included natural gas of $50 million, and materials and supplies of $38
million. The corresponding balances at December 31, 2003 were $21 million
and $39 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.

Income Taxes

Income tax expense includes current and deferred income taxes from
operations during the year. In accordance with SFAS 109, Accounting for
Income Taxes, the company records deferred income taxes for temporary
differences between the book and tax bases of assets and liabilities.
Investment tax credits from prior years are being amortized to income
over the estimated service lives of the properties. Other credits are
recognized in income as earned. The company follows certain provisions of
SFAS 109 that permit regulated enterprises to recognize deferred taxes as
regulatory assets or liabilities if it is probable that such amounts will
be recovered from, or returned to, customers.

Property, Plant and Equipment

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

The cost of plant includes labor, materials, contract services and
certain expenditures, including refurbishments, replacement of major
component parts and labor and overheads incurred to install the parts,
incurred during a major maintenance outage of a generating plant.
Maintenance costs are expensed as incurred. In addition, the cost of
plant includes an allowance for funds used during construction (AFUDC).
The cost of most retired depreciable utility plant minus salvage value
is charged to accumulated depreciation.

41

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) 2004 2003 2004 2003 2002
- -----------------------------------------------------------------------
Natural gas operations $ 1.0 $ 1.0 3.42% 3.63% 3.62%
Electric distribution 3.4 3.2 4.11% 4.70% 4.66%
Electric transmission 1.0 0.9 3.06% 3.09% 3.17%
Construction work in
progress 0.3 0.2
Other electric 0.6 0.5 11.33% 9.53% 9.37%
----------------
Total $ 6.3 $ 5.8
- -----------------------------------------------------------------------

Accumulated depreciation and decommissioning of natural gas and electric
utility plant in service were $0.4 billion and $1.4 billion, respectively,
at December 31, 2004, and were $0.3 billion and $1.4 billion, respectively,
at December 31, 2003. The discussion of SFAS 143 under "New Accounting
Standards" describes a change in presentation of accumulated depreciation.
Depreciation expense is based on the straight-line method over the useful
lives of the assets or a shorter period prescribed by the CPUC. Note 10
includes a discussion of the industry restructuring, which affected
recorded depreciation.

AFUDC, which represents the cost of debt and equity funds used to finance
the construction of utility plant, is added to the cost of utility plant.
Although it is not a current source of cash, AFUDC increases income and is
recorded partly as an offset to interest charges and partly as a component
of Other Income and Deductions in the Statements of Consolidated Income.
AFUDC amounted to $12 million, $17 million and $21 million for 2004, 2003
and 2002, respectively.

Nuclear Decommissioning Liability

At December 31, 2004 and 2003, as the result of implementing SFAS 143, the
company had asset retirement obligations of $328 million and $316 million,
respectively, and related regulatory liabilities of $333 million and $303
million, respectively. Additional information on San Onofre Nuclear
Generating Station (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.

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, which consists of all these changes other than
net income as shown on the Statement of Consolidated Income, are shown

42

in the Statements of Consolidated Changes in Shareholders' Equity. At
December 31, 2004, the Accumulated Other Comprehensive Income consisted
of minimum pension liability adjustments, net of income tax.

Revenues

Revenues are primarily derived from deliveries of electricity and
natural gas to customers and changes in related regulatory balancing
accounts. Revenues from electricity and natural gas sales and services
are generally recorded under the accrual method and 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.
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. Note 10 includes a discussion of the electric industry
restructuring. Operating revenue includes amounts for services rendered
but unbilled (approximately one-half month's deliveries) at the end of
each year.

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 started over at January 1, 2004,
essentially eliminating earnings from SONGS except from increases in
ratebase in 2004 and beyond.

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

Transactions with Affiliates

On a daily basis, SDG&E and SoCalGas share numerous functions with each
other and they also receive various services from and provide various
services to Sempra Energy.

SDG&E has a promissory note receivable from Sempra Energy which bears a
variable interest rate based on short-term commercial paper rates
(2.01% at December 31, 2004), and is due on demand. The note balance
(net of intercompany payables) was $96 million at December 31, 2003 and
was paid off during 2004. In addition, at December 31, 2004 and 2003,
SDG&E had $30 million and $55 million, respectively, due from
affiliates. These amounts, including the promissory note described
above, are included in Due from Unconsolidated Affiliates.
Additionally, at December 31, 2004, SDG&E had $15 million due to
affiliates, which is included in current liabilities. At December 31,
2004 and 2003, SDG&E had $267 million related to Palomar project which
is not due to Sempra Generation until 2006 and $21 million due to
Sempra Energy, respectively. These amounts are included in noncurrent
liabilities as Due to Unconsolidated Affiliates.

43

New Accounting Standards

SFAS 123 (revised 2004), "Share-Based Payment" (SFAS 123R): In December
2004, the Financial Accounting Standards Board (FASB) issued SFAS 123R,
a revision of SFAS 123, Accounting for Stock-Based Compensation (SFAS
123), which establishes the accounting for transactions in which an
entity exchanges its equity instruments for goods or services received.
This statement requires companies to measure and record the cost of
employee services received in exchange for an award of equity
instruments based on the grant-date fair value of the award and gives
companies three alternative transition methods. The modified
prospective method requires companies to recognize compensation cost
for unvested awards that are outstanding on the effective date based on
the fair value that the company had originally estimated for purposes
of preparing its SFAS 123 pro forma disclosures. For all new awards
that are granted or modified after the effective date, a company would
use SFAS 123R's measurement model. The second alternative is a
variation of the modified prospective method, allowing companies to
restate earlier interim periods in the year that SFAS 123R is adopted
using applicable SFAS 123 pro forma amounts. Under the third
alternative, the modified retrospective method, companies would apply
the modified prospective method, but also restate their prior financial
statements to include the amounts that were previously reported in
their pro forma disclosures under the original provisions of SFAS 123.
Sempra Energy has not determined the transition method it will use. The
effective date of this statement is July 1, 2005 for Sempra Energy.

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. Note
6 provides additional information on employee benefit plans.

SFAS 143, "Accounting for Asset Retirement Obligations": Beginning in
2003, SFAS 143 requires entities to record liabilities for future costs
expected to be incurred when assets are retired from service, if the
retirement process is legally required. It requires recording of the
estimated retirement cost over the life of the related asset by
depreciating the present value of the obligation (measured at the time
of the asset's acquisition) and by accreting the present value of the
estimated future obligation over the asset's estimated useful life. 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. It also requires the
reclassification of estimated removal costs, which had historically
been recorded in accumulated depreciation, to a regulatory liability.
At December 31, 2004 and 2003, these costs were $913 million and $846
million, respectively. Implementation of SFAS 143 has had no effect on
results of operations and is not expected to have a significant effect
in the future.

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

44

The changes in the asset retirement obligations for the years ended
December 31, 2004 and 2003 are as follows (dollars in millions):

2004 2003
- ------------------------------------------------------------------
Balance as of January 1 $ 326* $ --
Adoption of SFAS 143 319
Accretion expense 23 21
Payments (10) (14)
------ ------
Balance as of December 31 $ 339* $ 326*
- ------------------------------------------------------------------

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

In June 2004, the FASB issued a proposed interpretation, Accounting
for Conditional Asset Retirement Obligations, an interpretation of
FASB Statement No. 143. The interpretation would clarify that a legal
obligation to perform an asset retirement activity that is conditional
on a future event is within the scope of SFAS 143. Accordingly, the
interpretation would require an entity to recognize a liability for a
conditional asset retirement obligation if the liability's fair value
can be reasonably estimated. A final interpretation is expected to be
issued by the FASB in the first quarter of 2005 and would be effective
for the company on December 31, 2005. The company has not determined
the effect the proposed interpretation would have on its financial
statements if the proposed interpretation is adopted.

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. The "normal purchases and normal sales
exception" provides for not marking to market contracts that are very
rarely settled by means other than physical delivery of the commodity
involved in the transaction.) 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 Both 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.

45

SFAS 151, "Inventory Costs-an amendment of ARB No. 43, Chapter 4":
This statement amends the guidance in Accounting Research Bulletin
(ARB) No. 43, Chapter 4, Inventory Pricing, to clarify the accounting
for abnormal amounts of idle facility expense, freight, handling cost,
and wasted material. This statement requires that those items be
recognized as current-period charges regardless of whether they meet
the criteria of "abnormal." The statement is effective for inventory
costs incurred during fiscal years beginning after June 15, 2005. The
company does not expect that this statement will have a material
impact on the company's financial statements.

FIN 46, "Consolidation of Variable Interest Entities, an
interpretation of ARB No. 51": FIN 46, as revised by FIN 46R, requires
an enterprise to consolidate a variable interest entity (VIE), as
defined in FIN 46, if the company is the primary beneficiary of a
VIE's activities. Contracts under which SDG&E acquires power from
generation facilities otherwise unrelated to SDG&E could result in a
requirement for SDG&E to consolidate the entity that owns the
facility. As permitted by the interpretation, SDG&E is continuing the
process of determining whether it has any such situations and, if so,
gathering the information that would be needed to perform the
consolidation. The effects of this, if any, are not expected to
significantly affect the financial position of SDG&E and there would
be no effect on results of operations or liquidity.

FASB Staff Position (FSP) 106-2, "Accounting and Disclosure
Requirements Related to the Medicare Prescription Drug, Improvement
and Modernization Act of 2003": The Medicare Prescription Drug,
Improvement and Modernization Act of 2003 (the "Act") was enacted in
December of 2003. The Act establishes a prescription drug benefit
under Medicare, known as "Medicare Part D," and a tax-exempt federal
subsidy to sponsors of retiree health care benefit plans that provide
a benefit that actuarially is at least equivalent to Medicare Part D.
At December 31, 2003, the company elected a one-time deferral of the
accounting for the Act, as permitted by FSP 106-1, Accounting and
Disclosure Requirements Related to the Medicare Prescription Drug,
Improvement and Modernization Act of 2003.

In May 2004, the FASB issued FSP 106-2, which supersedes FSP 106-1 and
provides guidance on the accounting, disclosure, effective date and
transition requirements related to the Medicare Prescription Drug Act.
During 2004, the company adopted FSP 106-2 retroactive to the
beginning of the year.

