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, 2001
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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 ]

Exhibit Index on page 70. Glossary on page 75.

Aggregate market value of the voting preferred stock held by non-
affiliates of the registrant as of February 28, 2002 was $19 million.

Registrant's common stock outstanding as of February 28, 2002 was
wholly owned by Enova Corporation.

DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Information Statement prepared for the May 2002
annual meeting of shareholders are incorporated by reference into
Part III.

TABLE OF CONTENTS

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

PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . . 15
Item 6. Selected Financial Data. . . . . . . . . . . . . . . . 16
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . 16
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk . . . . . . . . . . . . . . . . . 31
Item 8. Financial Statements and Supplementary Data. . . . . . 31
Item 9. Changes In and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . 66

PART III
Item 10. Directors and Executive Officers of the Registrant . . 66
Item 11. Executive Compensation . . . . . . . . . . . . . . . . 66
Item 12. Security Ownership of Certain Beneficial Owners
and Management. . . . . . . . . . . . . . . . . . . 67
Item 13. Certain Relationships and Related Transactions . . . . 67

PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . . 67

Independent Auditors' Consent . . . . . . . . . . . . . . . . . 68

Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . 69

Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . 70

Glossary. . . . . . . . . . . . . . . . . . . . . . . . . . . . 75

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

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

GOVERNMENT REGULATION

Local Regulation
SDG&E has electric franchises with the three counties and the 26
cities, and gas franchises with one county and the 23 cities in its
service territory. These franchises allow SDG&E to locate facilities
for the transmission and distribution of electricity and/or natural
gas in the streets and other public places. The franchises do not have
fixed terms, except for the electric and natural gas franchises with
the cities of Chula Vista (2003), Encinitas (2012), San Diego (2021)
and Coronado (2028); and the natural gas franchises with the city of
Escondido (2036) and the county of San Diego (2030).

California Utility Regulation
The State of California Legislature, from time to time, passes laws
that regulate SDG&E's operations. For example, in 1996 the legislature
passed an electric industry deregulation bill, and then in 2000 and
2001 passed additional bills aimed at addressing problems in the
deregulated electric industry. In addition, the legislature enacted a
law in 1999 addressing natural gas industry restructuring.
The 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 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 also 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 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.

United States Utility Regulation
The Federal Energy Regulatory Commission (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.
The Nuclear Regulatory Commission (NRC) oversees the licensing,
construction and operation of nuclear facilities. NRC regulations
require extensive review of the safety, radiological and environmental
aspects of these facilities. Periodically, the NRC requires that newly
developed data and techniques be used to re-analyze the design of a
nuclear power plant and, as a result, requires plant modifications as
a condition of continued operation in some cases.

Licenses and Permits
SDG&E obtains a number of permits, authorizations and licenses in
connection with the transmission and distribution of natural gas and
electricity. They require periodic renewal, which results in
continuing regulation by the granting agency.
Other regulatory matters are described in Notes 12 and 13 of the
notes to Consolidated Financial Statements herein.

SOURCES OF REVENUE

Information on this topic is provided in Note 2 of the notes to
Consolidated Financial Statements herein.

ELECTRIC OPERATIONS

Resource Planning
In 1996, California enacted legislation restructuring California's
investor-owned electric utility industry. The legislation and related
decisions of the CPUC were intended to stimulate competition and
reduce rates. Beginning on March 31, 1998, customers were given the
opportunity to choose to continue to purchase their electricity from
the local utility under regulated tariffs, to enter into contracts
with other energy service providers (direct access), or to buy their
power from the California Power Exchange (PX) that served as a
wholesale power pool allowing all energy producers to participate
competitively. However, supply/demand imbalances and a number of
factors resulted in abnormally high wholesale electric prices
beginning in mid-2000, which caused SDG&E's monthly customer bills to
be substantially higher than normal. These conditions and the
resultant abnormally high electric-commodity prices continued into
2001. In response to these high commodity prices, the California
legislature has adopted legislation intended to stabilize the
California electric utility industry and reduce wholesale electric
commodity prices. These actions include the California Department of
Water and Resources (DWR) purchasing the net short position of SDG&E
(the power needed by SDG&E's customers, other than that provided by
SDG&E's nuclear generating facilities or its previously existing
purchase power contracts) and the Memorandum of Understanding (MOU)
entered into by representatives of California Governor Davis, the DWR,
Sempra Energy, and SDG&E. Subject to CPUC approval, the MOU
contemplated the implementation of a series of transactions and
regulatory settlements and actions to resolve many of the issues
affecting SDG&E and its customers arising out of the California energy
crisis.
Additional information concerning the MOU and electric-industry
restructuring in general is provided in "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and in
Notes 12 and 13 of the notes to Consolidated Financial Statements
herein.

Electric Resources
In connection with California's electric-industry restructuring,
beginning March 31, 1998, the California investor-owned utilities
(IOUs) were obligated to bid their power supply, including owned
generation and purchased-power contracts, into the PX. The IOUs also
were obligated to purchase from the PX the power that they sell. In
1999, SDG&E completed divestiture of its owned generation other than
nuclear. An Independent System Operator (ISO) schedules power
transactions and access to the transmission system. As discussed in
Note 12 of the notes to Consolidated Financial Statements, due to the
conditions in the California electric utility industry, the PX
suspended its trading operations on January 31, 2001. SDG&E has been
granted authority by the CPUC to purchase up to 1,900 megawatts of
power through bilateral contracts. Also, as discussed above, the
California legislature passed laws (e.g., Assembly Bill 1 in February
2001), authorizing the DWR to enter into long-term contracts to
purchase the portion of power used by SDG&E customers that is not
provided by SDG&E's existing supply. Based on generating plants in
service and purchased-power contracts currently in place, at February
28, 2002, the megawatts (mW) of electric power available to SDG&E are
as follows:

Source mW
--------------------------------------------------
Nuclear generating plants 430*
Long-term contracts with other utilities 84
Contracts with others 359
-----
Total 873
=====
* Net of plants' internal usage

San Onofre Nuclear Generating Station (SONGS): SDG&E owns 20 percent
of the three nuclear units at SONGS (located south of San Clemente,
California). The cities of Riverside and Anaheim own a total of 5
percent of Units 2 and 3. Southern California Edison (Edison) owns the
remaining interests and operates the units.
Unit 1 was removed from service in November 1992 when the CPUC
issued a decision to permanently shut down the unit. At that time
SDG&E began the recovery of its remaining capital investment, with
full recovery completed in April 1996. The unit's spent nuclear fuel
has been removed from the reactor and is stored on-site. In March
1993, the NRC issued a Possession-Only License for Unit 1, and the
unit was placed in a long-term storage condition in May 1994. In June
1999, the CPUC granted authority to begin decommissioning Unit 1.
Decommissioning work is now in progress.
Units 2 and 3 began commercial operation in August 1983 and April
1984, respectively. SDG&E's share of the capacity is 214 mW of Unit 2
and 216 mW of Unit 3.
SDG&E deposits funds in an external trust to provide for the
decommissioning of all three units.
During 2001, SDG&E spent $6 million on capital additions and
modifications of Units 2 and 3, and expects to spend $9 million in
2002.
Additional information concerning the SONGS units, nuclear
decommissioning and industry restructuring is provided below and in
"Environmental Matters" and "Electric Properties" herein, and in
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" and in Notes 5, 11 and 12 of the notes to
Consolidated Financial Statements herein.

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

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

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

Qualifying Facilities (QFs) --

Applied Energy December 2019 102 Cogeneration

Yuma Cogeneration June 2024 50 Cogeneration

Goal Line Limited
Partnership December 2025 50 Cogeneration

Other QFs (73) Various 32 Cogeneration
------
234
Others --

Various (3) December 2003 125 System Supply
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Total 359
======

Under the contract with PGE, SDG&E pays a capacity charge plus a
charge based on the amount of energy received. Charges under this
contract are based on PGE's costs, including lease payments, fuel
expenses, operating and maintenance expenses, transmission expenses,
administrative and general expenses, and state and local taxes. Costs
under the contracts with QFs are based on SDG&E's avoided cost.
Charges under the remaining contracts are for firm energy only and are
based on the amount of energy received. The prices under these
contracts are at the market value at the time the contracts were
negotiated.
Additional information concerning SDG&E's purchased-power
contracts is provided below, and in "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and Note 12
of the notes to Consolidated Financial Statements herein.

Power Pools
SDG&E is a participant in the Western Systems Power Pool, which
includes an electric-power and transmission-rate agreement with
utilities and power agencies located throughout the United States and
Canada. More than 220 investor-owned and municipal utilities, state
and federal power agencies, energy brokers, and power marketers share
power and information in order to increase efficiency and competition
in the bulk power market. Participants are able to make power
transactions on standardized terms that have been pre-approved by
FERC.

Transmission Arrangements
Pacific Intertie (Intertie): The Intertie, consisting of AC and DC
transmission lines, connects the Northwest with SDG&E, Pacific Gas &
Electric (PG&E), Edison and others under an agreement that expires in
July 2007. SDG&E's share of the Intertie is 266 mW.
Southwest Powerlink: SDG&E's 500-kilovolt Southwest Powerlink
transmission line, which is shared with Arizona Public Service Company
and Imperial Irrigation District, extends from Palo Verde, Arizona to
San Diego. SDG&E's share of the line is 970 mW, although it can be
less, depending on specific system conditions.
Mexico Interconnection: Mexico's Baja California Norte system is
connected to SDG&E's system via two 230-kilovolt interconnections with
firm capability of 408 mW in the north to south direction and 800 mW
in the south to north direction.
Due to electric-industry restructuring (see "Transmission Access"
below), the operating rights of SDG&E on these lines have been
transferred to the ISO.

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

Fuel and Purchased-Power Costs
The following table shows the percentage of each electric-fuel source
used by SDG&E and compares the kilowatt hour (kWh) costs of the fuels
with each other and with the total cost of purchased power:

Percent of kWh Cents per kWh
- ---------------------------------------------------------------
2001 2000 1999 2001 2000 1999
----- ----- ----- ---- ---- ----
Natural gas * -- -- 6.5 -- -- 3.0
Nuclear fuel 30.1 14.9 12.6 0.5 0.5 0.5
----- ----- -----
Total generation 30.1 14.9 19.1
Purchased power
and ISO/PX 69.9 85.1 80.9 9.4 9.7 3.7
----- ----- -----
Total 100.0% 100.0% 100.0%
====== ====== ======

* SDG&E sold its fossil-fuel generating plants during the quarter
ended June 30, 1999.
The cost of purchased power includes capacity costs as well as
the costs of fuel. The cost of natural gas includes transportation
costs. The costs of natural gas and nuclear fuel do not include
SDG&E's capacity costs. While fuel costs are significantly less for
nuclear units than for other units, capacity costs are higher.
As discussed above in "Resource Planning" and "Electric
Resources", during February 2001 the DWR began purchasing the portion
of power used by SDG&E customers that was not provided by SDG&E's
nuclear generating facilities or its previously existing purchase
power contracts.