The company and its actuarial advisors determined that benefits
provided to certain participants will actuarially be at least
equivalent to Medicare Part D, and, accordingly, the company will be
entitled to an expected tax-exempt subsidy that reduces the company's
accumulated postretirement benefit obligation under the plan at
January 1, 2004 by $3 million and the net postretirement benefit cost
for 2004 by an immaterial amount. Employee benefit plans are discussed
further in Note 6.

46

NOTE 2. SHORT-TERM BORROWINGS

Committed Lines of Credit

SDG&E and its affiliate, SoCalGas, have a combined $500 million three-year
syndicated revolving credit facility 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 agreement
requires SDG&E to maintain, at the end of each quarter, a ratio of total
indebtedness to total capitalization (as defined in the agreement) of no more
than 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. At December 31, 2004, SDG&E had
no amounts outstanding under this facility.

NOTE 3. LONG-TERM DEBT

- -------------------------------------------------------------------
December 31,
(Dollars in millions) 2004 2003
- -------------------------------------------------------------------
First mortgage bonds
6.8% June 1, 2015 $ 14 $ 14
5.9% June 1, 2018 68 68
5.9% September 1, 2018 93 176
5.85% June 1, 2021 60 60
5.25% to 7% December 1, 2027 150 225
After floating to fixed rate swap
expiring 2009:
2.516% to 2.832% January
and February 2024 176 --
2.8275% May 1, 2039 75 --
6.1% September 1, 2019 -- 35
Variable rates -- 58
------------------------
636 636
------------------------
Rate-reduction bonds, 6.31% to 6.37% at
December 31, 2004 payable annually
through 2007 198 263

Other bonds
5.9% June 1, 2014 130 130
5.3% July 1, 2021 39 39
5.5% December 1, 2021 60 60
4.9% March 1, 2023 25 25
------------------------
254 254
------------------------
1,088 1,153

Current portion of long-term debt (66) (66)
------------------------
Total $1,022 $1,087
- -------------------------------------------------------------------

Maturities of long-term debt are $66 million in each of 2005, 2006 and
2007, and $890 million after 2009.

47

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 long-term
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:
$577 million in 2005 and $169 million thereafter.

First Mortgage Bonds

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 $2.4 billion of first mortgage bonds at December 31, 2004.

In June 2004, the company issued $251 million of first mortgage bonds and
applied the proceeds in July to refund an identical amount of first
mortgage bonds and related tax-exempt industrial development bonds of a
shorter maturity. The bonds secure the repayment of tax-exempt industrial
development bonds of an identical amount, maturity and interest rate
issued by the City of Chula Vista, the proceeds of which were loaned to
the company and which are being repaid with payments on the first
mortgage bonds. When SDG&E called the $251 million of refunded first
mortgage bonds in July of 2004, it incurred $6 million in call premium
costs. These costs were recorded as regulatory assets and are being
amortized over the life of the retired debt. The bonds were initially
issued as auction-rate securities, but the company entered into floating-
for-fixed interest-rate swap agreements that effectively changed the
refunding bonds' interest rates to fixed interest rates in September
2004. The swaps expire in 2009.

Unsecured Long-term Debt

Various long-term obligations totaling $254 million are unsecured at
December 31, 2004.

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%. These bonds were
issued to facilitate the 10-percent rate reduction mandated by
California's electric-restructuring law, which is described in Note 10.
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.

48

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 discussed above, in September 2004 SDG&E entered
into interest-rate swaps to exchange the floating rates on its $251
million Chula Vista Series 2004 bonds for fixed rates.

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, 2004, are
as follows:

Southwest
(Dollars in millions) SONGS Powerlink
- --------------------------------------------------------------------
Percentage ownership 20% 91%
Utility plant in service $19 $290
Accumulated depreciation and amortization $-- $149
Construction work in progress $16 $ 1
- --------------------------------------------------------------------

The company and the other owners each holds 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 (NRC), 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 $328 million in 2004 dollars. Cost studies are updated
every three years, with the next update expected to be submitted to the
CPUC for its approval in 2006. 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, at which
time sufficient funds are expected to have been collected to fully
decommission SONGS, but may be extended by CPUC approval until 2022,
when the SONGS' operating license ends and the decommissioning of SONGS
2 and 3 would be expected to begin.

The amounts collected in rates are invested in externally managed trust
funds. Amounts held by the 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 the trusts must be invested passively. The securities held
by the trust are considered available for sale. These trusts are shown
on the Consolidated Balance Sheets at market value. At December 31,

49

2004, these trusts reflected unrealized gains of $182 million with the
offsetting credits recorded on the Consolidated Balance Sheets in Asset
Retirement Obligations 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. Spent nuclear
fuel has been removed from the Unit 1 Spent Fuel Pool and stored on-
site in an Independent Spent Fuel Storage Facility (ISFSI) licensed by
the NRC. The remaining major work will include dismantling, removal and
disposal of all remaining Unit 1 equipment and facilities (both nuclear
and non-nuclear components), and decontamination of the site. These
activities are expected to be completed in 2008. The ISFSI and the
reactor vessel will remain on site until a permanent storage facility
becomes available.

Trust investments include:

December 31,
(Dollars in millions) Maturity dates 2004 2003
- ----------------------------------------------------------------------
Municipal Bonds 2005 - 2034 $ 45 $ 47
US government issues 2005 - 2034 209 181
Short-term cash and other 2005 55 49
Stocks 303 293
- ----------------------------------------------------------------------
Total $ 612 $ 570
- ----------------------------------------------------------------------

Net earnings (loss) were $45 million in 2004, $82 million in 2003 and
$(25) million in 2002. Proceeds from sales of securities (which are
reinvested) were $237 million in 2004, $266 million in 2003 and $409
million in 2002.

Customer contribution amounts are determined by estimates of after-tax
investment returns, decommissioning costs and decommissioning cost
escalation rates. Lower actual investment returns or higher actual
decommissioning costs would result in an increase in future customer
contributions.

Discussion regarding the impact of SFAS 143 is provided in Note 1.
Additional information regarding SONGS is included in Notes 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,
2004 2003 2002
- -----------------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Depreciation 3.9 3.9 2.3
State income taxes, net of
federal income tax benefit 5.2 6.4 6.1
Tax credits (0.8) (0.6) (0.9)
Settlement of Internal Revenue Service audit -- (11.7) (8.6)
Other, net (2.2) (2.7) (3.6)
--------------------------
Effective income tax rate 41.1% 30.3% 30.3%
- -----------------------------------------------------------------------

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The components of income tax expense are as follows:

Years ended December 31,
(Dollars in millions) 2004 2003 2002
- ---------------------------------------------------------------------
Current:
Federal $ 107 $ 133 $ 171
State 41 44 47
-----------------------
Total 148 177 218
-----------------------
Deferred:
Federal 15 (20) (100)
State (12) (6) (24)
------------------------
Total 3 (26) (124)
------------------------
Deferred investment tax credits (3) (3) (3)
------------------------
Total income tax expense $ 148 $ 148 $ 91
- ----------------------------------------------------------------------

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.

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

(Dollars in millions) 2004 2003
- ----------------------------------------------------------------------
Deferred tax liabilities:
Differences in financial and
tax bases of utility plant $ 575 $ 561
Regulatory balancing accounts 74 132
Loss on reacquired debt 20 19
Other 16 10
--------------------
Total deferred tax liabilities 685 722
--------------------
Deferred tax assets:
Investment tax credits 27 29
Deferred compensation 29 76
State income taxes 19 24
Federal benefit of state taxes 24 29
Workers compensation and
public liability 6 7
Environmental liabilities 11 5
Other accruals not yet deductible 30 38
Other 2 3
--------------------
Total deferred tax assets 148 211
--------------------
Net deferred income tax liability $ 537 $ 511
- ----------------------------------------------------------------------

51

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

(Dollars in millions) 2004 2003
- ----------------------------------------------------------------------
Current liability $ 15 $ 26
Noncurrent liability 522 485
--------------------
Total $ 537 $ 511
- ----------------------------------------------------------------------

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 either final
average or career salary.

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

There were no amendments to the company's pension and other
postretirement benefit plans in 2003 or 2004. During 2002, the company
had amendments to other postretirement benefit plans related to the
transfer of employees from 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.

December 31 is the measurement date for the pension and other
postretirement benefit plans. The following table provides 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:

52

The net asset (liability) is recorded on the Consolidated Balance
Sheets at December 31 as follows:

At December 31, 2004 and 2003, the company had an unfunded pension plan
and a funded pension plan. The funded plan had benefit obligations in
excess of its plan assets. The following table provides information for
the funded plan at December 31:

(Dollars in millions) 2004 2003
- -------------------------------------------------------------
Projected benefit obligation $ 694 $ 662
Accumulated benefit obligation $ 692 $ 661
Fair value of plan assets $ 569 $ 538

53

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

As described in Note 1, the company adopted FSP 106-2 in 2004
retroactive to the beginning of the year. The company and its actuarial
advisors determined that benefits provided to certain participants will
actuarially be at least equivalent to Medicare Part D, and,
accordingly, the company will be entitled to an expected tax-exempt
subsidy that reduces the company's accumulated postretirement benefit
obligation under the plan at January 1, 2004 by $3 million ($2 million
of which applies to payments during the next 10 years) and the net
postretirement benefit cost for 2004 by an immaterial amount.

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.

54

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

Pension Plan Investment Strategy

The asset allocation for Sempra Energy's pension trust (which includes
SDG&E's pension plan) at December 31, 2004 and 2003 and the target
allocation for 2005 by asset categories are as follows:

The company's investment strategy is to stay fully invested at all
times and maintain its strategic asset allocation, keeping the
investment structure relatively simple. The equity portfolio is
balanced to maintain risk characteristics similar to the S&P 1500 with
respect to market capitalization, and 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

55

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, 2004 and 2003 and the target allocation for 2005 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 (shown 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.

Future Payments

The company expects to contribute $22 million to the pension plan and
$9 million to its other postretirement benefit plans in 2005.