Electric Fuel Supply
Natural Gas: Information concerning natural gas is provided in
"Natural Gas Operations" herein.
Nuclear Fuel: The nuclear-fuel cycle includes services performed
by others under contract through 2003, including mining and milling of
uranium concentrate, conversion of uranium concentrate to uranium
hexafluoride, enrichment services, and fabrication of fuel assemblies.
Spent fuel from SONGS is being stored on site, where storage
capacity will be adequate at least through 2005. If necessary,
modifications in fuel storage technology can be implemented to provide
on-site storage capacity for operation through 2022, the expiration
date of the NRC operating license. Pursuant to the Nuclear Waste
Policy Act of 1982, SDG&E entered into a contract with the U.S.
Department of Energy (DOE) for spent-fuel disposal. Under the
agreement, the DOE is responsible for the ultimate disposal of spent
fuel. SDG&E pays a disposal fee of $0.90 per megawatt-hour of net
nuclear generation, or approximately $3 million per year. The DOE
projects it will not begin accepting spent fuel until 2010.
To the extent not currently provided by contract, the
availability and the cost of the various components of the nuclear-
fuel cycle for SDG&E's nuclear facilities cannot be estimated at this
time.
Additional information concerning nuclear-fuel costs is provided
in Note 11 of the notes to Consolidated Financial Statements herein.

NATURAL GAS OPERATIONS

SDG&E purchases and distributes natural gas to 774,000 end-use
customers throughout the western portion of San Diego County. The
company also transports natural gas to over 1,000 customers who
procure their natural gas from other sources.

Supplies of Natural Gas
SDG&E buys natural gas under several short-term and long-term
contracts. Short-term purchases are from various Southwest U.S. and
Canadian suppliers and are primarily based on monthly spot-market
prices. SDG&E transports gas under long-term firm pipeline capacity
agreements that provide for annual reservation charges, which are
recovered in rates. SDG&E has long-term natural gas transportation
contracts with various interstate pipelines which expire on various
dates between 2003 and 2023. SDG&E has a long-term purchase agreement
with a Canadian supplier that expires in August 2003, and in which the
delivered cost is tied to the California border spot-market price.
SDG&E purchases natural gas on a spot basis to fill its additional
long-term pipeline capacity. SDG&E intends to continue using the long-
term pipeline capacity in other ways as well, including the transport
of other natural gas for its own use and the release of a portion of
this capacity to third parties.
Most of the natural gas purchased and delivered by the company is
produced outside of California. These supplies are delivered to the
pipeline owned by an SDG&E affiliate, Southern California Gas Company
(SoCalGas), at the California border by interstate pipeline companies,
primarily El Paso Natural Gas Company and Transwestern Natural Gas
Company. These interstate companies provide transportation services
for supplies purchased from other sources by the company or its
transportation customers. The rates that interstate pipeline companies
may charge for natural gas and transportation services are regulated
by the FERC. All natural gas is delivered to SDG&E under a
transportation and storage agreement with SoCalGas.

The following table shows the sources of natural gas deliveries from
1997 through 2001.

Market-sensitive natural gas supplies (supplies purchased on the spot
market, ranging from one month to two years, as well as under longer-
term contracts based on spot prices) accounted for nearly all of total
natural gas volumes purchased by the company. The average price of
natural gas at the California/Arizona border was $7.27/mmbtu in 2001,
compared with $6.25/mmbtu in 2000, and $2.33/mmbtu in 1999.
Supply/demand imbalances and a number of other factors associated
with California's energy crisis in late 2000 and in early 2001
resulted in higher natural gas prices during that period. Prices for
natural gas have subsequently decreased in the later part of 2001. As
of December 31, 2001, the average spot cash price at the
California/Arizona border was $2.63/mmbtu.
The company provided transportation services for the customer-
owned natural gas. The company estimates that sufficient natural gas
supplies will be available to meet the requirements of its customers
for the next several years.

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. There are 775,000 core customers (746,000 residential and
29,000 small commercial and industrial). There are 82 noncore
customers which consist primarily of electric generating plants (UEG),
wholesale purchasers, and large commercial and industrial customers.
Most core customers purchase natural gas directly from the
company. Core customers are permitted to aggregate their natural gas
requirement and, up to a limit of 10 percent of the company's core
market, to purchase natural gas directly from brokers or producers.
Beginning in 2002, the CPUC authorized the removal of the 10 percent
limit. The company continues to be obligated to purchase reliable
supplies of natural gas to serve the requirements of its core
customers. The California utilities recently filed an application
with the CPUC to combine their core procurement portfolios. On March
6, 2002, a proposed decision was issued which, if approved, will allow
SDG&E and SoCalGas to combine their core procurement portfolios. A
final CPUC decision is expected in mid-2002.
Beginning in 2002, utility procurement services offered to
noncore customers will be phased out. Noncore customers will have the
option to either become core customers, and continue to receive
utility procurement services, or remain noncore customers and purchase
their natural gas from other sources, such as brokers or producers.
Noncore customers will also have to make arrangements to deliver their
purchases to the company's receipt points for delivery through the
company's transmission and distribution system.
In 2001, approximately 89 percent of the CPUC-authorized natural
gas margin was allocated to the core customers, with 11 percent
allocated to the noncore customers.
Although revenues from transportation throughput is less than for
natural gas sales, the company generally earns the same margin whether
the company buys the gas and sells it to the customer or transports
natural gas already owned by the customer.

Demand for Natural Gas
Natural gas is a principal energy source for residential, commercial,
industrial and electric generating plant customers. Natural gas
competes with electricity for residential and commercial cooking,
water heating, space heating and clothes drying, and with other fuels
for large industrial, commercial customers and UEG uses. Growth in the
natural gas markets is largely dependent upon the health and expansion
of the southern California economy. The company added approximately
12,000 and 13,000 new customer meters in 2001 and 2000, respectively,
representing growth rates of approximately 1.6 percent and 1.8
percent, respectively. The company expects its growth rate for 2002
will approximate that of 2001.
During 2001, 90 percent of residential energy customers in the
company's service area used natural gas for water heating, 75 percent
for space heating, 55 percent for cooking and 40 percent for clothes
drying.
Demand for natural gas by noncore customers is very sensitive to
the price of competing fuels. Although the number of noncore customers
in 2001 was only 82, they accounted for approximately 8 percent of the
authorized natural gas revenues and 67 percent of total natural gas
volumes. External factors such as weather, the price of electricity,
electric deregulation, the use of hydroelectric power, competing
pipelines and general economic conditions can result in significant
shifts in demand and market price. The demand for natural gas by large
UEG customers is also greatly affected by the price and availability
of electric power generated in other areas.
Effective March 31, 1998, electric industry restructuring gave
California consumers the option of selecting their electric energy
provider from a variety of local and out-of-state producers. As a
result, natural gas demand for electric generation within southern
California competes with electric power generated throughout the
western United States. Although electric industry restructuring has no
direct impact on the company's natural gas operations, future volumes
of natural gas transported for electric generating plant customers may
be significantly affected to the extent that regulatory changes divert
electricity generation from the company's service area.

Other
Additional information concerning customer demand and other aspects of
natural gas operations is provided under "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and in
Notes 11, 12 and 13 of the notes to Consolidated Financial Statements
herein.

RATES AND REGULATION

Electric Industry Restructuring
A flawed electric-industry restructuring plan, electricity
supply/demand imbalances and legislative and regulatory responses have
significantly impacted the company's operations. Additional
information on electric-industry restructuring is provided above under
"Electric Operations," in "Management's Discussion and Analysis of
Financial Condition and Results of Operations," and in Note 12 of the
notes to Consolidated Financial Statements herein.

Natural Gas Industry Restructuring
The natural gas industry in California experienced an initial phase of
restructuring during the 1980s. In December 2001 the CPUC issued a
decision adopting provisions affecting the structure of the natural
gas industry in California, some of which could introduce additional
volatility into the earnings of SDG&E and other market participants.
Additional information on natural gas industry restructuring is
provided in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and in Note 13 of the notes to
Consolidated Financial Statements herein.

Balancing Accounts
In general, earnings fluctuations from changes in the costs of natural
gas and consumption levels for the majority of natural gas are
eliminated through balancing accounts authorized by the CPUC. As a
result of California's electric restructuring law, overcollections
recorded in the electric balancing accounts were applied to transition
cost recovery, and fluctuations in certain costs and consumption
levels can now affect earnings from electric operations. Additional
information on balancing accounts is provided in "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" and in Note 2 of the notes to Consolidated Financial
Statements herein.

Biennial Cost Allocation Proceeding (BCAP)
Rates to recover the changes in the cost of natural gas transportation
services are determined in the BCAP. The BCAP adjusts rates to reflect
variances in customer demand from estimates previously used in
establishing customer natural gas transportation rates. The mechanism
substantially eliminates the effect on income of variances in market
demand and natural gas transportation costs. Additional information on
the BCAP is provided in "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and in Note 13 of the
notes to Consolidated Financial Statements herein.

Cost of Capital
The authorized cost of capital is determined by an automatic
adjustment mechanism based on changes in certain capital market
indices. Additional information on SDG&E's cost of capital is provided
in "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and in Note 12 of the notes to Consolidated
Financial Statements herein.

ENVIRONMENTAL MATTERS

Discussions about environmental issues affecting SDG&E are included in
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" 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, a mechanism that allows SDG&E and other utilities
to recover in rates the costs associated with the cleanup of sites
contaminated with hazardous waste. In general, utilities are allowed
to recover 90 percent of their cleanup costs and any related costs of
litigation.
During the early 1900s, SDG&E and its predecessors manufactured
gas from coal or oil. The manufacturing sites often have become
contaminated with the hazardous residual by-products of the process.
SDG&E has identified three former manufactured-gas plant sites. These
sites have been remediated and closure letters have been received for
two of the sites (discussed below).
Under authority from the Redevelopment Agency for the City of San
Diego, and under oversight by the County of San Diego, Station A (a
former electric generating facility) has been undergoing remediation
since 1998. The vast majority of remedial activities were completed in
1999 and early 2000. $8.7 million was spent in 1999, with an
additional $1.3 million spent in 2000 and $0.3 million spent in 2001.
Included in the activity was remediation of several underground
storage tanks, cleanup of lead-contaminated soil on one block of
Station A, and remediation of fuel oil believed to have leaked from
pipelines under city streets. All closure letters have been received
from the County, with the exception of one open case related to
ongoing groundwater monitoring. At December 31, 2001, the estimated
remaining remediation liability is less than $0.2 million. As
properties are developed, there remains a possibility that additional
contaminated soil will be found.
Remediation was completed in 2000 at SDG&E's former manufactured-
gas plant site in Oceanside at the cost of $0.5 million. Offsite
cleanup was completed in 2001 at a cost of $47,000.
SDG&E sold its fossil-fuel generating facilities in 1999. As a
part of its due diligence for the sale, SDG&E conducted a thorough
environmental assessment of the facilities. Pursuant to the sale
agreements for such facilities, SDG&E and the buyers have apportioned
responsibility for such environmental conditions generally based on
contamination existing at the time of transfer and the cleanup level
necessary for the continued use of the sites as industrial sites.
While the sites are relatively clean, the assessments identified some
instances of significant contamination, principally resulting from
hydrocarbon releases, for which SDG&E has a cleanup obligation under
the agreement. Estimated costs to perform the necessary remediation
are $11 million. These costs were offset against the sales price for
the facilities, together with other appropriate costs, and the
remaining net proceeds were included in the calculation of customer
rates. Remediation of the plants commenced in early 2001. During 2001,
cleanup was completed at three minor sites at a cost of $0.3 million.
Also during 2001, additional assessments were performed at the primary
sites at a cost of $0.3 million. Cleanup completion is expected by the
end of 2002.
Demolition of the Encanto Gas Holder Station began in 2000. The
site, taken out of service in 1995, consisted of a compressor building
and over nine miles of 30-inch diameter steel pipe used to store gas.
Contamination issues at the site include asbestos and hydrocarbons.
Completion of the cleanup is expected in 2002. Cleanup expenses
through the end of 2001 were $0.9 million and remaining expenses,
expected to be incurred in 2002, are estimated at $0.5 million.
SDG&E lawfully disposed 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.
SDG&E and 10 other entities have been named potentially
responsible parties (PRPs) by the California Department of Toxic
Substances 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 electrical 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 10.1 percent, subject to
adjustment based on ultimate responsibility allocations. 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 was $0.2 million,
including $47,000 in 2001.
At December 31, 2001, SDG&E's estimated remaining investigation
and remediation liability related to hazardous waste sites, including
the manufactured-gas sites, was $1 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-fueled 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 SDG&E'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 adverse health effects and
exposure to the type of EMFs emitted by power lines and other
electrical facilities. Some laboratory studies suggest that such
exposure creates biological effects, but those effects have not been
shown to be harmful. The studies that have most concerned the public
are epidemiological studies, some of which have reported a weak
correlation between childhood leukemia and the proximity of homes to
certain power lines and equipment. 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
utilities to adopt a low-cost EMF-reduction policy that requires
reasonable design changes to achieve noticeable reduction of EMF
levels that are anticipated from new projects. However, consistent
with the major scientific reviews of the available research
literature, the CPUC has indicated that no health risk has been
identified.