The following table reflects the total benefits expected to be paid for
the next 10 years to current employees and retirees from the plans or
from the company's assets, including both the company's share of the
benefit cost and, where applicable, the participants' share of the
costs, which is funded by participant contributions to the plans.

Savings Plan

The company offers a 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

56

completed service, the company begins to make matching contributions.
Employer contributions are equal to 50 percent of the first 6 percent
of eligible base salary contributed by employees and, if certain
company goals are met, an additional amount related to incentive
compensation payments.

Employer contributions are invested in Sempra Energy common stock and
had been required to remain so invested until termination of employment
or until the employee's attainment of age 55, when they could be
transitioned into other investments. Effective January 1, 2005, all
employees have the ability to transfer employer contributions into
other investments. The employees' contributions are invested in Sempra
Energy stock, mutual funds, or institutional trusts (the same
investments in which employees may now direct the employer
contributions). Company contributions to the savings plan were $10
million in 2004, $8 million in 2003 and $7 million in 2002.

NOTE 7. STOCK-BASED COMPENSATION

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

In 1995, SFAS 123, Accounting for Stock-Based Compensation, was issued.
It encourages a fair-value-based method of accounting for stock-based
compensation. As permitted by SFAS 123, Sempra Energy and its
subsidiaries adopted only its disclosure requirements and continue to
account for stock-based compensation in accordance with the provisions
of Accounting Principles Board Opinion 25. Discussion of SFAS 123R (a
revision of SFAS 123) is provided in Note 1. The subsidiaries record an
expense for the plans to the extent that subsidiary employees
participate in the plans or that subsidiaries are allocated a portion
of Sempra Energy's costs of the plans. SDG&E recorded expenses of $9
million, $7 million and $1 million in 2004, 2003 and 2002,
respectively.

57

NOTE 8. FINANCIAL INSTRUMENTS

Fair Value

The fair values of certain of the company's financial instruments
(cash, temporary investments, notes receivable 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 are based on
their quoted market prices or quoted market prices for similar
securities.

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
attributable to the risk being hedged; therefore, there is no effect on
net income. 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
similarly reflected. The ineffective portion is reported in earnings
immediately. The effect on other comprehensive income for the years
ended December 31, 2004 and 2003 was not material. In instances where
derivatives do not qualify for hedge accounting, gains and losses are
recorded in earnings immediately.

58

The company utilizes natural gas and energy derivatives to manage
commodity price risk associated with servicing its 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, i.e.,
those that rarely settle by means other than physical delivery of the
commodities involved in the transaction, are eligible for the normal
purchases and sales exception of SFAS 133, whereby they are accounted
for under accrual accounting and recorded in Revenues or Cost of Sales
on the Statements of Consolidated Income at the time of delivery. 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 by 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.

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

59

Regulatory assets and liabilities related to derivatives held by SDG&E at
December 31 were:

The above had no impact on net income during 2004 and 2003.

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 its 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.

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NOTE 9. PREFERRED STOCK

All series of SDG&E's preferred stock have cumulative preferences as to
dividends. The $20 par value preferred stock has two votes per share on
matters being voted upon by shareholders of SDG&E and a liquidation
value at par, whereas the no-par-value preferred stock is nonvoting and
has a liquidation value of $25 per share plus any unpaid dividends.
SDG&E is authorized to issue 10,000,000 shares of no-par-value
preferred stock (both subject to and not subject to mandatory
redemption). All series are callable at December 31, 2004. The $1.7625
Series has a sinking fund requirement to redeem 50,000 shares at $25
per share per year from 2005 to 2007; all remaining shares must be
redeemed in 2008. On January 15, 2005, SDG&E redeemed 100,000 shares.

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

61

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, which is included in Regulatory Balancing Accounts,
Net on the Consolidated Balance Sheets) and began recovering these
amounts in rates charged to customers following the end of the rate-
ceiling period. The remaining AB 265 undercollection was fully
collected in 2004.

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. In 2001, the DWR entered into long-
term contracts with suppliers to provide power for the utility
procurement customers of each of the California investor-owned
utilities (IOUs). The CPUC has established the allocation of the power
and its administrative responsibility, including collection of power
contract costs from utility customers, among the IOUs. Beginning on
January 1, 2003, the IOUs resumed responsibility for electric commodity
procurement above their allocated share of the DWR's long-term
contracts.

Department of Water Resources

The DWR's operating agreement with SDG&E, approved by the CPUC,
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
responsibility associated with these activities continues to reside
with the DWR. Therefore, the revenues and costs associated with the
contracts are not included in the Statements of Consolidated Income.

In October 2003, the CPUC initiated a proceeding to consider a
permanent methodology for allocating the DWR's revenue requirement
beginning in 2004 through the remaining life of the DWR contracts. On
December 2, 2004, the CPUC issued a decision that would shift $790
million of the costs to SDG&E's customers over the period between
implementation of the decision and 2013. On December 20, 2004, SDG&E
filed an application for rehearing of the decision, arguing that the
CPUC reached its decision without the proper evidentiary review of the
method of calculating above-market costs. On January 13, 2005, the CPUC
acted to grant rehearing on that limited issue.

Such a shift would not affect SDG&E's net income, but would adversely
affect its customers' commodity costs. In the near term, the effect on
SDG&E's cash flows would be minor, but could become significant in the
later years unless rate ceilings imposed by AB 1X, which freeze total
rates for most residential customers at the February 2001 level, are
increased to provide more-contemporaneous recovery. Until January 1,
2016, CPUC Decision 04-12-048 provides SDG&E with a true-up triggering
mechanism when an overcollection or undercollection in SDG&E's power
procurement balancing account exceeds approximately five percent of the
prior year's recorded electric commodity revenue.

Power Procurement and Resource Planning

In 2001, the CPUC directed the IOUs to resume electric commodity
procurement to cover their net short energy requirements by January 1,
2003 and also implemented legislation regarding procurement and
renewables portfolio standards. In addition, the CPUC established a
process for review and approval of the utilities' long-term resource

62

and procurement plans, which is intended to identify forecasted needs
for generation and transmission resources within a utility's service
territory to support transmission grid reliability and to serve
customers. An updated 10-year resource plan was approved by the CPUC in
December 2004, in a proceeding to consider utility resource planning,
including energy efficiency, contracted power, demand response,
qualifying facilities, renewable generation and distributed generation.
SDG&E's updated long-term resource plan incorporates the resources
approved by the CPUC that are discussed below, and recognizes updated
CPUC goals to reach a 20-percent renewable resources target by 2010.
The updated plan recommends a 500-kilovolt (kV) transmission line
addition in 2010, which would be processed for approval in a subsequent
CPUC proceeding. The CPUC also endorsed SDG&E's continued analysis and
planning for a 500-kV transmission line, adopted SDG&E's proposal for
cost recovery related to utility-owned generation, recognized the debt-
equivalent impact associated with long-term power purchase contracts,
adopted a greenhouse gas adder for assessing new resource acquisitions,
and established a cap on initial costs for new utility-owned generation
resources to level the playing field with respect to power purchase
options. The estimated cost related to this updated plan is $700
million, to be spent by 2008, for capital projects approved by the CPUC
in June 2004, as described below.

On June 9, 2004, the CPUC approved SDG&E's entering into five new
electric resource contracts (including two under which SDG&E would take
ownership, on a turnkey basis, of new generating assets, including the
550-MW combined-cycle Palomar plant being developed by Sempra
Generation, an affiliate, for completion in 2006). An additional,
demand-response contract was also approved. The decision authorized
SDG&E to recover the costs of both contracted resources and turnkey
resources, but did not adopt SDG&E's specific cost recovery, ratemaking
and revenue requirement proposals for the proposed turnkey resources.
On July 15, 2004, three parties filed requests for rehearing of the
decision. SDG&E filed its response on July 30, 2004, opposing the
requests. The CPUC is expected to rule on the requests by mid-2005. In
September 2004, SDG&E filed its revenue requirement and ratemaking
proposals for the 45-MW combustion turbine which SDG&E will acquire as
a turnkey project and filed its revenue requirement and ratemaking
proposals for the Palomar plant on November 1, 2004. On January 27,
2005, the CPUC approved the revenue requirement and ratemaking
proposals for the 45-MW combustion turbine. The June 9, 2004, decision
did not approve SDG&E's proposals for a return on equity (ROE) for
SDG&E's new generation investments higher than SDG&E's ROE on
distribution assets, an equity offset for the debt equivalent of
purchase power contracts or an equity buildup for construction. These
matters may be re-introduced for consideration in future CPUC
proceedings.

SONGS

Southern California Edison's (Edison) CPUC decision on its 2003 General
Rate Case application sets rates for SONGS, 20 percent of which is
owned by SDG&E. 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. For the year ended December 31, 2003, ICIP contributed $53
million to SDG&E's net income. SDG&E's SONGS ratebase restarted at $0
on January 1, 2004 and, therefore, SDG&E's earnings from SONGS are now
generally limited to a return on new capital additions.

63

Edison has applied for CPUC approval to replace SONGS' steam
generators, which would require an estimated capital expenditure of
$782 million. Hearings before the CPUC on Edison's application were
completed on February 11, 2005 and a final decision addressing the cost
effectiveness of the steam generator project is expected during the
second half of 2005. SDG&E had elected not to participate in the
project. SDG&E nonparticipation would result in a reduction in its
share ownership in the project and a proportionate reduction in its
share of SONGS' output. On February 18, 2005, an arbitrator issued a
decision that, based upon Edison's cost calculations, would result in
SDG&E's interest in SONGS being reduced to zero if SDG&E continues to
decline to participate in the project. The arbitration decision is
subject to CPUC review and approval, with a CPUC decision expected in
the second half of 2006. The CPUC could require SDG&E to participate in
the project or, if the reductions of SDG&E's ownership percentage
resulting from the CPUC final decision were to be unacceptable, SDG&E
may elect to participate.

During the most recent SONGS Unit 3 refueling outage which ended on
December 28, 2004, Edison reported that it had performed inspections of
two pressurizer sleeves and found evidence of degradation. Degradation
of the pressurizer sleeves has been a concern in the nuclear industry
for some time. Edison had been planning to replace all of the sleeves
in Units 2 and 3 during the next refueling for each unit in 2005 and
2006, but decided to move the planned replacement of Unit 3's
pressurizer sleeves forward from 2006 to 2004. This extra work
lengthened the 2004 outage, but allowed Edison to move the 2006
refueling outage out of the peak summer period to the fall or winter of
2006. Edison reported that it will incur about $9 million of capital
expenditures during 2005 that otherwise would have occurred in 2006.
SDG&E's share would be approximately $2 million. Edison plans to
replace the pressurizer sleeves in Unit 2 during its next scheduled
outage in 2005.

Also during the 2004 outage, Edison reported that it had conducted a
planned inspection of the Unit 3 reactor vessel head and found
indications of degradation. Although the degradation is far below the
level at which leakage would occur, Edison made the repairs during the
2004 outage. While Edison reports that this is the first experience at
SONGS of this kind of degradation to the reactor vessel heads, the
detection and repair of similar degradation at other plants are now
common in the industry. Edison reports that it plans to replace the
Unit 2 and Unit 3 reactor vessel heads during refueling outages in
2009-2010.

Spent Nuclear Fuel

SONGS owners have responsibility for the interim storage of spent
nuclear fuel generated at SONGS until it is accepted by the Department
of Energy (DOE) for final disposal. Spent nuclear fuel has been stored
in the SONGS Units 1, 2 and 3 spent fuel pools and the ISFSI. Movement
of all spent fuel to the ISFSI was completed as of December 31, 2004,
except for the movement of Unit 1 spent fuel stored at the Unit 2 spent
fuel pool, which is expected to be completed by the end of 2005. With
these moves, there will be sufficient space for the Units 2 and 3 spent
fuel pools to meet requirements through mid-2007 and mid-2008,
respectively.

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NOTE 11. OTHER REGULATORY MATTERS

Natural Gas Industry Restructuring (GIR)

In December 2001, the CPUC issued a decision related to GIR, with
implementation anticipated during 2002. On April 1, 2004, after many
delays and changes, the CPUC issued a decision that adopts tariffs to
implement the 2001 decision. However, by that same decision, the CPUC
stayed implementation of the GIR tariffs until it issues a decision in
Phase I of the Natural Gas Market Order Instituting Ratemaking (OIR)
discussed below. At that time, the CPUC will reconcile the GIR market
structure with whatever structure results from the Phase I decision of
the Natural Gas Market OIR.

Natural Gas Market OIR

The CPUC's Natural Gas Market OIR was instituted in January 2004 and
will be addressed in two phases. A decision on Phase I was issued in
September 2004 and Phase II is awaiting CPUC direction on further
proceedings. In Phase I, the CPUC's objective was 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 liquefied natural gas (LNG)
project to which interconnection is planned, providing costs and terms,
including access to the pipelines in Mexico being developed by
affiliated company, Sempra Pipelines & Storage. Phase II will primarily
address emergency reserves and ratemaking policies. 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 the period from 2006 to 2016. Since GIR,
discussed above, would end in August 2006 and there is overlap between
GIR and the OIR issues, a number of parties (including SoCalGas) have
requested the CPUC not to implement GIR.

The California Utilities have made comprehensive filings in the OIR
outlining a proposed market structure that is intended to create access
to new natural gas supply sources (such as LNG, which is the business
of affiliated company, Sempra LNG) for California. In their Phase I and
Phase II filings, SoCalGas and SDG&E proposed a framework to provide
firm tradable access rights for intrastate natural gas transportation;
provide SoCalGas with continued balancing account protection for
intrastate transmission and distribution revenues, thereby eliminating
throughput risk; and integrate the transmission systems of SoCalGas and
SDG&E so as to have common rates and rules. The California Utilities
also proposed that the capital expenditures necessary to access new
sources of supply be included in ratebase and that the total amount of
the expenditures would be $200 million to $300 million.

The California Utilities also proposed a methodology and framework to
be used by the CPUC for granting pre-approval of new interstate
transportation agreements. The Phase I decision approved the California
Utilities' transportation capacity pre-approval procedures with some
modifications. In January 2005, SDG&E was granted pre-approval of a
capacity contract with El Paso Natural Gas Company (El Paso) that would
expire in 2007. All interstate transportation capacity under the pre-
approved contracts will be used to transport natural gas supplies on
behalf of the California Utilities' core residential and small
commercial customers, and all costs of the capacity will be recovered

65

in the customers' rates through each utility's Purchased Gas Account, a
balancing account. In December 2004, pursuant to the Phase I decision,
SoCalGas filed an application to implement proposals for transmission
system integration, firm access rights, and off-system delivery
services. The CPUC has determined that the ratemaking treatment and
cost responsibility for any access-related infrastructure will be
addressed in future applications to be filed when more is known about
the particular projects. Phase II of the Gas Market OIR will review the
CPUC's ratemaking policies on throughput risk to better align these
with its objectives of promoting energy conservation and adequate
infrastructure. Phase II will also investigate the need for emergency
natural gas storage reserves and the role of the utility in
backstopping the noncore market.

Cost of Service

On December 2, 2004, the CPUC issued a decision in the California
Utilities' cost of service proceedings that essentially approved a
settlement recommended by most major parties to the proceedings. The
decision reduces the California Utilities' annual rate revenues,
effective retroactively to January 1, 2004, by an aggregate net amount
of approximately $23 million from the rates in effect during 2003. The
reduced rates will remain in effect through 2007, subject to annual
attrition allowances. Of the reduction, $10 million relates to what
SDG&E believes to be a computational error concerning its nuclear
electric rate revenues. With respect to the $10 million reduction, a
Petition for Modification and an Application for Rehearing were filed
in December 2004 and January 2005, respectively.

Attrition allowances, performance-based incentive mechanisms (PBR),
which are described in the following section, and related matters are
being addressed by the CPUC in Phase II of the cost of service
proceedings, expected to be decided in the first quarter of 2005. In
addition to recommending changes in the PBR formulas, the CPUC's Office
of Ratepayer Advocates (ORA) also proposed the possibility of
performance penalties for service quality, safety and electric service
reliability, without the possibility of performance awards. Hearings
took place in June 2004. In July 2004, all of the active parties in
Phase II who dealt with post-test-year ratemaking and performance
incentives filed for adoption by the CPUC of an all-party settlement
agreement for most of the Phase II issues, including annual inflation
adjustments and earnings sharing. The proposed settlement does not
cover performance incentives. For the interim years of 2005-2007, the
Consumer Price Index would be used to adjust the escalatable authorized
base rate revenues within identified floors and ceilings, each of which
limits the adjustment to approximately three to five percent of the
prior year's authorized base rate revenues.

SDG&E had filed for continuation of existing 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 did not determine the extent of
rewards or penalties. As part of the proposed Phase II Settlement
Agreement, earnings sharing, under which IOUs return to customers a
percentage of earnings above specified levels, would be suspended for
2004 and resume for 2005 through 2007. The proposed earnings sharing
mechanism also provides the utility the option to file for suspension
of the earnings sharing mechanism if earnings fall 175 basis points or
more below its authorized rate of return; however, if earnings are more
than 300 basis points above the utility's authorized rate of return,

66

the earnings sharing mechanism would be automatically suspended and
trigger a formal regulatory review by the CPUC to determine whether
modification of the ratemaking mechanism is required.

On February 15, 2005, the Administrative Law Judge (ALJ) and the CPUC
Commissioner assigned to Phase II of the cost of service proceedings
issued differing proposed decisions for consideration by the CPUC. If
adopted by the CPUC, the ALJ's decision would not approve the parties'
settlement of the Phase II issues, but would authorize the California
Utilities to adjust their authorized revenues in each of years 2005
through 2007 on a formula basis similar to that proposed by the
California Utilities and also establish performance measures with
reward and penalty potentials of approximately $20 million. In
addition, the ALJ's decision would have the utilities' cost of capital
reviewed on an annual basis. If adopted by the CPUC, the Commissioner's
proposed decision would approve the parties' settlement and also
approve performance measures for customer service, safety and
reliability with the same reward and penalty provisions as the ALJ's
proposed decision. The Commissioner's proposed decision also would
continue the use of the cost of capital adjustment mechanism currently
in place, which adjusts each utility's rate of return automatically
based on market indices. The CPUC may adopt either proposed decision,
as proposed or with modifications, or reject both and adopt a different
result.

The California Utilities had been equally sharing between ratepayers
and shareholders the estimated savings for the 1998 business
combination that created Sempra Energy. Pursuant to an October 2001
CPUC decision, that sharing has ceased and all merger savings go to
ratepayers beginning with 2003.

Performance-Based Regulation

PBR consists of three primary components. The first is a mechanism to
adjust rates in years between general rate cases or cost of service
cases. It annually adjusts base rates from those of the prior year to
provide for inflation, 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
specified benchmark, the utility is rewarded or penalized certain
dollar amounts.

The three areas that have been 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 have resumed
this activity. However, as noted under "Cost of Service," Phase II of
the California Utilities' current cost of service proceeding is not
complete. As a result, these safety, reliability and customer
satisfaction incentive mechanisms (i.e., those that are reviewed in the
Cost of Service proceeding) were not in effect during 2004. However, it

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is not expected that the effect would be other than a one-year
moratorium of the mechanisms.

PBR and DSM rewards are not included in the company's earnings before
CPUC approval is received. The only incentive reward approved during
2004 consisted of $1.5 million related to SDG&E's Year 10 natural gas
PBR, which was approved in August 2004. This reward was awarded by the
CPUC subject to refund based on the outcome of the Border Price
Investigation discussed below. The cumulative amount of rewards subject
to refund based on the outcome of the Border Price Investigation is
$8.4 million, all of which has been included in net income in 2004 or
previously.

On December 30, 2004, a joint settlement agreement between the
California Utilities and the ORA (collectively, the joint parties) was
filed with the CPUC for approval. The settlement agreement resolves all
outstanding shareholder earnings claims filed with the CPUC commencing
in 2000 and those claims that would have been filed through 2007
associated with DSM, energy efficiency and low-income energy efficiency
programs. The proposed settlement is for $73 million (including
interest, franchise fees, uncollectible amounts and awards earned in
prior years that had not yet then been requested). The joint parties
requested expeditious approval of the settlement agreement, without
modification. A CPUC decision is expected by the end of the second
quarter of 2005.