Air and Water Quality
California's air quality standards are more restrictive than federal
standards. However, as a result of the sale of the company's fossil-
fuel generating facilities, the company's primary air-quality issue,
compliance with these standards has now less significance to the
company's operations.
The transmission and distribution of natural gas require the
operation of compressor stations, which are subject to increasingly
stringent air-quality standards. Costs to comply with these standards
are recovered in rates.
In connection with the issuance of operating permits, SDG&E and
the other owners of SONGS reached agreement with the California
Coastal Commission to mitigate the environmental damage to the marine
environment attributed to the cooling-water discharge from SONGS Units
2 and 3. This mitigation program includes an enhanced fish-protection
system, a 150-acre artificial reef and restoration of 150 acres of
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 $27.7 million. These mitigation
projects are expected to be completed by 2007.

OTHER MATTERS

Research, Development and Demonstration (RD&D)
For 2001, the CPUC authorized SDG&E to fund $1.2 million and $4
million for its natural gas and electric RD&D programs, respectively,
which includes $3.9 million to the CEC for its PIER (Public Interest
Energy Research) Program. SDG&E co-funded several of these projects
with the CEC. Annual RD&D costs have averaged $4.4 million over the
past three years.

Employees of Registrant
As of December 31, 2001, SDG&E had 3,106 employees, compared to 3,248
at December 31, 2000.

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

ITEM 2. PROPERTIES

Electric Properties
SDG&E's generating capacity is described in "Electric Resources"
herein.
SDG&E's electric transmission and distribution facilities include
substations, and overhead and underground lines. The electric
facilities are located in San Diego, Imperial and Orange counties and
in Arizona, and consist of 1,799 miles of transmission lines and
20,428 miles of distribution lines. Periodically various areas of the
service territory require expansion to accommodate customer growth.

Natural Gas Properties
SDG&E's natural gas facilities are located in San Diego and Riverside
counties and consist of the Moreno and Rainbow compressor stations,
166 miles of high pressure transmission pipelines, 7,449 miles of high
and low pressure distribution mains, and 5,989 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.
SDG&E owns or leases other offices, operating and maintenance
centers, shops, service facilities, and equipment necessary in the
conduct of business.

ITEM 3. LEGAL PROCEEDINGS

Except for the matters described in Note 11 of the notes to
Consolidated Financial Statements or referred to elsewhere in this
Annual Report, neither the company nor its subsidiary are party to,
nor is their property the subject of, any material pending legal
proceedings other than routine litigation incidental to their
businesses.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS

All of the issued and outstanding common stock of SDG&E is owned by
Enova Corporation, a wholly owned subsidiary of Sempra Energy. The
information required by Item 5 concerning dividends declared is
included in the "Statements of Consolidated Changes in Shareholders'
Equity" set forth in Item 8 of this Annual Report herein.

ITEM 6. SELECTED FINANCIAL DATA

Since San Diego Gas & Electric Company is a wholly owned subsidiary of
Enova Corporation, per share data has been omitted.
This data should be read in conjunction with the Consolidated
Financial Statements and the notes to Consolidated Financial
Statements contained herein.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

Introduction

This section includes management's discussion and analysis of
operating results from 1999 through 2001, and provides information
about the capital resources, liquidity and financial performance of
San Diego Gas & Electric (SDG&E or the company). It also focuses on
the major factors expected to influence future operating results and
discusses investment and financing 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 electric
and natural gas businesses which provide services to 3 million
customers. It generates and purchases electric energy and distributes
it through 1.2 million electric meters in San Diego County and an
adjacent portion of southern Orange County, California. It also
purchases and distributes natural gas through 0.8 million meters in
San Diego County and transports electricity and gas for others.
SDG&E's only subsidiary is SDG&E Funding LLC, which was formed to
facilitate the issuance of SDG&E's rate reduction bonds as described
in Note 4 of the notes to Consolidated Financial Statements.

Business Combination

Sempra Energy was formed to serve as a holding company for Pacific
Enterprises (PE), the parent corporation of the Southern California
Gas Company (SoCalGas), and Enova Corporation (Enova), the parent
corporation for SDG&E, in connection with a tax-free business
combination that became effective on June 26, 1998 (the business
combination). In connection with the business combination, the holders
of common stock of PE and Enova became the holders of Sempra Energy's
common stock. See Note 1 of the notes to Consolidated Financial
Statements for additional information.

Capital Resources and Liquidity

The company's operations have historically been a major source of
liquidity. However, beginning in the third quarter of 2000 and
continuing into the first quarter of 2001, SDG&E's liquidity and its
ability to make funds available to Sempra Energy were adversely
affected by the electric cost undercollections resulting from a
temporary ceiling on electric rates legislatively imposed in response
to high electric costs. Significant growth in these undercollections
has ceased as a result of an agreement with the California Department
of Water and Resources (DWR), under which the DWR is obligated to
purchase SDG&E's full net short position consisting of the power and
ancillary services required by SDG&E's customers that are not provided
by SDG&E's nuclear generating facilities or its previously existing
purchase power contracts. The agreement extends through December 31,
2002. In addition, the California Public Utilities Commission (CPUC)
is conducting proceedings intended to establish guidelines and
procedures for the eventual resumption of electricity procurement by
SDG&E and the other California investor-owned utilities (IOUs). In
addition, electric costs are now below and are expected to remain
below the rates under the rate ceiling. See further discussion in Note
12 of the notes to Consolidated Financial Statements.
In June 2001, representatives of California Governor Davis, the
DWR, Sempra Energy and SDG&E entered into a Memorandum of
Understanding (MOU) contemplating the implementation of a series of
transactions and regulatory settlements and actions to resolve many of
the issues affecting SDG&E and its customers arising out of the
California energy crisis. Many of the significant elements of the MOU
have received the requisite approvals of the CPUC and have been
implemented. These include settlement of reasonableness reviews and
the application by SDG&E of its $100 million refund involving the
prudence of its purchased-power costs and its overcollections in other
regulatory balancing accounts to reduce the rate-ceiling balancing
account to $392 million at December 31, 2001.
However, in January 2002, the CPUC rejected the MOU's proposed
settlement regarding the rate-making treatment of favorably priced
intermediate-term electricity purchase contracts held by SDG&E. In May
2001, the CPUC issued a decision that, effective February 1, 2001,
electricity purchased under these contracts was to be provided by
SDG&E to its customers at cost. This decision is inconsistent with
prior CPUC staff positions that the electricity was to be provided at
current market prices, with any resulting profits or losses borne by
SDG&E.
In accordance with the May 2001 CPUC decision, SDG&E ceased
recording profits from these contracts effective February 1, 2001, and
none of the profits from the contracts, which have now expired, are
included in the rate-ceiling balancing account. SDG&E had appealed the
CPUC's decision to the California Court of Appeals, but held the
appeal in abeyance pending the settlement contemplated by the MOU,
under which $219 million of the contract profits (including those that
would have been attributable to periods subsequent to February 1, 2001
and, therefore, are not reflected in income) would have been applied
to reduce the rate-ceiling balancing account, with the balance of the
profits retained by SDG&E. Following the CPUC rejection of this
portion of the MOU in January 2002, SDG&E is proceeding with its
appeal and has also filed a complaint in federal district court in San
Diego against the CPUC alleging that the CPUC's actions constitute an
unconstitutional taking and have denied SDG&E its due process rights.
The timing and manner of resolution of this issue will affect SDG&E's
cash flows from the rate-ceiling balancing account.
For additional discussion, see "Factors Influencing Future
Performance--Electric Industry Restructuring and Electric Rates"
herein and Note 12 of the notes to Consolidated Financial Statements.

Cash Flows From Operating Activities

Net cash provided by operating activities totaled $557 million, $174
million and $520 million for 2001, 2000 and 1999, respectively.
The increase in cash flows from operating activities in 2001
compared to 2000 was primarily due to lower customer refunds paid by
SDG&E in 2001 (see below) and the increase in overcollected regulatory
balancing accounts, partially offset by a decrease in accounts
payable. The decrease in accounts payable was due to decreases in the
average prices for natural gas and the DWR's purchasing of SDGE's net
short position for power.
The decrease in cash flows from operating activities in 2000 was
primarily due to SDG&E's refunds to customers for surplus rate-
reduction-bond proceeds, SDG&E's cost undercollections related to
high-electric commodity prices, and energy charges in excess of the
6.5 cents per kilowatt-hour(kWh) ceiling in accordance with AB 265
(see "Results of Operations" below and Note 12 of the notes to
Consolidated Financial Statements). These factors were partially
offset by higher deferred income taxes and accounts payable. The
increase in accounts payable is primarily due to higher sales volumes
and higher prices for natural gas and purchased power. The increase in
deferred income taxes primarily relates to the timing of deductions
for undercollections associated with the higher electricity costs
referred to above.

Cash Flows From Investing Activities

Net cash provided by (used in) investing activities totaled ($310)
million, $288 million and ($225) million for 2001, 2000 and 1999,
respectively.
For 2001, cash flows used in investing activities consisted
primarily of capital expenditures of $307 million for the upgrade and
expansion of utility plant. The decrease in cash flows from investing
activities in 2001 was attributable to loan repayments from Sempra
Energy in 2000. In addition, the increase in proceeds from sale of
assets was due to the sale of property in Blythe, California, for $42
million.
Net cash provided by investing activities increased in 2000
primarily due to the loan repayments noted above, partially offset by
higher capital expenditures. For 2000, cash flows used in investing
activities consisted primarily of capital expenditures of $324 million
for the upgrade and expansion of utility plant.

Capital Expenditures
Capital expenditures in 2001 were down slightly from 2000, which was
$79 million higher than 1999 primarily due to additions and
improvements to SDG&E's natural gas and electric distribution systems.
Over the next five years, the company expects to make capital
expenditures of approximately $2 billion. Construction, investment and
financing programs are continuously 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.
Capital expenditures in 2002 are expectedly to be significantly
higher than in 2001. Significant capital expenditures in 2002 are
expected to include $460 million for additions to the company's
natural gas and electric distribution systems. These expenditures are
expected to be financed by operations and security issuances. These
capital expenditures are dependent on SDG&E's ability to recover its
electricity costs, including the balancing account undercollections
referred to above.

Cash Flows From Financing Activities

Net cash used in financing activities totaled $181 million, $543
million and $242 million for 2001, 2000 and 1999, respectively.
Net cash used in financing activities decreased in 2001 primarily
due to higher dividends paid to Sempra Energy in 2000 and the increase
in the issuance of long-term debt in 2001. The increase in net cash
used in financing activities in 2000 is attributable to the higher
dividends noted above.