At December 31, 2004, other performance incentives were pending CPUC
approval and, therefore, were not included in the company's earnings
(dollars in millions):

Program
-----------------------------------
2003 Distribution PBR $ 8.2
Natural gas PBR Year 11 .2
-----------------------------------
Total $ 8.4
-----------------------------------

Cost of Capital

Effective January 1, 2005, SDG&E's authorized return on ratebase (ROR)
and ROE became 8.18 percent and 10.37 percent, respectively, for its
electric distribution and natural gas businesses, down from 8.77
percent and 10.9 percent, respectively. The decrease is a result of the
CPUC's automatic triggering mechanism, which resets these rates
whenever Moody's Aa utility bond yield as published by Mergent Bond
Record changes by more than a specified amount. The current benchmark
is 6.19 percent and an automatic adjustment would be triggered if the
Mergent Aa utility bond yield were to average less than 5.19 percent or
greater than 7.19 percent during the April - September timeframe of any
year. The effect of the 2004 changes in ROR and ROE will be to decrease
net income in 2005 by $10 million from what it would have been if the
2005 rates had not changed from the 2004 rates. In December 2004, the
CPUC ordered SDG&E to file a cost of capital application in 2005 to
take effect January 1, 2006. SDG&E had recommended that the CPUC
approve a policy allowing utilities to increase the equity in their
authorized capital structure to adjust for the debt equivalent effect
of purchased power agreements. The CPUC has directed that such
adjustment only be considered in the context of a full review of the

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cost of capital. The electric-transmission cost of capital is
determined under a FERC proceeding and is currently at an 11.25% ROE.

Potential changes to this process are described above in "Cost of
Service."

Biennial Cost Allocation Proceeding

The Biennial Cost Allocation Proceeding (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 sales volumes 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. In November
2003, an Assigned Commissioner Ruling stayed the BCAP application until
a decision is issued in the GIR implementation proceeding. As a result
of the April 1, 2004 decision on GIR implementation as described in
Natural Gas Industry Restructuring above, in May 2004 the ALJ in the
2005 BCAP issued a decision dismissing the BCAP application. The
company is required to file a new BCAP application after the stay in
the GIR implementation proceeding is lifted.

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. The CPUC broadly
determined that it could, in appropriate circumstances, 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 provide for their utility
subsidiaries' capital requirements, as the IOUs previously acknowledged
in connection with their holding companies' formations. In January
2002, the CPUC ruled that it had jurisdiction to create the holding
company system and, therefore, retains jurisdiction to enforce
conditions to which the holding companies had agreed.

In a May 2004 opinion, the California Court of Appeal upheld the CPUC's
assertion of limited enforcement jurisdiction, but concluded that the
CPUC's interpretation of the "first priority" condition (that the
holding companies could be required to infuse cash into the utilities
as necessary to meet the utilities' obligation to serve) was not ripe
for review. In September 2004, the California Supreme Court declined to
review the California Court of Appeal's decision.

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, covering years 1997
through 2003, is expected to be completed by the third quarter of 2005.
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

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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.

Recovery of Certain Disallowed Transmission Costs

In August 2002, the FERC issued Opinion No. 458, which effectively
disallowed SDG&E's recovery in its transmission rates of the
differentials between certain payments to SDG&E by its co-owners of the
Southwest Powerlink (SWPL) under the SWPL Participation Agreements, and
charges assessed to SDG&E under the California Independent System
Operator (ISO) FERC tariff related to energy schedules of its SWPL co-
owners. As a result, SDG&E is incurring unreimbursed costs of $4
million to $8 million per year. SDG&E has appealed the FERC decision to
the Federal Court of Appeals, which has set oral argument for May 9,
2005.

SDG&E has challenged the propriety of the disallowed ISO charges in
several proceedings. In July 2001, SDG&E filed an arbitration claim
against the ISO, claiming the ISO should not charge SDG&E for the
transmission losses attributable to its SWPL co-owners' energy
schedules. In October 2003, the arbitrator awarded SDG&E all amounts
claimed, which totaled $22 million, including interest, as of the time
of the award. The ISO appealed this result to the FERC and decision on
this appeal is pending.

SDG&E has also challenged at the FERC the ISO's grid management charges
assessed on the subject SWPL schedules. In January 2004, the FERC
denied rehearing of its Opinion No. 463, which upheld such charges on
the subject SWPL schedules for 2001 through 2003, but ordered certain
refunds to SDG&E. The refunds are pending before the FERC, as is a
separate proceeding involving application of the charges to the subject
schedules from 2004 forward. In addition, in March 2004, SDG&E
petitioned the U.S. Court of Appeals for review of these FERC orders.
The court has held SDG&E's appeal in abeyance pending the FERC's
disposition of other parties' rehearing requests.

SDG&E has also commenced a private arbitration to reform the SWPL
Participation Agreements to remove prospectively SDG&E's obligation to
provide to its SWPL co-owners the services that result in unreimbursed
ISO tariff charges. The parties have agreed to hold the arbitration in
abeyance pending resolution of the related FERC proceedings.

Southern California Wildfires

On June 28, 2004, SDG&E filed its catastrophic event memorandum
accounts (CEMA) application with the CPUC to recover incremental
operating and maintenance and capital costs of its natural gas and
electric distribution systems associated with the 2003 California
wildfires. In that application, SDG&E is requesting a 2005 revenue
requirement of $20 million, representing the operating and maintenance
costs of $12 million plus the 2004 and 2005 ongoing annual amounts of
$4 million to recover the $26 million of capital costs and the
authorized return thereon. The company expects no significant effect on
earnings from the fires. The assigned ALJ indicated that he expects to
issue a proposed decision during the first quarter of 2005.

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Gain on Sale Rulemaking

A gain on sale rulemaking was issued in September 2004 in order to
standardize the treatment of gains on sales of property by utilities.
This rulemaking may result in the adoption of a general ratemaking
policy for allocation between utility shareholders and ratepayers of
any gain or loss on sale of utility property. The CPUC will consider
adopting a standard percentage allocation, probably between 5 percent
and 50 percent to shareholders, rather than resolving such allocations
on a case-by-case basis, as is now its practice. In unusual
circumstances the CPUC would be able to depart from the standard
allocation to be adopted. The CPUC intends to apply this standard
percentage to sales of both depreciable property and non-depreciable
property. The rulemaking states that the new policy would replace the
CPUC'S current policy of allocating all gain or loss to shareholders on
sale to a municipality of a utility operating system. The final outcome
of the rulemaking may be different than that proposed for comment in
the order instituting the rulemaking. No schedule has been announced
yet for this proceeding.

NOTE 12. COMMITMENTS AND CONTINGENCIES

Natural Gas Contracts

SDG&E buys natural gas under long-term contracts. 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 2005 and
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. In accordance with regulatory directives,
SDG&E will reconfigure its pipeline capacity portfolio by November 2005
to secure firm transportation rights from a diverse mix of U.S. and
Canadian supply sources for its projected core customer natural gas
requirements.

All of SDG&E's natural gas is delivered through SoCalGas' pipelines
under a short-term transportation agreement. In addition, under a
separate agreement expiring in March 2006, SoCalGas provides SDG&E
eight billion cubic feet of storage capacity.

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At December 31, 2004, the future minimum payments under existing
natural gas storage and transportation contracts were:

Total payments under natural gas contracts were $347 million in 2004,
$274 million in 2003 and $205 million in 2002.

Purchased-Power Contracts

For 2005, 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 2032. In addition, during 2002 SDG&E entered
into contracts which will provide five percent of its 2005 total energy
sales from renewable sources. These contracts expire on various dates
through 2025.

At December 31, 2004, the estimated future minimum payments under the
long-term contracts (not including the DWR allocations) were:

(Dollars in millions)
- --------------------------------------------------------------------
2005 $ 218
2006 241
2007 274
2008 319
2009 316
Thereafter 4,017
-------
Total minimum payments $ 5,385
- --------------------------------------------------------------------

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 $329
million in 2004, $396 million in 2003 and $235 million in 2002.

Leases

SDG&E has operating leases on real and personal property expiring at
various dates from 2005 to 2045. Certain leases on office facilities
contain escalation clauses requiring annual increases in rent ranging
from 2 percent to 5 percent. The rentals payable under these leases are

72

determined on both fixed and percentage bases, and most leases contain
extension options which are exercisable by SDG&E.

At December 31, 2004, the minimum rental commitments payable in future
years under all noncancellable leases were as follows:

(Dollars in millions)
- ------------------------------------------------------------
2005 $ 19
2006 18
2007 16
2008 10
2009 10
Thereafter 14
--------
Total future rental commitments $ 87
- ------------------------------------------------------------

Rent expense for operating leases totaled $20 million in each of 2004
and 2003 and $18 million in 2002.

Construction Projects

In addition to the usual expenditures for plant improvements, the
company will purchase in 2006 the 550-MW Palomar power plant, which is
currently being constructed by Sempra Generation, for $500 million. The
company has also contracted to purchase a 45-MW generating facility
being constructed by an unrelated party.

Guarantees

As of December 31, 2004, the company did not have any outstanding
guarantees.

Environmental Issues

The company's operations are subject to federal, state and local
environmental laws and regulations governing hazardous wastes, air and
water quality, land use, solid waste disposal and the protection of
wildlife. As applicable, appropriate and relevant, these laws and
regulations require that the company investigate and remediate the
effects of the release or disposal of materials at sites associated
with past and present operations, including sites at which the company
has been identified as a Potentially Responsible Party (PRP) under the
federal Superfund laws and comparable state laws. The company is
required to obtain numerous governmental permits, licenses and other
approvals to construct facilities and operate its businesses.
Additionally, to comply with these legal requirements, it must spend
significant sums on environmental monitoring, pollution control
equipment and emissions fees. In addition, existing environmental
regulations could be revised or reinterpreted and other new laws and
regulations could be adopted or become applicable to the company and
its facilities. 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

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environmental laws and regulations were $9 million in 2004, $5 million
in 2003 and $4 million in 2002. The cost of compliance with these
regulations over the next five years is not expected to be significant.

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

The environmental issues currently facing the company or resolved
during the last three years include investigation and remediation of
its manufactured-gas sites (two completed as of December 31, 2004 and
site-closure letters received), 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. Costs of future expenditures for
environmental remediation obligations are not discounted to their
present value. Not including the liability for SONGS marine mitigation,
which SDG&E is participating in jointly with Edison, at December 31,
2004, the company's accrued liability for environmental matters was
$11.4 million, of which $1.8 million is related to manufactured-gas
sites, $8.7 million to cleanup at SDG&E's former fossil-fueled power
plants and $0.9 million to waste-disposal sites used by the company
(which has been identified as a PRP). These accruals are expected to be
paid ratably over the next three years.

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 $10.5 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 were to occur by any other SONGS 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

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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
$8.8 million.

Both the nuclear liability and property insurance programs subscribed
to by members of the nuclear power generating industry include industry
aggregate limits for non-certified acts (as defined by the Terrorism
Risk Insurance Act) of terrorism-related SONGS losses, including
replacement power costs. An industry aggregate limit of $300 million
exists for liability claims, regardless of the number of non-certified
acts affecting SONGS or any other nuclear energy liability policy or
the number of policies in place. An industry aggregate limit of $3.24
billion exists for property claims, including replacement power costs,
for non-certified acts of terrorism affecting SONGS or any other
nuclear energy facility property policy within twelve months from the
date of the first act. These limits are the maximum amount to be paid
to members who sustain losses or damages from these non-certified
terrorist acts.

For certified acts of terrorism, the individual policy limits stated
above apply.

Legal Proceedings

Except for the matters referred to below, neither the company nor its
subsidiary are party to, nor is their property the subject of, any
material pending legal proceedings other than routine litigation
incidental to their businesses. At December 31, 2004, the company had
accrued approximately $38 million to provide for the costs of legal
proceedings related to the 2000-2001 California energy crisis.
Management believes that none of these matters will have further
material adverse effect on the company's financial condition or results
of operations.

California Energy Crisis

In 2000 and 2001, California experienced a severe energy crisis
characterized by dramatic increases in the prices of electricity and
natural gas. The energy crisis has generated many, often duplicative,
governmental investigations, regulatory proceedings and lawsuits
involving numerous energy companies seeking recovery of tens of
billions of dollars for allegedly unlawful activities asserted to have
caused or contributed to the energy crisis. The material proceedings
arising out of the energy crisis that involve the company are
summarized below.

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Natural Gas Cases

Class-action and individual antitrust and unfair competition lawsuits
filed in 2000 and thereafter, and currently consolidated in San Diego
Superior Court, seek damages, alleging that Sempra Energy, SoCalGas and
SDG&E, along with El Paso and several of its affiliates, unlawfully
sought to control natural gas and electricity markets. In December
2003, the Court approved a settlement whereby the applicable El Paso
entities will pay approximately $1.6 billion to resolve these claims
(including cases involving unrelated claims not applicable to Sempra
Energy, SoCalGas or SDG&E). The proceeding against Sempra Energy and
the California Utilities has not been settled and continues to be
litigated. In October 2004, certain of the plaintiffs issued a news
release asserting that they could recover as much as $24 billion from
Sempra Energy and the California Utilities if their allegations were
upheld at trial. During the third quarter of 2004, the court denied
motions for summary judgment in favor of Sempra Energy and the
California Utilities. The Court of Appeal has declined to review the
summary judgment denial and the companies have petitioned for review by
the California Supreme Court. Interim review pending a final decision
on the merits of the case is entirely at the discretion of the
California Supreme Court. On January 18, 2005, the judge stated that
pre-trial motions will be heard on June 3, 2005, and set a trial date
of September 2, 2005.

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. The claims against the Sempra Energy
defendants in the Arizona lawsuit were settled in September 2004 for
$150,000 and have been dismissed with prejudice. The Nevada Attorney
General's lawsuit remains pending.

The company is cooperating with an investigation being conducted by the
California Attorney General into possible anti-competitive behavior in
the natural gas and electricity markets during the 2000-2001 energy
crisis. In December 2004, several of the company's senior officers
testified at investigational hearings conducted by the California
Attorney General's Office. The company expects additional hearings to
take place in early 2005.

In April 2003, Sierra Pacific Resources and its utility subsidiary
Nevada Power filed a lawsuit in U.S. District Court in Las Vegas
against major natural gas suppliers, and included Sempra Energy, the
California Utilities and other company subsidiaries, seeking recovery
of damages alleged to aggregate in excess of $150 million (before
trebling) 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 to resolve.
However, the court granted plaintiffs' request to amend their
complaint. Sempra Energy filed another motion to dismiss on plaintiffs'
amended complaint. After argument on November 29, 2004, the federal
court dismissed the Sierra Pacific case with prejudice. Plaintiffs have
filed a notice of appeal with the Ninth Circuit Court of Appeals.

In July 2004, the City and County of San Francisco, the County of Santa
Clara and the County of San Diego brought actions, alleging that energy
prices were unlawfully manipulated by defendants' reporting

76

artificially inflated natural gas prices to trade publications and by
entering into wash trades and by engaging in "churning" transactions
with Reliant Energy, in San Diego Superior Court against various
entities, including Sempra Energy, Sempra Commodities, SoCalGas and
SDG&E.

Electricity Cases

Various antitrust lawsuits, which seek class-action certification,
allege that numerous entities, including Sempra Energy and certain
subsidiaries, including SDG&E, that participated in the wholesale
electricity markets unlawfully manipulated those markets. Collectively,
these lawsuits allege damages against all defendants in an aggregate
amount in excess of $16 billion (before trebling). In January 2003, the
federal court granted a motion to dismiss one of these lawsuits, filed
by the Snohomish County, Washington Public Utility District, 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 was appealed to the Ninth Circuit U.S. Court of Appeals.

CPUC 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. The California Utilities are the parties to the first phase of
the investigation. If the investigation were to determine that the
conduct of either of the California Utilities contributed to the
natural gas price spikes that occurred during the investigation period,
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. At
December 31, 2004, the cumulative amount of shareholder awards, all of
which has been included in net income, was $8.4 million.

On November 16, 2004, the CPUC ALJ assigned to the investigation issued
a proposed decision for consideration by the full CPUC in the first
phase of the investigation that did not include any adverse findings or
make any adverse recommendations regarding SDG&E.

The CPUC may hold additional rounds of hearings to consider whether
other companies, including other California utilities, contributed to
the natural gas price spikes. No hearings have yet been scheduled.

FERC Refund Proceedings

The FERC is investigating prices charged to buyers in the California
Power Exchange (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 be
refunded to ratepayers.

In December 2002, a FERC ALJ issued preliminary findings indicating
that the California PX and ISO owe power suppliers $1.2 billion for the

77

October 2, 2000 through June 20, 2001 period (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 adopted its ALJ's findings, but changed the
calculation of the refund by basing it on a different estimate of
natural gas prices. 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 for the same time
period. Pending in the Ninth Circuit are various parties' appeals on
aspects of the FERC's order.

In a series of orders in 2004, the FERC has provided further direction
and clarifications regarding the methodology to be used by the ISO and
PX to recalculate the precise refund obligations and entitlements
through their settlement models.

FERC Manipulation Investigation

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

On June 25, 2003, the FERC issued several orders requiring various
entities to show cause why they should not be found to have violated
California ISO and PX tariffs. The FERC directed 43 entities, including
SDG&E, to show cause why they should not disgorge profits from certain
transactions between January 1, 2000 and June 20, 2001 that are
asserted to have constituted gaming and/or anomalous market behavior
under the California ISO and/or PX tariffs. SDG&E and the FERC resolved
the matter through a settlement, which documents the ISO's finding that
SDG&E did not engage in market activities in violation of the ISO or PX
tariffs, and in which SDG&E agreed to pay $27,792 into a FERC-
established fund.

On June 25, 2003, the FERC determined that it was appropriate to
initiate an investigation into possible physical and economic
withholding in the California ISO and PX markets. 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. For the purpose of investigating economic
withholding, SDG&E received data requests from the FERC staff and
provided responses. In May 2004, based on the results of its
investigation, the FERC's Office of Market Oversight and Investigation
informed SDG&E that its bidding procedures are no longer being
investigated by the FERC.

Settlement of Claims Associated with the FERC's Investigations

During 2004, three settlements of claims associated with the FERC's
investigations were announced. One settlement, in which SDG&E received
a net payment of $11.6 million in August 2004, resolves all but a few
claims against The Williams Companies and Williams Power Company for

78

the period May 1, 2000 through June 20, 2001. Another settlement, in
which SDG&E received a net payment of $13.5 million (of the $13.8
million total SDG&E settlement allocation) in November 2004, resolves
all claims against Dynegy, NRG Energy and West Coast Power LLC for the
period January 1, 2000 through June 20, 2001. A third settlement, in
which SDG&E received a net payment of $14.4 million (of the $14.7
million total SDG&E settlement allocation) in January 2005, resolves
specified claims against Duke Energy for the period January 1, 2000
though June 20, 2001. On January 13, 2005, SDG&E announced a $23.8
million settlement (including an unsecured claim in the Mirant
bankruptcy proceeding valued at approximately $2.4 million), which
resolves specified claims against merchant generator Mirant Corp. for
the 2000-2001 energy crisis period. The settlement is pending final
CPUC, FERC and U.S. Bankruptcy Court (for Mirant) approval. In all
cases, the majority of the funds was received within 20 days of
receiving FERC approval with the remainder contingent on certain
actions by the FERC, the ISO and the PX. Receipt of the remaining
amounts by SDG&E would take place at the conclusion of the FERC refund
proceeding, now expected to be in early 2006. These funds would be
received for the benefit of SDG&E's bundled customers and will
reimburse SDG&E for the costs of litigating this matter. In November
2004, the CPUC approved SDG&E's proposal to apply 70 percent (about $17
million) of the refunds due to ratepayers to the AB 265
undercollection, thus facilitating the full recovery of the
undercollections, as further discussed in Note 10.