Long-Term Debt
In 2001, repayments on long-term debt included $66 million of rate-
reduction bonds and $25 million of unsecured variable-rate bonds.
During December 2000, $60 million of variable-rate industrial
development bonds were put back by the holders and subsequently
remarketed in February 2001 at a fixed interest rate of 7 percent.
In 2000 and 1999, repayments on long-term debt included $66
million of rate-reduction bonds in each year. $10 million and $28
million of first-mortgage bonds were also repaid in 2000 and 1999,
respectively.

Dividends
Dividends paid to Sempra Energy amounted to $150 million in 2001,
compared to $400 million in 2000 and $100 million in 1999.
The payment of future dividends and the amount thereof are within
the discretion of the company's board of directors. The CPUC's
regulation of SDG&E's capital structure limits to $178 million the
portion of its December 31, 2001, retained earnings that is available
for dividends to Sempra Energy.

Capitalization
Total capitalization, including the current portion of long-term debt,
was $2.5 billion at December 31, 2001. The debt-to-capitalization
ratio was 53 percent at December 31, 2001.

Cash and Cash Equivalents
At December 31, 2001, the company had $250 million of revolving lines
of credit, none of which was borrowed. A description of the credit
lines and other information concerning them and related matters is
provided in Notes 3, 4 and 12 of the notes to Consolidated Financial
Statements. Management believes that these amounts, cash flows from
operations and new security issuances will be adequate to finance
capital expenditure requirements and other commitments.

Commitments
The following is a summary of the company's contractual commitments at
December 31, 2001 (in millions of dollars). Additional information
concerning these commitments is provided above and in Notes 4 and 11
of the notes to Consolidated Financial Statements.

Credit Ratings
The credit ratings for SDG&E are as follows:

(As of February 21, 2002) S&P Moody's Fitch
- ----------------------------------------------------------------
Secured Debt AA- Aa3 AA
Unsecured Debt A+ A1 AA-
Preferred Stock A A3 A+
Commercial Paper A-1+ P-1 F1+

In late 2000, California regulatory uncertainties led the credit-
rating agencies to change their rating outlooks on some of these
securities to negative. SDG&E still has negative outlooks from the
three agencies.

Results of Operations

To understand the operations and financial results of SDG&E, it is
important to understand the ratemaking procedures that SDG&E follows.
SDG&E is regulated by the CPUC. It is the responsibility of the
CPUC to determine that utilities operate in the best interests of their
customers and have the opportunity to earn a reasonable return on
investment. In 1996, California enacted legislation restructuring
California's investor-owned electric utility industry. The legislation
and related decisions of the CPUC were intended to stimulate
competition and reduce electric rates. As part of the framework for a
competitive electric-generation market, the legislation established the
California Power Exchange (PX) and the Independent System Operator
(ISO). The PX served as a wholesale power pool and the ISO scheduled
power transactions and access to the transmission system. Due to
subsequent industry restructuring developments, the PX suspended its
trading operations in January 2001.
The natural gas industry experienced an initial phase of
restructuring during the 1980s by deregulating natural gas sales to
noncore customers. In December 2001, the CPUC issued a decision
adopting several provisions that the company believes will make gas
service more reliable, efficient and better tailored to the desires of
customers. The CPUC is still considering the schedule for
implementation of these regulatory changes, but it is expected that
most of the changes will be implemented during 2002.
In connection with restructuring of the electric and natural gas
industries, SDG&E received approval from the CPUC for Performance-Based
Ratemaking (PBR). Under PBR, income potential is tied to achieving or
exceeding specific performance and productivity measures, rather than
to expanding utility plant in a market where a utility already has a
highly developed infrastructure.
See additional discussion of these matters under "Factors
Influencing Future Performance" and in Notes 12 and 13 of the notes to
Consolidated Financial Statements.
The tables below summarize the components of electric and natural
gas volumes and revenues by customer class.

2001 Compared to 2000
Net income increased from $151 million in 2000 to $183 million in
2001. The increase is primarily due to the gain on sale of SDG&E's
Blythe property and lower interest expense incurred as the result of
refunds made to customers in 2000 for the rate-reduction bond
liability, as well as the $30 million after-tax charge for regulatory
issues in 2000 (see discussion below). This increase is partially
offset by lower interest income from affiliates resulting from loan
repayments by Sempra Energy in 2000. Net income increased to $46
million for the fourth quarter of 2001, compared to $39 million for
the corresponding period in 2000. This increase was primarily due to
the sale of the Blythe property, noted above, during the fourth
quarter of 2001.
Electric revenues decreased from $2.2 billion in 2000 to $1.6
billion in 2001, and the cost of electric fuel and purchased power
decreased from $1.3 billion in 2000 to $0.7 billion in 2001. These
decreases were primarily due to the DWR's purchases of SDG&E's net
short position. These purchases and the corresponding sale to SDG&E's
customers are not included in the Statements of Consolidated Income
since SDG&E was merely transporting the electricity from the DWR to
the customers. Similarly, PX/ISO power revenues have been netted
against purchased-power expense to avoid double-counting as SDG&E
sells power into the PX/ISO and then purchases power therefrom. In
addition, volumes were down compared to 2000 due to reductions in
customer demand, arising from conservation efforts encouraged by the
State of California program to give bill credits (funded by the DWR)
to customers who significantly reduced usage. It is uncertain when
SDG&E's electric volumes will return to levels of prior years.
Natural gas revenues increased from $487 million in 2000 to $686
million in 2001, and the cost of natural gas distributed increased from
$273 million in 2000 to $457 million in 2001. These increases were
primarily due to higher average prices for natural gas in 2001. Under
the current regulatory framework, changes in core-market natural gas
prices (gas purchased for customers who are primarily residential and
small commercial and industrial customers, without alternative fuel
capability) do not affect net income, since core customer rates
generally recover the actual cost of natural gas on a substantially
concurrent basis. See discussion of balancing accounts in Note 2 of the
notes to Consolidated Financial Statements.
Other operating expenses increased from $412 million in 2000 to
$495 million in 2001. The increase was primarily due to increased
wages and employee benefits costs, as well as an increase in operating
costs associated with balancing accounts.

2000 Compared to 1999
Net income decreased from $199 million in 1999 to $151 million in 2000.
The decrease is primarily due to a $30 million after-tax charge as noted
above for a potential regulatory disallowance related to the acquisition
of wholesale power in the deregulated California market. Net income
increased to $39 million for the three months ended December 31, 2000,
compared to net income of $36 million for the corresponding period in
1999. This increase was primarily due to higher natural gas sales.
Electric revenues increased from $1.8 billion in 1999 to $2.2
billion in 2000. The increase was primarily due to higher sales to
industrial customers and the effect of higher electric commodity
costs, partially offset by the charge noted above, which reduced
revenues by $50 million, and the decrease in base electric rates (the
noncommodity portion) from the completion of stranded cost recovery.
For 2000, SDG&E's electric revenues included an undercollection of
$447 million as a result of the 6.5-cent rate cap.
Natural gas revenues increased from $389 million in 1999 to $487
million in 2000, primarily due to higher prices for natural gas in
2000 and higher electric generation plant revenues. The increase in
electric generation plant revenues was due to higher demand for
electricity in 2000 and the sale of SDG&E's fossil fuel generating
plants in the second quarter of 1999. Prior to the plant sale, SDG&E's
natural gas revenues from these plants consisted of the margin from
the sales. Subsequent to the plant sale, SDG&E gas revenues consisted
of the price of the natural gas transportation services, since the
sales now are to unrelated parties. In addition, the generating plants
receiving gas transportation from SDG&E were operating at higher
capacities than previously, as discussed below.
The cost of electric fuel and purchased power increased from $0.5
billion in 1999 to $1.3 billion in 2000. The increase was primarily
due to the higher cost of electricity from the PX that has resulted
from higher demand for electricity and the shortage of power plants in
California, higher prices for natural gas used to generate electricity
(as described above), the sale of SDG&E's fossil fuel generating
plants, and warmer weather in California. Under the current regulatory
framework, changes in on-system prices normally do not affect net
income. See the discussions of balancing accounts and electric
revenues in Note 2 of the notes to Consolidated Financial Statements.
In September 2000, as a result of high electricity costs the CPUC
authorized SDG&E to purchase up to 1,900 megawatts of power directly
from third-party suppliers under both short-term contracts and long-
term contracts. Subsequent to December 31, 2000, the state of
California authorized the DWR to purchase all of SDG&E's power
requirements not covered by its own generation or by existing
contracts. These and related events are discussed more fully in Note
12 of the notes to Consolidated Financial Statements.
The cost of natural gas distributed increased from $168 million
in 1999 to $273 million in 2000. The increase was largely due to
higher prices for natural gas. Prices for natural gas have increased
due to the increased use of natural gas to fuel electric generation,
colder winter weather and population growth in California.
Depreciation and decommissioning expense decreased from $561
million in 1999 to $210 million in 2000 and other operating expenses
decreased from $479 million in 1999 to $412 million in 2000. Both
decreases were primarily due to the 1999 sale of SDG&E's fossil fuel
generating plants.

Other Income and Deductions, Interest Expense, and Income Taxes

Other Income and Deductions
Other income and deductions, which primarily consists of interest
income and/or expense from short-term investments and regulatory
balancing accounts, were $56 million, $34 million and $38 million in
2001, 2000 and 1999, respectively. The increase from 2000 to 2001 is
primarily due to the $19 million gain on sale of SDG&E's Blythe,
California property (discussed above in Cash Flows From Investing
Activities), partially offset by lower interest income from affiliates
due to loan repayments by Sempra Energy in 2000.

Interest Expense
Interest expense was $92 million, $118 million and $120 million in
2001, 2000 and 1999, respectively. The decrease in interest expense in
2001 was primarily due to lower interest incurred as the result of
refunds made to customers in 2000 for the rate reduction bond
liability. Interest rates on certain of the company's debt can vary
with credit ratings, as described in Notes 3 and 4 of the notes to
Consolidated Financial Statements. See additional discussion of rate-
reduction bonds in Note 4 of the notes to Consolidated Financial
Statements.

Income Taxes
Income tax expense was $141 million, $144 million and $126 million for
the years ended December 31, 2001, 2000 and 1999, respectively. The
effective income tax rates were 43.5 percent, 48.8 percent and 38.8
percent for the same years. The increase in income tax expense for
2000 compared to 1999 was primarily due to the fact that SDG&E made a
charitable contribution to the San Diego Unified Port District in 1999
in connection with the sale thereto of its South Bay generating plant.

Factors Influencing Future Performance

Factors influencing future performance are summarized below.

Electric Industry Restructuring and Electric Rates
In 1996, California enacted legislation restructuring California's
investor-owned electric utility industry. The legislation and related
decisions of the CPUC were intended to stimulate competition and
reduce electric rates. During the transition period, utilities were
allowed to charge frozen rates that were designed to be above current
costs by amounts assumed to provide a reasonable opportunity to
recover the above-market "stranded" costs of investments in electric-
generating assets. The rate freeze was to end for each utility when it
completed recovery of its stranded costs, but no later than March 31,
2002. SDG&E completed recovery of its stranded costs in June 1999 and,
with its rates no longer frozen, SDG&E's overall rates became subject
to fluctuation with the actual cost of electricity purchases.
Supply/demand imbalances and a number of other factors resulted
in abnormally high electric-commodity costs beginning in mid-2000 and
continuing into 2001. This caused SDG&E's monthly customer bills to be
substantially higher than normal. In response, legislation enacted in
September 2000 imposed a ceiling of 6.5 cents/kWh on the cost of
electricity that SDG&E could pass on to its residential, small-
commercial and lighting customers. The legislation provides for the
future recovery of undercollections in a manner (not specified in the
decision) intended to make SDG&E whole for the reasonable and prudent
costs of procuring electricity. The undercollection, included as a
noncurrent regulatory asset on the Consolidated Balance Sheets,
amounted to $392 million at December 31, 2001.
As a result of the passage of Assembly Bill 1 in February 2001,
the DWR began to purchase power from generators and marketers to
supply a portion of the power requirements of the state's population
that is served by IOUs. The DWR is now purchasing SDG&E's full net
short position (the power needed by SDG&E's customers, other than that
provided by SDG&E's nuclear generating facilities or its previously
existing purchase power contracts). Therefore, increases in SDG&E's
undercollections would result only from these contracts and interest,
offset by nuclear generation, the cost of which is below the 6.5-cent
customer rate cap. Any increases are not expected to be material.
On June 18, 2001, representatives of California Governor Davis,
the DWR, Sempra Energy and SDG&E entered into the MOU, contemplating
the implementation of a series of transactions and regulatory
settlements and actions to resolve many of the issues affecting SDG&E
and its customers arising out of the California energy crisis. The MOU
contemplated, subject to requisite approvals of the CPUC, the
elimination from SDG&E's rate-ceiling balancing account of the
undercollected costs that otherwise would be recovered in future rates
charged to SDG&E customers; settlement of reasonableness reviews,
electricity purchase contract issues and various other regulatory
matters affecting SDG&E. During 2001, the CPUC dealt with several of
these regulatory settlements, including approval of a reduction of the
rate-ceiling balancing account by the application thereto of
overcollections in certain other balancing accounts totaling $70
million and approval of a delay in the effective date of revised base
rates for the California utilities to 2004. In addition, the CPUC
approved a $100 million reduction of the rate-ceiling balancing
account in settlement of the reasonableness of SDG&E's electric
procurement practices between July 1, 1999 through February 7, 2001.
In January 2002, the CPUC rejected the part of the MOU dealing
with a settlement on electricity purchase contracts held by SDG&E. The
MOU would have granted SDG&E ownership of its power sale profits in
exchange for crediting $219 million to customers to offset the rate-
ceiling balancing account. Instead, the CPUC asserted that all the
profits associated with the energy purchase contracts should accrue to
the benefit of customers. The CPUC estimated these profits as $363
million. The company believes the CPUC's calculation is incorrect and
the CPUC has not explained to the company how it arrived at that
amount. In addition, the company believes the CPUC's position is
incorrect and has challenged the CPUC's original disallowance in the
Court of Appeals. The court challenge was put on hold when the MOU was
reached. SDG&E has now reactivated the case and has also filed a
similar suit in federal court. Further discussion is included in Note
12 of the notes to Consolidated Financial Statements.
As discussed in Note 13 of the notes to Consolidated Financial
Statements, the company will make new cost of service filings at the
end of 2002. Upon approval by the CPUC, new rates will be effective
January 1, 2004. See additional discussion of these and related topics
in Note 13 of the notes to Consolidated Financial Statements.
In September 2001, the CPUC suspended the ability of retail
electricity customers to choose their power provider ("direct access")
until at least the end of 2003 in order to improve the probability
that enough revenue would be available to the DWR to cover the state's
power purchases. The decision forbids new direct access contracts
after September 20, 2001. In January 2002, a draft decision was issued
modifying the direct access suspension decision, suspending direct
access retroactively to July 1, 2001. This issue is on the CPUC's
agenda for March 21, 2002. Any effect is not expected to be material
to the company's financial position.
The CPUC is studying whether the incentive plan for the San
Onofre Nuclear Generating Station (SONGS) should be terminated earlier
than currently scheduled. This is discussed in Note 2 of the notes to
Consolidated Financial Statements. The effects of an earlier
termination are not yet determinable.

Natural Gas Restructuring and Gas Rates
On December 11, 2001, the CPUC issued a decision adopting the
following provisions affecting the structure of the natural gas
industry in California, some of which could introduce additional
volatility into the earnings of the company and other market
participants: a system for shippers to hold firm, tradable rights to
capacity on SoCalGas' major gas transmission lines; new balancing
services including separate core and noncore balancing provisions; a
reallocation among customer classes of the cost of interstate pipeline
capacity held by SoCalGas and an unbundling of interstate capacity for
gas marketers serving core customers; and the elimination of noncore
customers' option to obtain gas supply service from SDG&E and
SoCalGas. The CPUC is still considering the schedule for
implementation of these regulatory changes, but it is expected that
most of the changes will be implemented during 2002.

Allowed Rate of Return
SDG&E is authorized to earn an 8.75 percent rate of return on rate
base (ROR) and a 10.6 percent rate of return on common equity (ROE),
effective July 1, 1999, and remaining in effect through 2002. SDG&E is
required to file an application by May 8, 2002, addressing ROE, ROR
and capital structure for 2003. The company can earn more than the
authorized rate by controlling costs below approved levels or by
achieving favorable results in certain areas, such as various
incentive mechanisms. In addition, earnings are affected by changes in
sales volumes.

Utility Integration
On September 20, 2001, the CPUC approved Sempra Energy's request to
integrate the management teams of SDG&E and SoCalGas. The decision
retains the separate identities of each utility and is not a merger.
Instead, utility integration is a reorganization that consolidates
senior management functions of the two utilities and returns to the
utilities a significant portion of shared support services currently
provided by Sempra Energy's centralized corporate center. Once
implementation is completed, the integration is expected to result in
more efficient and effective operations.
In a related development, a CPUC draft decision would allow SDG&E
and SoCalGas to combine their natural gas procurement activities. The
CPUC is scheduled to act on the draft decision at its April 4, 2002
meeting.

Environmental Matters
The company's operations are subject to federal, state and local
environmental laws and regulations governing such things as hazardous
wastes, air and water quality, land use, solid-waste disposal and the
protection of wildlife.
Utility costs to comply with environmental requirements are
generally recovered in customer rates. Therefore, the likelihood of
the company's financial position or results of operations being
adversely affected in a significant manner is believed to be remote.
The environmental issues currently facing the company or resolved
during the latest three-year period include investigation and
remediation of its manufactured-gas sites, cleanup at its former
fossil fuel power plants, cleanup of third-party waste-disposal sites
used by the company, and mitigation of damage to the marine
environment caused by the cooling-water discharge from SONGS.
See further discussion of environmental matters in Note 11 of the
notes to Consolidated Financial Statements.

Market Risk
Market risk is the risk of erosion of the company's cash flows, net
income asset values and equity due to adverse changes in prices for
natural gas and electric commodities, and in interest and foreign-
currency rates.
The company's policy is to use derivative financial instruments to
reduce its exposure to fluctuations in interest rates and commodity
prices. Transactions involving these financial instruments are with
firms believed to be credit worthy. The use of these instruments
exposes the company to market and credit risks which, at times, may be
concentrated with certain counterparties. There were no unusual
concentrations at December 31, 2001, that would indicate an
unacceptable level of risk.
The company uses energy derivatives to manage natural gas price
risk associated with servicing its load requirements. These
instruments can include forward contracts, futures, swaps, options and
other contracts. In the case of price-risk management and trading
activities, the use of derivative financial instruments by the company
is subject to certain limitations imposed by company policy and
regulatory requirements. See the continuing discussion below and Note
9 of the notes to Consolidated Financial Statements for further
information regarding the use of energy derivatives by the company.
The company has adopted corporate-wide policies governing its
market-risk management and trading activities. An Energy Risk
Management Oversight Committee, consisting of senior officers,
oversees company-wide energy risk management activities and monitors
the results of trading activities to ensure compliance with the
company's stated energy-risk management and trading policies. In
addition, SDG&E's risk-management committee monitors energy-price
risk management and trading activities independently from the groups
responsible for creating or actively managing these risks.
Along with other tools, the company uses Value at Risk (VaR) to
measure its exposure to market risk. VaR is an estimate of the
potential loss on a position or portfolio of positions over a
specified holding period, based on normal market conditions and within
a given statistical confidence interval. The company has adopted the
variance/covariance methodology in its calculation of VaR, and uses
both the 95-percent and 99-percent confidence intervals. Historical
volatilities and correlations between instruments and positions are
used in the calculation. As of December 31, 2001, the total VaR of
SDG&E's natural gas positions was not material.
The following discussion of the company's primary market-risk
exposures as of December 31, 2001, includes further discussion of how
these exposures are managed.

Commodity-Price Risk
Market risk related to physical commodities is based upon potential
fluctuations 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 instruments are traded. The
company is exposed, in varying degrees, to price risk 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 natural gas market risk exposure is limited due to
CPUC authorized rate recovery of natural gas purchase, sale and
storage activity. However, the company may at times, be exposed to
market risk as a result of activities under SDG&E's natural gas PBR,
which is discussed in Note 13 of the notes to Consolidated Financial
Statements. SDG&E manages this risk within the parameters of the
company's market-risk management and trading framework. At December
31, 2001 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 fixed-rate long-term debt. The company has
historically funded operations through long-term debt issues with
fixed interest rates and these interest rates are recorded in rates.
With the restructuring of the regulatory process, the CPUC has
permitted greater flexibility within the debt-management process. As a
result, recent debt offerings have been selected with short-term
maturities to take advantage of yield curves, or have used a
combination of fixed-rate and floating-rate debt. Subject to
regulatory constraints, interest-rate swaps may be used to adjust
interest-rate exposures when appropriate, based upon market
conditions.
At December 31, 2001, SDG&E had $1,165 million of fixed-rate debt
and $157 million of variable-rate debt. Interest on fixed-rate utility
debt is fully recovered in historical cost basis rates and interest on
variable-rate debt is generally recovered on a forecasted basis. At
December 31, 2001, SDG&E's fixed-rate debt had a one-year VaR of $245
million and its variable-rate debt had a one-year VaR of $1 million
At December 31, 2001, the notional amount of the company's
interest-rate swap transaction was $45 million. See Note 4 of the
notes to Consolidated Financial Statements for further information
regarding this swap transaction.

Credit Risk
Credit risk relates to the risk of loss that would be incurred as a
result of nonperformance by counterparties pursuant to the terms of
their contractual obligations. The company avoids concentration of
counterparties and maintains credit policies with regard to
counterparties that management believes significantly minimize overall
credit risk. These policies include an evaluation of prospective
counterparties' financial position (including credit ratings),
collateral requirements under certain circumstances, and the use of
standardized agreements that allow for the netting of positive and
negative exposures associated with a single counterparty.
The company monitors credit risk through a credit-approval
process and the assignment and monitoring of credit limits. These
credit limits are established based on risk and return considerations
under terms customarily available in the industry.
The company periodically enters into interest-rate swap
agreements to moderate exposure to interest-rate changes and to lower
the overall cost of borrowing. The company would be exposed to
interest-rate fluctuations on the underlying debt should other parties
to the agreement not perform.

Critical Accounting Policies

The company's most significant accounting policies are described in
Note 2 of the notes to Consolidated Financial Statements. The most
critical policies are Statement of Financial Accounting Standards
(SFAS) 71 "Accounting for the Effects of Certain Types of Regulation,"
and SFAS 133 and SFAS 138 "Accounting for Derivative Instruments and
Hedging Activities" and "Accounting for Certain Derivative Instruments
and Certain Hedging Activities," (see below). All of these policies
are mandatory under generally accepted accounting principles and the
regulations of the Securities and Exchange Commission. Each of these
policies has a material effect on the timing of revenue and expense
recognition for significant company operations.
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
values, and the collectibility of regulatory and other assets. 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 or
other techniques. The assumed collectibility of regulatory assets
considers legal and regulatory decisions involving the specific items
or similar items. The assumed collectibility of other assets considers
the nature of the item, the enforceability of contracts where
applicable, the creditworthiness of other parties and other factors.