Other Litigation

The Utility Consumers' Action Network (UCAN), a consumer-advocacy group
which had requested a CPUC rehearing of a CPUC decision concerning the
allocation of certain power contract gains between SDG&E customers and
the company, appealed the CPUC's rehearing denial to the California
Court of Appeal. On July 12, 2004, the Court of Appeal affirmed the
CPUC's decision. On August 20, 2004, UCAN filed a Petition for Review
in the California Supreme Court. On November 10, 2004, the Supreme
Court denied review.

Department Of Energy Nuclear Fuel Disposal

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

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, 2004, the aggregate
unexpended amount of this commitment was $80 million. Capital
expenditures for underground conversions were $23 million in 2004, $28
million in 2003 and $33 million in 2002.

Concentration Of Credit Risk

The company maintains credit policies and systems to manage overall
credit risk. These policies include an evaluation of potential

79

counterparties' financial condition and an assignment of credit limits.
These credit limits are established based on risk and return
considerations under terms customarily available in the industry. The
company grants credit to customers and counterparties, substantially
all of whom are located in its service territories, which covers all of
San Diego County and an adjacent portion of Orange County.

NOTE 13. QUARTERLY FINANCIAL DATA (UNAUDITED)

Operating revenues and expenses in the fourth quarter of 2004 include the
favorable impact of the final cost of service decision and operating
expenses include litigation costs recorded in the fourth quarter.

Operating revenues in the third quarter of 2003 included the recognition of
$116 million before-tax related to the approved settlement of intermediate-
term purchase power contracts. The after-tax impact to net income was $65
million. Additionally, operating expenses in the third quarter of 2003 were
impacted by a $19 million before-tax charge for litigation. The after-tax
impact was $11 million. Net income in the fourth quarter of 2003 includes
$79 million related to the favorable resolution of income tax issues.

80

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of San Diego Gas & Electric
Company:

We have audited the accompanying consolidated balance sheets of San
Diego Gas & Electric Company and subsidiary (the "Company") as of
December 31, 2004 and 2003, and the related consolidated statements of
income, shareholders' equity and cash flows for each of the three years
in the period ended December 31, 2004. 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 the standards of the Public
Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audit to obtain reasonable
assurance about whether 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 the Company as of
December 31, 2004 and 2003, and the results of its operations and its
cash flows for each of the three years in the period ended December 31,
2004, 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.

We have also audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the effectiveness
of the Company's internal control over financial reporting as of
December 31, 2004, based on the criteria established in Internal
Control-Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission and our report dated February
22, 2005 expressed an unqualified opinion on management's assessment of
the effectiveness of the Company's internal control over financial
reporting and an unqualified opinion on the effectiveness of the
Company's internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

San Diego, California
February 22, 2005

81

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of San Diego Gas & Electric
Company:

We have audited management's assessment, included in the accompanying
Management's Report on Internal Control over Financial Reporting, that
San Diego Gas & Electric and subsidiaries (the "Company") maintained
effective internal control over financial reporting as of December 31,
2004, based on criteria established in Internal Control-Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission. The Company's management is responsible for
maintaining effective internal control over financial reporting and for
its assessment of the effectiveness of internal control over financial
reporting. Our responsibility is to express an opinion on management's
assessment and an opinion on the effectiveness of the Company's
internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audit to obtain reasonable
assurance about whether effective internal control over financial
reporting was maintained in all material respects. Our audit included
obtaining an understanding of internal control over financial
reporting, evaluating management's assessment, testing and evaluating
the design and operating effectiveness of internal control, and
performing such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable basis
for our opinions.

A company's internal control over financial reporting is a process
designed by, or under the supervision of, the company's principal
executive and principal financial officers, or persons performing
similar functions, and effected by the company's board of directors,
management, and other personnel to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally
accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1)
pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the
assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of
financial statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company are being
made only in accordance with authorizations of management and directors
of the company; and (3) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or
disposition of the company's assets that could have a material effect
on the financial statements.

Because of the inherent limitations of internal control over financial
reporting, including the possibility of collusion or improper
management override of controls, material misstatements due to error or
fraud may not be prevented or detected on a timely basis. Also,
projections of any evaluation of the effectiveness of the internal
control over financial reporting to future periods are subject to the
risk that the controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or
procedures may deteriorate.

82

In our opinion, management's assessment that the Company maintained
effective internal control over financial reporting as of December 31,
2004, is fairly stated, in all material respects, based on the criteria
established in Internal Control-Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission. Also
in our opinion, the Company maintained, in all material respects,
effective internal control over financial reporting as of December 31,
2004, based on the criteria established in Internal Control-Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission.

We have also audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the consolidated
financial statements as of and for the year ended December 31, 2004 of
the Company and our report dated February 22, 2005 expressed an
unqualified opinion on those financial statements and included an
explanatory paragraph regarding the Company's adoption of a new
accounting standard.
/s/ DELOITTE & TOUCHE LLP
San Diego, California
February 22, 2005

83

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures - Management has
established disclosure controls and procedures to ensure that
material information relating to the company and its consolidated
subsidiaries is made known to the officers who certify the company's
financial reports and to other members of senior management and the
Board of Directors. 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.

Based on their evaluation as of December 31, 2004, the principal
executive officer and principal financial officer of the company have
concluded that the company's disclosure controls and procedures (as
defined in Rules 13a-15(e) and 15d-15(e) under the Securities
Exchange Act of 1934) are effective, at the reasonable assurance
level, to ensure that the information required to be disclosed by the
company in the reports that it files or submits under the Securities
Exchange Act of 1934 is recorded, processed, summarized and reported
within the time periods specified by SEC rules and forms.

Management's Report on Internal Control Over Financial Reporting -
Company management is responsible for establishing and maintaining
adequate internal control over financial reporting, as defined in
Exchange Act Rule 13a-15(f). Under the supervision and with the
participation of company management, including the principal executive
officer and principal financial officer, the company conducted an
evaluation of the effectiveness of its internal control over financial
reporting based on the framework in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission. Based on the company's evaluation under the
framework in Internal Control - Integrated Framework, management
concluded that the company's internal control over financial reporting
was effective as of December 31, 2004. Management's assessment of the
effectiveness of internal control over financial reporting as of
December 31, 2004 has been audited by Deloitte & Touche LLP, an
independent registered public accounting firm, as stated in its report,
which is included herein.

ITEM 9B. OTHER INFORMATION

In February, 2005, Sempra Energy entered into a severance pay agreement
with each executive officer of SDG&E to replace the previously reported
similar agreements. The agreements are for an initial term of three
years and are subject to automatic one year extensions on each
anniversary of the effective date (commencing with the second
anniversary) unless Sempra Energy or the executive elects not to extend
the term.

The agreements provide severance benefits to the executive in the event
that Sempra Energy or its subsidiaries terminates the executive's

84

employment (other than for cause, death or disability) or the executive
does so for good reason.

Severance benefits under the agreements vary with the executive's
position and include (i) a lump sum cash severance payment varying from
50% to 100% of the sum of the executive's annual base salary plus the
greater of the executive's average annual bonus or average annual
target bonus for the two years prior to termination; (ii) continuation
of health insurance benefits for a period varying from six months to
one year; and (iii) financial planning and outplacement services for a
period varying from 18 months to two years. If the termination were to
occur within two years after a change in control of the company, (i)
the lump sum cash severance payment would be multiplied by two; (ii) an
additional lump sum payment would be paid equal to the pro rata portion
for the year of termination of the target amount payable under any
annual incentive compensation award for that year or, if greater, the
average of the three highest gross annual bonus awards paid to the
executive in the five years preceding the year of termination; (iii)
all equity-based incentive compensation awards would immediately vest
and become exercisable or payable and any restrictions on the awards
would automatically lapse; (iv) a lump sum cash payment would be made
equal to the present value of the executive's benefits under
supplemental executive retirement plans calculated on the basis of the
greater of actual years of service or years of service that would have
been completed upon attaining age 62 and applying certain early
retirement factors; (v) life, disability, accident and health insurance
benefits would be continued for a period varying from one year to two
years; and (vi) financial planning and outplacement services would be
provided for a period varying from two years to three years.

The agreements also provide that if the terminated executive agrees to
provide consulting services for two years and abide by certain
covenants regarding non-solicitation of employees and information
confidentiality, the executive would receive (i) an additional lump sum
payment equal to the executive's annual base salary and the greater of
the executive's target bonus for the year of termination or the average
of the two or three highest gross annual bonus awards paid to the
executive in the five years prior to termination and (ii) health
insurance benefits would be continued for an additional one year.

The agreements also provide for a gross-up payment to offset the
effects of any excise tax imposed on the executive under Section 4999
of the Internal Revenue Code.

Good reason is defined in the agreements to include the assignment to
the executive of duties materially inconsistent with those appropriate
to a senior executive of Sempra Energy and its subsidiaries; a material
reduction in the executive's overall standing and responsibilities
within Sempra Energy and its subsidiaries; and a material reduction in
the executive's annualized compensation and benefit opportunities other
than across-the-board reductions affecting all similarly situated
executives of comparable rank. Following a change in control, good
reason is defined to include an adverse change in the executive's
title, authority, duties, responsibilities or reporting lines;
reduction in the executive's annualized compensation opportunities
other than across-the-board reductions of less than 10% similarly
affecting all similarly situation executives of comparable rank;
relocation of the executive's principal place of employment by more
than 30 miles; and a substantial increase in business travel
obligations. A change in control is defined to include the acquisition

85

by one person or group of 20% or more of the voting power of Sempra
Energy's shares; the election of a new majority of the board of Sempra
Energy comprised of individuals who are not recommended for election by
two-thirds of the current directors or successors to the current
directors who were so recommended for election; certain mergers,
consolidations or sales of assets that result in the shareholders of
Sempra Energy owning less than 60% of the voting power of Sempra Energy
or of the surviving entity or its parent; and approval by shareholders
of the liquidation or dissolution of the company.