New Accounting Standards
Effective January 1, 2001, the company adopted SFAS No. 133
"Accounting for Derivative Instruments and Hedging Activities," as
amended by SFAS No. 138, "Accounting for Certain Derivative
Instruments and Certain Hedging Activities." As amended, SFAS 133
requires that an entity recognize all derivatives as either assets or
liabilities in the statement of financial position, measure those
instruments at fair value and recognize changes in the fair value of
derivatives in earnings in the period of change unless the derivative
qualifies as an effective hedge that offsets certain exposure.
The company utilizes derivative financial instruments to reduce
its exposure to unfavorable changes in energy prices, which are
subject to significant and often volatile fluctuation. Derivative
financial instruments include futures, forwards, swaps, options and
long-term delivery contracts. These contracts allow the company to
predict with greater certainty the effective prices to be received and
the prices to be charged to its customers.
Upon adoption of SFAS 133 on January 1, 2001, the company is
classifying its forward contracts as follows:

Normal Purchase and Sales: These forward contracts are excluded from
the requirements of SFAS No. 133. The realized gains and losses on
these contracts are reflected in the income statement at the contract
settlement date. The contracts that generally qualify as normal
purchases and sales are long-term contracts that are settled by
physical delivery.

Cash Flow Hedges: The unrealized gains and losses related to these
forward contracts would be included in accumulated other comprehensive
income, a component of shareholders' equity, but not reflected in the
Statements of Consolidated Income until the corresponding hedged
transaction is settled. The company has not used this type of hedge
so far.

Electric and Gas Purchases and Sales: The unrealized gains and losses
related to these forward contracts are reflected on the balance sheet
as regulatory assets and liabilities, to the extent derivative gains
and losses will be recoverable or payable in future rates.
If gains and losses at the company are not recoverable or payable
through future rates, the company will apply hedge accounting if
certain criteria are met.
In instances where hedge accounting would be applied to energy
derivatives, cash flow hedge accounting would be elected and,
accordingly, changes in fair values of the derivatives would be
included in other comprehensive income, but not reflected in the
Statements of Consolidated Income until the corresponding hedged
transaction was settled. There was no effect on other comprehensive
income for the year ended December 31, 2001. In instances where energy
derivatives do not qualify for hedge accounting, gains and losses are
recorded in the Statements of Consolidated Income.
The adoption of this new standard on January 1, 2001, did not
have a material impact on the company's earnings. However, $93 million
in current assets, $5 million in noncurrent assets, $2 million in
current liabilities, and $238 million in noncurrent liabilities were
recorded in the Consolidated Balance Sheets as fixed-priced contracts
and other derivatives as of January 1, 2001. Due to the regulatory
environment in which the company operates, regulatory assets and
liabilities were established to the extent that derivative gains and
losses are recoverable or payable through future rates. As such, $93
million in current regulatory liabilities, $5 million in noncurrent
regulatory liabilities, $2 million in current regulatory assets, and
$238 million in noncurrent regulatory assets were recorded in the
Consolidated Balance Sheets as of January 1, 2001. See Note 9 of the
notes to Consolidated Financial Statements for additional information
on the effects of SFAS 133 on the financial statements at December 31,
2001. The ongoing effects will depend on future market conditions and
the company's hedging activities.
In July 2001, the Financial Accounting Standards Board (FASB)
issued three statements, SFAS 141 "Business Combinations," SFAS 142
"Goodwill and Other Intangible Assets" and SFAS 143 "Accounting for
Asset Retirement Obligations." The first two are not presently
relevant to the company.
SFAS 143 addresses financial accounting and reporting for
obligations associated with the retirement of tangible long-lived
assets and the associated asset retirement costs. This applies to
legal obligations associated with the retirement of long-lived assets
that result from the acquisition, construction, development and/or
normal operation of a long-lived asset, such as nuclear plants. It
requires entities to record the fair value of a liability for an asset
retirement obligation in the period in which it is incurred. When the
liability is initially recorded, the entity increases the carrying
amount of the related long-lived asset to reflect the future
retirement cost. Over time, the liability is accreted to its present
value and paid, and the capitalized cost is depreciated over the
useful life of the related asset. SFAS 143 is effective for financial
statements issued for fiscal years beginning after June 15, 2002.
Upon adoption of SFAS 143, the company estimates it would record
an addition of $468 million to utility plant, representing the
company's share of SONGS estimated future decommissioning costs, and a
corresponding retirement obligation liability of $468 million. The
nuclear decommissioning trusts' balance of $526 million at December
31, 2001 represents amounts collected for future decommissioning costs
and has a corresponding amount included in accumulated depreciation.
Any difference between the amount of capitalized cost that would have
been recorded and depreciated and the amounts collected in the nuclear
decommissioning trusts will be recorded as a regulatory asset or
liability. Additional information on SONGS decommissioning is included
in Note 5 of the notes to Consolidated Financial Statements. Except
for SONGS, the company has not yet determined the effect of SFAS 143
on its financial statements.
In August 2001, the FASB issued SFAS 144 "Accounting for the
Impairment or Disposal of Long-Lived Assets" that replaces SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of." SFAS 144 applies to all long-lived assets,
including discontinued operations. SFAS 144 requires that those long-
lived assets classified as held for sale be measured at the lower of
carrying amount or fair value less cost to sell. Discontinued
operations will no longer be measured at net realizable value or
include amounts for operating losses that have not yet occurred. SFAS
144 also broadens the reporting of discontinued operations to include
all components of an entity with operations that can be distinguished
from the rest of the entity and that will be eliminated from the
ongoing operations of the entity in a disposal transaction. The
provisions of SFAS 144 are effective for fiscal years beginning after
December 15, 2001. The company has not yet determined the effect of
SFAS 144 on its financial statements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information required by Item 7A is set forth under "Item 7.
Management's Discussion and Analysis of Financial Condition and
Results of Operations - Market Risk."

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEPENDENT AUDITORS' REPORT

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

We have audited the accompanying consolidated balance sheets of San
Diego Gas & Electric Company and subsidiary as of December 31, 2001
and 2000, and the related statements of consolidated income, cash
flows and changes in shareholders' equity for each of the three years
in the period ended December 31, 2001. These financial statements are
the responsibility of the Company's management. Our responsibility is
to express an opinion on these financial statements based on our
audits.
We conducted our audits in accordance with auditing standards
generally accepted in the United States of America. Those standards
require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of San Diego
Gas & Electric Company and subsidiary as of December 31, 2001 and
2000, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2001, in
conformity with accounting principles generally accepted in the United
States of America.

/s/ DELOITTE & TOUCHE LLP

San Diego, California
February 4, 2002 (February 21, 2002 as to Note 12)

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

Years ended December 31 2001 2000 1999
------- ------- -------

Operating Revenues
Electric $1,627 $2,184 $1,818
Natural gas 686 487 389
------- ------- -------
Total operating revenues 2,313 2,671 2,207
------- ------- -------
Operating Expenses
Electric fuel and net purchased power 733 1,326 536
Cost of natural gas distributed 457 273 168
Other operating expenses 495 412 479
Depreciation and decommissioning 207 210 561
Income taxes 120 134 102
Other taxes and franchise payments 82 81 80
------- ------- -------
Total operating expenses 2,094 2,436 1,926
------- ------- -------
Operating Income 219 235 281
------- ------- -------
Other Income and (Deductions)
Interest income 21 51 40
Regulatory interest 5 (8) (6)
Allowance for equity funds used
during construction 5 6 5
Taxes on non-operating income (21) (10) (24)
Other - net 46 (5) 23
------- ------- -------
Total 56 34 38
------- ------- -------
Interest Charges
Long-term debt 84 81 84
Other 12 39 38
Allowance for borrowed funds
used during construction (4) (2) (2)
------- ------- -------
Total 92 118 120
------- ------- -------
Net Income 183 151 199
Preferred Dividend Requirements 6 6 6
------- ------- -------
Earnings Applicable to Common Shares $ 177 $ 145 $ 193
======= ======= =======

See notes to Consolidated Financial Statements.

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

Balance at December 31 2001 2000
------- -------

ASSETS
Utility plant - at original cost $5,009 $4,778
Accumulated depreciation and decommissioning (2,642) (2,502)
------ ------
Utility plant - net 2,367 2,276
------ ------
Nuclear decommissioning trusts 526 543
------ ------
Current assets:
Cash and cash equivalents 322 256
Accounts receivable - trade 160 233
Accounts receivable - other 27 20
Due from unconsolidated affiliates 28 --
Income taxes receivable 73 236
Regulatory assets arising from fixed-price contracts
and other derivatives 88 --
Other regulatory assets 75 76
Inventories 70 50
Other 3 8
------ ------
Total current assets 846 879
------ ------
Other assets:
Deferred taxes recoverable in rates 162 140
Regulatory assets arising from fixed-price contracts
and other derivatives 673 --
Other regulatory assets 842 849
Deferred charges and other assets 28 47
------ ------
Total other assets 1,705 1,036
------ ------
Total assets $5,444 $4,734
====== ======

See notes to Consolidated Financial Statements.

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

Balance at December 31 2001 2000
------- -------

CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock (255,000,000 shares authorized;
116,583,358 shares outstanding) $ 857 $ 857
Retained earnings 232 205
Accumulated other comprehensive income (loss) (3) (3)
------ ------
Total common equity 1,086 1,059
Preferred stock not subject to mandatory redemption 79 79
------ ------
Total shareholders' equity 1,165 1,138
Preferred stock subject to mandatory redemption 25 25
Long-term debt 1,229 1,281
------ ------
Total capitalization 2,419 2,444
------ ------
Current liabilities:
Accounts payable 139 407
Deferred income taxes 128 252
Regulatory balancing accounts - net 575 367
Fixed-price contracts and other derivatives 89 --
Current portion of long-term debt 93 66
Other 212 196
------ ------
Total current liabilities 1,236 1,288
------ ------
Deferred credits and other liabilities:
Customer advances for construction 42 40
Deferred income taxes 639 502
Deferred investment tax credits 45 48
Fixed-price contracts and other derivatives 673 --
Deferred credits and other liabilities 390 412
------ ------
Total deferred credits and other liabilities 1,789 1,002
------ ------
Contingencies and commitments (Note 11)

Total liabilities and shareholders' equity $5,444 $4,734
====== ======

See notes to Consolidated Financial Statements.