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 2005 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 55 Chairman and Chief Executive Officer

Debra L. Reed 48 President and Chief Operating Officer

James P. Avery 48 Senior Vice President, Electric
Transmission

Steven D. Davis 48 Senior Vice President, External
Relations and Chief Financial Officer

Margot A. Kyd 51 Senior Vice President, Corporate
Business Solutions

William L. Reed 52 Senior Vice President, Regulatory
and Strategic Planning

Anne S. Smith 51 Senior Vice President, Customer
Service

Lee M. Stewart 59 Senior Vice President, Gas
Transmission

Terry M. Fleskes 48 Vice President and Controller

* As of December 31, 2004.

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.

86

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 2005 annual meeting of shareholders.

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 2005 annual meeting of shareholders.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information regarding principal accountant fees and services as
required by Item 14 is incorporated by reference from "Proposal 3:
Ratification of Independent Auditors" in the Information Statement
prepared for the May 2005 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

Reports of Independent Registered Public Accounting Firm . . . 80

Statements of Consolidated Income for the years
ended December 31, 2004, 2003 and 2002 . . . . . . . . . . . 33

Consolidated Balance Sheets at December 31,
2004 and 2003. . . . . . . . . . . . . . . . . . . . . . . . 34

Statements of Consolidated Cash Flows for the
years ended December 31, 2004, 2003 and 2002 . . . . . . . . 36

Statements of Consolidated Changes in
Shareholders' Equity for the years ended
December 31, 2004, 2003 and 2002. . . . . . . . . . . . . . 37

Notes to Consolidated Financial Statements . . . . . . . . . . 38

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.

87

3. Exhibits

See Exhibit Index on page 90 of this report.

(b) Reports on Form 8-K

The following reports on Form 8-K were filed after September 30, 2004:

Current Report on Form 8-K filed October 27, 2004, discussing the
current status of the California Utilities' Cost of Service Proceedings
and the Border Price Investigation.

Current Report on Form 8-K filed November 4, 2004, filing as an exhibit
Sempra Energy's press release of November 4, 2004, giving the financial
results for the quarter ended September 30, 2004.

Current Report on Form 8-K filed November 5, 2004, discussing the
current status of the California Utilities' Cost of Service
Proceedings, including a proposed decision and an alternate proposed
decision issued by CPUC commissioners on November 4, 2004.

Current Report on Form 8-K filed November 17, 2004, discussing the
current status of the Border Price Investigation, including the
proposed decision issued by the CPUC Administrative Law Judge on
November 16, 2004.

Current Report on Form 8-K filed December 3, 2004, discussing the
current status of the California Utilities' Cost of Service
Proceedings, including the CPUC decision issued on December 2, 2004.

Current Report on Form 8-K filed December 7, 2004, discussing and
filing as an exhibit the 2005 Deferred Compensation Plan.

Current Report on Form 8-K filed January 11, 2005, discussing the
current status of energy crisis litigation.

Current Report on Form 8-K filed January 18, 2005, discussing the
current status of energy crisis litigation.

Current Report on Form 8-K filed February 23, 2005, filing as an
exhibit Sempra Energy's press release of February 23, 2005, giving the
financial results for the three months ended December 31, 2004.

88

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of San Diego Gas & Electric
Company:

We consent to the incorporation by reference in Registration Statement
Numbers 33-45599, 33-52834, 333-52150 and 33-49837 on Form S-3 of our
reports dated February 22, 2005 (which reports express an unqualified
opinion and include an explanatory paragraph relating to the Company's
adoption of Statement of Financial Accounting Standards No. 143,
Accounting for Asset Retirement Obligations, effective January 1, 2003)
relating to the financial statements of San Diego Gas and Electric
Company and management's report on the effectiveness of internal
control over financial reporting, incorporated by reference in this
Annual Report on Form 10-K of San Diego Gas and Electric Company for
the year ended December 31, 2004.
/S/ DELOITTE & TOUCHE LLP
San Diego, California
February 22, 2005

89

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.

90

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).

4.07 Forty-Ninth Supplemental Indenture dated June 1, 2004 (2004
Sempra Energy Form 10-K, Exhibit 4.07).

91

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).

10.05 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).

Compensation

10.06 Form of Severance Pay Agreement (2004 Sempra Energy 10-K,
Exhibit 10.10).

10.07 Sempra Energy 2005 Deferred Compensation Plan (San Diego Gas &
Electric Form 8-K filed on December 07, 2004, Exhibit 10.1).

10.08 Sempra Energy Employee Stock Incentive Plan (September 30, 2004
Sempra Energy Form 10-Q, Exhibit 10.1).

10.09 Sempra Energy Amended and Restated Executive Life
Insurance Plan (September 30, 2004 Sempra Energy Form 10-Q,
Exhibit 10.2).

10.10 Sempra Energy Excess Cash Balance Plan (September 30, 2004
Sempra Energy Form 10-Q, Exhibit 10.3).

10.11 Form of Sempra Energy 1998 Long Term Incentive Plan
Performance-Based Restricted Stock Award (September 30, 2004
Sempra Energy Form 10-Q, Exhibit 10.4).

10.12 Form of Sempra Energy 1998 Long Term Incentive Plan
Nonqualified Stock Option Agreement (September 30, 2004
Sempra Energy Form 10-Q, Exhibit 10.5).

10.13 Form of Sempra Energy 1998 Non-Employee Directors' Stock
Plan Nonqualified Stock Option Agreement (September 30, 2004
Sempra Energy Form 10-Q, Exhibit 10.6).

10.14 Sempra Energy Supplemental Executive Retirement Plan (September
30, 2004 Sempra Energy Form 10-Q, Exhibit 10.7).

10.15 Neal Schmale Restricted Stock Award Agreement (September 30,
2004 Sempra Energy Form 10-Q, Exhibit 10.8).

10.16 Severance Pay Agreement between Sempra Energy and

92

Donald E. Felsinger (September 30, 2004 Sempra Energy Form 10-Q,
Exhibit 10.9).

10.17 Severance Pay Agreement between Sempra Energy and Neal Schmale
(September 30, 2004 Sempra Energy Form 10-Q, Exhibit 10.10).

10.18 Sempra Energy Executive Personal Financial Planning Program
Policy Document (September 30, 2004 Sempra Energy Form 10-Q,
Exhibit 10.11).

10.19 2003 Sempra Energy Executive Incentive Plan B (2003 Sempra Energy
Form 10-K, Exhibit 10.10).

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

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

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

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

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

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

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

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

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

Financing

10.29 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 (1997 Enova Form 10-K,
Exhibit 10.34).

10.30 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).

10.31 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).

93

10.32 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).

10.33 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).

10.34 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).

10.35 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).

10.36 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).

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

10.38 Loan agreement with the City of Chula Vista in connection with
the issuance of $251.3 million of Industrial Development Revenue
Refunding Bonds, dated as of June 1, 2004 (2004 Sempra Energy Form
10-K, Exhibit 10.43).

Nuclear

10.39 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).

10.40 Amendment No. 1 to the Qualified CPUC Decommissioning Master
Trust Agreement dated September 22, 1994 (see Exhibit 10.39
herein)(1994 SDG&E Form 10-K, Exhibit 10.56).

10.41 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 10.39 herein)(1994 SDG&E Form 10-K, Exhibit 10.57).

10.42 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 10.39 herein)(1996 Form 10-K, Exhibit 10.59).

10.43 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 10.39 herein)(1996 Form 10-K, Exhibit 10.60).

94

10.44 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 10.39 herein)(1999 Form 10-K, Exhibit 10.26).

10.45 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 10.39 herein)(1999 Form 10-K, Exhibit 10.27).

10.46 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 10.39 herein)(2003 Sempra Energy Form 10-K,
Exhibit 10.42).

10.47 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).

10.48 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 10.47 herein)(1996 Form 10-K, Exhibit 10.62).

10.49 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 10.47 herein)(1996 Form 10-K, Exhibit 10.63).

10.50 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 10.47 herein)(1999 Form 10-K, Exhibit 10.31).

10.51 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 10.47 herein)(1999 Form 10-K, Exhibit 10.32).

10.52 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 10.47 herein)(2003 Sempra Energy Form 10-K,
Exhibit 10.48).

10.53 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).

10.54 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).

95

Natural Gas Transportation and Storage

10.55 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).

10.56 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).

10.57 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).

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, 2004,
2003, 2002, 2001 and 2000.

Exhibit 21 -- Subsidiaries

21.01 Schedule of Subsidiaries at December 31, 2004.

Exhibit 23 -- Consent of Independent Registered Public
Accounting Firm, page 88.

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.

96

GLOSSARY

AB California Assembly Bill

AFUDC Allowance for Funds Used During Construction

ALJ Administrative Law Judge

ARB Accounting Research Bulletin

BCAP Biennial Cost Allocation Proceeding

California Utilities San Diego Gas & Electric and Southern California Gas
Company

CEC California Energy Commission

CEMA Catastrophic Event Memorandum Act

CPUC California Public Utilities Commission

DOE Department of Energy

DSM Demand Side Management

DTSC Department of Toxic Substance Control

DWR Department of Water Resources

Edison Southern California Edison Company

El Paso El Paso Natural Gas Company

EMFs Electric and Magnetic Fields

ERMG Energy Risk Management

ERMOC Energy Risk management Oversight Committee

FASB Financial Accounting Standards Board

FERC Federal Energy Regulatory Commission

FSP FASB Staff Position

GIR Gas Industry Restructuring

ICIP Incremental Cost Incentive Mechanism

IOUs Investor-Owned Utilities

IRS Internal Revenue Service

ISFSI Independent Spent Fuel Storage Facility

ISO Independent System Operator

kV Kilovolt

LIFO Last in first out inventory costing method

97

LNG Liquefied Natural Gas

MGP Manufactured-Gas Plants

mmbtu Million British Thermal Units (of natural gas)

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

PRP Potentially Responsible Party

PX Power Exchange

QF Qualifying Facility

RD&D Research Development and Demonstration

ROE Return on Equity

ROR Return on Ratebase

SDG&E San Diego Gas & Electric Company

SFAS Statement of Financial Accounting Standards

SoCalGas Southern California Gas Company

SONGS San Onofre Nuclear Generating Station

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

UCAN Utility Consumers Action Network

VaR Value at Risk

VIE Variable Interest Entity