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

Years ended December 31 2001 2000 1999
--------- --------- ---------

Cash Flows from Operating Activities
Net income $ 183 $ 151 $ 199
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation and decommissioning 207 210 561
Customer refunds paid (127) (628) --
Deferred income taxes and investment tax credits (9) 300 (3)
Non-cash rate reduction bond expense (revenue) 66 32 (42)
Gain on disposition of assets (22) -- --
Portion of depreciation arising from sales of
generating plants -- -- (303)
Application of balancing accounts to stranded costs -- -- (66)
Changes in other assets (142) (152) 39
Changes in other liabilities 5 (18) 14
Changes in working capital components:
Accounts receivable 66 (55) 7
Inventories (20) -- --
Income taxes 163 (149) (87)
Other current assets (21) (17) (45)
Accounts payable (268) 252 (6)
Regulatory balancing accounts 426 213 267
Other current liabilities 50 35 (15)
------- ------- -------
Net cash provided by operating activities 557 174 520
------- ------- -------
Cash Flows from Investing Activities
Capital expenditures (307) (324) (245)
Loan repaid by (paid to) affiliate (33) 593 (422)
Net proceeds from sales of generating plants -- -- 466
Net proceeds from sale of assets 42 24 --
Contributions to decommissioning funds (5) (5) (16)
Other (7) -- (8)
------- ------- -------
Net cash provided by (used in) investing
activities (310) 288 (225)
------- ------- -------
Cash Flows from Financing Activities
Dividends paid (156) (406) (106)
Payments on long-term debt (118) (149) (136)
Issuances of long-term debt 93 12 --
------- ------- -------
Net cash used in financing activities (181) (543) (242)
------- ------- -------
Increase (decrease) in cash and cash equivalents 66 (81) 53
Cash and cash equivalents, January 1 256 337 284
------- ------- -------
Cash and cash equivalents, December 31 $ 322 $ 256 $ 337
======= ======= =======

Supplemental Disclosure of Cash Flow Information
Interest payments, net of amounts capitalized $ 83 $ 113 $ 127
======= ======= =======
Income tax payments net of (refunds) $ (11) $ (8) $ 266
======= ======= =======

See notes to Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
Years ended December 31, 2001, 2000 and 1999

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

Balance at December 31, 1998 $ 79 $ 857 $ 267 $1,203
Net income $ 199 199 199
Other comprehensive income adjustment:
Pension (3) $ (3) (3)
-----
Comprehensive income $ 196
Preferred dividends declared ===== (6) (6)
-----------------------------------------------------------------
Balance at December 31, 1999 79 857 460 (3) 1,393
Net income/comprehensive income $ 151 151 151
Common stock dividends declared ===== (400) (400)
Preferred dividends declared (6) (6)
-----------------------------------------------------------------
Balance at December 31, 2000 79 857 205 (3) 1,138
Net income/comprehensive income $ 183 183 183
Common stock dividends declared ===== (150) (150)
Preferred dividends declared (6) (6)
-----------------------------------------------------------------
Balance at December 31, 2001 $ 79 $ 857 $ 232 $ (3) $1,165
=========================================================================================================

See notes to Consolidated Financial Statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. BUSINESS COMBINATION

On June 26, 1998, Enova Corporation (Enova), the parent company of San
Diego Gas & Electric (SDG&E or the company), and Pacific Enterprises
(PE), parent company of Southern California Gas Company (SoCalGas),
combined into a new company named Sempra Energy. As a result of the
combination, each outstanding share of common stock of Enova was
converted into one share of common stock of Sempra Energy and each
outstanding share of common stock of PE was converted into 1.5038
shares of common stock of Sempra Energy.

NOTE 2. SIGNIFICANT ACCOUNTING POLICIES

Principles Of Consolidation
The Consolidated Financial Statements include the accounts of SDG&E
and its sole subsidiary, SDG&E Funding LLC. All material intercompany
accounts and transactions have been eliminated.
As a subsidiary of Sempra Energy, the company receives certain
services therefrom. Although it is charged its allocable share of the
cost of such services, that cost is believed to be less than if the
company had to provide those services itself.

Effects Of Regulation
The accounting policies of the company conform with generally accepted
accounting principles for regulated enterprises and reflect the
policies of the California Public Utilities Commission (CPUC) and the
Federal Energy Regulatory Commission (FERC).
The company prepares its financial statements in accordance with
the provisions of Statement of Financial Accounting Standards (SFAS)
No. 71, "Accounting for the Effects of Certain Types of Regulation,"
under which a regulated utility records a regulatory asset if it is
probable that, through the ratemaking process, the utility will
recover that asset from customers. Regulatory liabilities represent
future reductions in rates for amounts due to customers. To the extent
that portions of the utility operations cease to be subject to SFAS
No. 71, or recovery is no longer probable as a result of changes in
regulation or the utility's competitive position, the related
regulatory assets and liabilities would be written off. In addition,
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of," affects utility plant and
regulatory assets such that a loss must be recognized whenever a
regulator excludes all or part of an asset's cost from rate base. The
application of SFAS No. 121 continues to be evaluated in connection
with industry restructuring. Information concerning regulatory assets
and liabilities is described below in "Revenues," "Regulatory
Balancing Accounts," and "Regulatory Assets and Liabilities," and
industry restructuring is described in Notes 12 and 13.

Revenues
Revenues are derived from deliveries of electricity and natural gas to
customers and changes in related regulatory balancing accounts.
Revenues for electricity and natural gas sales and services are
generally recorded under the accrual method and these revenues are
recognized upon delivery. The portion of SDG&E's electric commodity
that is procured for its customers by the California Department of
Water Resources (DWR) is not included in SDG&E's revenues or costs.
PX/ISO power revenues have been netted against purchased-power expense
to avoid double-counting as SDG&E sells power into the PX/ISO and then
purchases power therefrom. Operating revenue includes amounts for
services rendered but unbilled (approximately one-half month's
deliveries) at the end of each year.
Operating costs of San Onofre Nuclear Generating Station (SONGS)
Units 2 and 3, including nuclear fuel and nuclear fuel financing
costs, and incremental capital expenditures, are recovered through
a performance incentive pricing plan which allows the company to
receive approximately 4 cents per kilowatt-hour(kWh) through 2003. Any
differences between these costs and the incentive price affect net
income. This is intended to make the units more competitive with other
sources. As part of the CPUC's study of retained generation by all
California's investor-owned electric utilities (IOUs), a draft
decision proposes that the incentive plan be terminated effective
December 31, 2001 even though California law provides for its
continuance through 2003. An alternative draft decision proposes that
the incentive plan continue as scheduled. The matter is on the CPUC's
agenda for its March 21, 2002 meeting.
Additional information concerning utility revenue recognition is
discussed below under "Regulatory Balancing Accounts" and "Regulatory
Assets and Liabilities."

Regulatory Balancing Accounts
The amounts included in regulatory balancing accounts represent net
payables (overcollected balancing accounts less undercollected
balancing accounts) of $575 million and $367 million at December 31,
2001 and 2000, respectively.
Balancing accounts provide a mechanism for charging utility
customers the exact amount incurred for certain costs, primarily
commodity costs. As a result of California's electric-restructuring
law, fluctuations in certain costs and consumption levels that had
been balanced now affect earnings from electric operations. In
addition, fluctuations in certain costs and consumption levels affect
earnings from the company's natural gas operations. Additional
information on regulatory matters is included in Notes 12 and 13.

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

Regulatory assets (liabilities) as of December 31 consist of (dollars in
millions):

SDG&E 2001 2000
------------- ------- -------
Fixed-price contracts and other derivatives $ 760 $ 474
Recapture of temporary discounts* 409 --
Undercollected electric commodity cost 392 352
Deferred taxes recoverable in rates 162 140
Unamortized loss on retirement of debt--net 52 57
Employee benefit costs 39 35
Other 26 7
------- -------
Total $1,840 $1,065
======= =======
*In connection with electric industry restructuring, which is described in
Note 12, SDG&E temporarily reduced rates to its small-usage customers.
That reduction is being recovered in rates through 2004.

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

2001 2000
------ ------
Current regulatory assets $ 163 $ 76
Noncurrent regulatory assets 1,677 989
------ ------
Total $1,840 $1,065
====== ======

All assets earn a return or the cash has not yet been expended and the
assets are offset by liabilities that do not incur a carrying cost.

Allowance For Doubtful Accounts
The allowance for doubtful accounts was $5 million, $5 million and $2
million at December 31, 2001, 2000, and 1999, respectively. The
company recorded a provision for doubtful accounts of $9 million, $6
million and $3 million in 2001, 2000 and 1999, respectively.

Inventories
At December 31, 2001, inventory included natural gas and fuel oil of
$34 million, and materials and supplies of $36 million. The
corresponding balances at December 31, 2000 were $12 million and $38
million, respectively. Fuel oil and natural gas are valued by the
last-in first-out (LIFO) method. When the inventory is consumed,
differences between this LIFO valuation and replacement cost will be
reflected in customer rates. Materials and supplies are generally
valued at the lower of average cost or market.

Due from Unconsolidated Affiliates
SDG&E has a promissory note receivable from Sempra Energy which bears a
variable interest rate based on short-term commercial paper rates, and
is due on demand. The note receivable balance was $52 million and $19
million at December 31, 2001 and 2000, respectively. This account also
included $24 million and $19 million of offsetting working capital
balances with Sempra affiliates at December 31, 2001 and 2000,
respectively.

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 service.
The cost of utility plant includes labor, materials, contract
services and related items, and an allowance for funds used during
construction (AFUDC). The cost of most retired depreciable utility
plant, plus removal costs minus salvage value, is charged to
accumulated depreciation. Information regarding electric industry
restructuring and its effect on utility plant is included in Note 12.
Utility plant balances by major functional categories were as follows:

Depreciation rates
Utility Plant for years ended
at December 31 December 31
-----------------------------------------
(Dollars in billions) 2001 2000 2001 2000 1999
---- ---- ---- ---- ----

Natural gas operations $ 1.0 $ 0.9 3.71% 3.79% 3.83%
Electric distribution 2.9 2.7 4.67% 4.67% 4.69%
Electric transmission 0.8 0.8 3.19% 3.21% 3.50%
Other electric 0.3 0.4 8.46% 8.33% 8.21%
------ ------
Total $ 5.0 $ 4.8
====== ======
- ------------------------------------------------------------------

Accumulated depreciation and decommissioning of electric and natural
gas utility plant in service were $2.1 billion and $0.5 billion,
respectively, at December 31, 2001, and were $2.0 billion and $0.5
billion, respectively, at December 31, 2000. Depreciation expense is
based on the straight-line method over the useful lives of the assets
or a shorter period prescribed by the CPUC. See Note 12 for discussion
of the sale of generation facilities and industry restructuring.
Maintenance costs are expensed as incurred.
AFUDC, which represents the cost of funds used to finance the
construction of utility plant, is added to the cost of utility plant.
AFUDC also increases income, partly as an offset to interest charges
and partly as a component of other income, shown in the Statements of
Consolidated Income, although it is not a current source of cash.

Long-Lived Assets
In accordance with SFAS 121, "Accounting for the Impairment of Long-
Lived Assets and for Long-Lived Assets to Be Disposed Of," the company
periodically evaluates whether events or circumstances have occurred
that may affect the recoverability or the estimated useful lives of
long-lived assets. Impairment occurs when the estimated future
undiscounted cash flows exceed the carrying amount of the assets. If
that comparison indicates that the assets' carrying value may be
permanently impaired, such potential impairment is measured based on
the difference between the carrying amount and the fair value of the
assets based on quoted market prices or, if market prices are not
available, on the estimated discounted cash flows. This calculation is
performed at the lowest level for which separately identifiable cash
flows exist.

Nuclear-Decommissioning Liability
At December 31, 2001 and 2000, deferred credits and other liabilities
include $151 million and $162 million, respectively, of accumulated
decommissioning costs associated with the company's interest in SONGS
Unit 1, which was permanently shut down in 1992. The corresponding
liability for SONGS Units 2 and 3 decommissioning (included in
accumulated depreciation and amortization) is $375 million and $381
million at December 31, 2001 and 2000, respectively. Additional
information on SONGS decommissioning costs is included in Note 5.

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, as
applicable, foreign-currency translation adjustments, minimum pension
liability adjustments, unrealized gains and losses on marketable
securities that are classified as available-for-sale, and certain
hedging activities. The components of other comprehensive income are
shown in the Statements of Consolidated Changes in Shareholders'
Equity.

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 assets and
liabilities, and the disclosure of contingent assets and liabilities
at the date of the financial statements, and the reported amounts of
revenues and expenses during the reporting period. Actual results can
differ significantly from those estimates.

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

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

New Accounting Standards
Effective January 1, 2001, the company adopted SFAS No. 133
"Accounting for Derivative Instruments and Hedging Activities," as
amended by SFAS No. 138, "Accounting for Certain Derivative
Instruments and Certain Hedging Activities." As amended, SFAS 133
requires that an entity recognize all derivatives as either assets or
liabilities in the statement of financial position, measure those
instruments at fair value and recognize changes in the fair value of
derivatives in earnings in the period of change unless the derivative
qualifies as an effective hedge that offsets certain exposure.
The company utilizes derivative financial instruments to reduce
its exposure to unfavorable changes in energy prices, which are
subject to significant and often volatile fluctuation. Derivative
financial instruments include futures, forwards, swaps, options and
long-term delivery contracts. These contracts allow the company to
predict with greater certainty the effective prices to be received and
the prices to be charged to its customers.
Upon adoption of SFAS 133 on January 1, 2001, the company
classifies its forward contracts as follows:

Normal Purchase and Sales: These forward contracts are excluded from
the requirements of SFAS No. 133. The realized gains and losses on
these contracts are reflected in the income statement at the contract
settlement date. The contracts that generally qualify as normal
purchases and sales are long-term contracts that are settled by
physical delivery.

Cash Flow Hedges: The unrealized gains and losses related to these
forward contracts would be included in accumulated other comprehensive
income, a component of shareholders' equity, but not reflected in the
Statements of Consolidated Income until the corresponding hedged
transaction is settled. The company has not used this type of hedge
so far.

Electric and Gas Purchases and Sales: The unrealized gains and losses
related to these forward contracts are reflected on the balance sheet
as regulatory assets and liabilities, to the extent derivative gains
and losses will be recoverable or payable in future rates.

If gains and losses at the company are not recoverable or payable
through future rates, the company will apply hedge accounting if
certain criteria are met.
In instances where hedge accounting is applied to energy
derivatives, cash flow hedge accounting is elected and, accordingly,
changes in fair values of the derivatives are included in other
comprehensive income, but not reflected in the Statements of
Consolidated Income until the corresponding hedged transaction is
settled. The effect on other comprehensive income for the year ended
December 31, 2001 was not material. In instances where energy
derivatives do not qualify for hedge accounting, gains and losses are
recorded in the Statements of Consolidated Income.
The adoption of this new standard on January 1, 2001, did not
have a material effect on the company's earnings. However, $93 million
in current assets, $5 million in noncurrent assets, $2 million in
current liabilities, and $238 million in noncurrent liabilities were
recorded in the Consolidated Balance Sheets as fixed-priced contracts
and other derivatives as of January 1, 2001. Due to the regulatory
environment in which the company operates, regulatory assets and
liabilities were established to the extent that derivative gains and
losses are recoverable or payable through future rates. As such, $93
million in current regulatory liabilities, $5 million in noncurrent
regulatory liabilities, $2 million in current regulatory assets, and
$238 million in noncurrent regulatory assets were recorded in the
Consolidated Balance Sheets as of January 1, 2001. See Note 9 of the
notes to Consolidated Financial Statements for additional information
on the effects of SFAS 133 on the financial statements at December 31,
2001. The ongoing effects will depend on future market conditions and
the company's hedging activities.
In July 2001, the Financial Accounting Standards Board (FASB)
issued three statements, SFAS 141 "Business Combinations," SFAS 142
"Goodwill and Other Intangible Assets" and SFAS 143 "Accounting for
Asset Retirement Obligations." The first two are not presently
relevant to the company.
SFAS 143 addresses financial accounting and reporting for
obligations associated with the retirement of tangible long-lived
assets and the associated asset retirement costs. This applies to
legal obligations associated with the retirement of long-lived assets
that result from the acquisition, construction, development and/or
normal operation of a long-lived asset, such as nuclear plants. It
requires entities to record the fair value of a liability for an asset
retirement obligation in the period in which it is incurred. When the
liability is initially recorded, the entity increases the carrying
amount of the related long-lived asset to reflect the future
retirement cost. Over time, the liability is accreted to its present
value and paid, and the capitalized cost is depreciated over the
useful life of the related asset. SFAS 143 is effective for financial
statements issued for fiscal years beginning after June 15, 2002.
Upon adoption of SFAS 143, the company estimates it would record
an addition of $468 million to utility plant representing the
company's share of SONGS estimated future decommissioning costs, and a
corresponding retirement obligation liability of $468 million. The
nuclear decommissioning trusts balance of $526 million at December 31,
2001 represents amounts collected for future decommissioning costs and
has a corresponding offset in accumulated depreciation. Any difference
between the amount of capitalized cost that would have been recorded
and depreciated and the amounts collected in the nuclear
decommissioning trusts will be recorded as a regulatory asset or
liability. Additional information on SONGS decommissioning is included
in Note 5. Except for SONGS, the company has not yet determined the
effect of SFAS 143 on its Consolidated Balance Sheets, but has
determined that it will not have a material effect on its Statements
of Consolidated Income.
In August 2001, the FASB issued SFAS 144 "Accounting for the
Impairment or Disposal of Long-Lived Assets" that replaces SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of." SFAS 144 applies to all long-lived assets,
including discontinued operations. SFAS 144 requires that those long-
lived assets classified as held for sale be measured at the lower of
carrying amount (cost less accumulated depreciation) or fair value
less cost to sell. Discontinued operations will no longer be measured
at net realizable value or include amounts for operating losses that
have not yet occurred. SFAS 144 also broadens the reporting of
discontinued operations to include all components of an entity with
operations that can be distinguished from the rest of the entity and
that will be eliminated from the ongoing operations of the entity in a
disposal transaction. The provisions of SFAS 144 are effective for
fiscal years beginning after December 15, 2001. The adoption of SFAS
144 is not expected to have a material effect on the company's
financial statements.

NOTE 3. SHORT-TERM BORROWINGS

At December 31, 2001, SDG&E had $250 million of revolving lines of
credit, which is available to support commercial paper and variable-
rate long-term debt. The revolving credit commitments on $50 million
and $200 million of these lines expire in July 2002 and August 2002,
respectively, at which time then outstanding borrowings may be
converted into term loans of one and two years, respectively.
Borrowings under the lines would bear interest at rates varying with
market rates and SDG&E's credit rating. These revolving lines of
credit were unused at December 31, 2001 and 2000.

NOTE 4. LONG-TERM DEBT

- -------------------------------------------------------------------
December 31,
(Dollars in millions) 2001 2000
- -------------------------------------------------------------------
First-mortgage bonds
7.625% June 15, 2002 $ 28 $ 28
6.8% June 1, 2015 14 14
5.9% June 1, 2018 68 68
5.9% to 6.4% September 1, 2018 176 176
6.1% September 1, 2019 35 35
Variable rates (2% to 2.4% at December 31,
2001) payable September 1, 2020 58 58
5.85% June 1, 2021 60 60
8.5% April 1, 2022 10 10
6.4% and 7% December 1, 2027 225 165
------------------------
Total 674 614
------------------------
Unsecured long-term debt
5.9% June 1, 2014 130 130
Variable rates (1.75% at December 31, 2001)
payable July 1, 2021 39 39
Variable rates (1.5% at December 31, 2001)
payable December 1, 2021 60 60
6.75% March 1, 2023 25 25
------------------------
Total 254 254
------------------------
Rate-reduction bonds, various rates
(6.15% to 6.37% at December 31, 2001)
payable annually through 2007 395 461
Capital leases -- 19
------------------------
Total 1,323 1,348
Less:
Current portion of long-term debt 93 66
Unamortized discount on long-term debt 1 1
------------------------
Total $1,229 $1,281
- -------------------------------------------------------------------

Maturities of long-term debt are $93 million in 2002, $66 million in
2003, $66 million in 2004, $66 million in 2005, $66 million in 2006
and $965 million thereafter. Holders of variable-rate bonds may
require the issuer to repurchase them prior to scheduled maturity.
However, since repurchased bonds would be remarketed and funds for
repurchase are provided by revolving lines of credit (which are
generally renewed upon expiration and which are described in Note 3),
it is assumed the bonds will be held to maturity for purposes of
determining the maturities listed above.

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. The most
restrictive of these tests (the property test) would permit the
issuance, subject to CPUC authorization, of an additional $1.7 billion
of first-mortgage bonds at December 31, 2001.
During the first quarter of 2001, SDG&E remarketed $150 million
of variable-rate first-mortgage bonds for a five-year term at a fixed
rate of 7 percent. At SDG&E's option, the bonds may be remarketed at a
fixed or floating rate at December 1, 2005, the expiration of the
fixed term.

Callable Bonds
At SDG&E's option, certain bonds may be called at a premium, including
$157 million of variable-rate bonds that are callable at various dates
in 2002. Of SDG&E's remaining callable bonds, $203 million are
callable in 2002, $266 million in 2003, $25 million in 2004 and $105
million in 2005.

Rate-Reduction Bonds
In December 1997, $658 million of rate-reduction bonds were issued on
behalf of SDG&E at an average interest rate of 6.26 percent. These
bonds were issued to facilitate the 10-percent rate reduction mandated
by California's electric-restructuring law, which is described in Note
12. These bonds are being repaid over 10 years by SDG&E's residential
and small commercial customers via a charge on their electricity
bills. These bonds are secured by the revenue streams collected from
customers and are not secured by, or payable from, utility assets.
The sizes of the rate-reduction bond issuances were set so as to
make the IOUs neutral as to the 10-percent rate reduction, and were
based on a four-year period to recover stranded costs. Because SDG&E
recovered its stranded costs in only 18 months (due to the greater-
than-anticipated plant-sale proceeds), the bond sale proceeds were
greater than needed. Accordingly, during the third quarter of 2000,
SDG&E returned to its customers $388 million of surplus bond proceeds
in accordance with a June 8, 2000 CPUC decision. The bonds and their
repayment schedule are not affected by this refund.

Unsecured Long-term Debt
In February 2001, SDG&E remarketed $25 million of variable-rate
unsecured bonds as 6.75 percent fixed-rate debt for a three-year term.
At SDG&E's option, the bonds may be remarketed at a fixed or floating
rate at February 29, 2004, the expiration of the fixed term.

Interest-Rate Swaps
SDG&E periodically enters into interest-rate swap agreements to
moderate its exposure to interest-rate changes and to lower its
overall cost of borrowing. At December 31, 2001, SDG&E has an
interest-rate swap agreement that matures in 2002 and effectively
fixes the interest rate on $45 million of variable-rate underlying
debt at 5.4 percent. This floating-to-fixed-rate swap does not qualify
for hedge accounting and, therefore, the gains and losses associated
with the change in fair value are recorded in the Statements of
Consolidated Income. For the year ended December 31, 2001, the effect
on income was a $1 million loss. Although this financial instrument
does not meet the hedge accounting criteria of SFAS 133, it continues
to be effective in achieving the risk management objectives for which
it was intended. See additional discussion of interest-rate swaps in
Note 9.

Financial Covenants
SDG&E's first-mortgage bond indenture requires the satisfaction of
certain bond interest coverage ratios and the availability of
sufficient mortgaged property to issue additional first-mortgage
bonds, but do not restrict other indebtedness. Note 3 discusses the
financial covenants applicable to short-term debt.

Note 5. FACILITIES UNDER JOINT OWNERSHIP

SONGS and the Southwest Powerlink transmission line are owned jointly
with other utilities. The company's interests at December 31, 2001,
are:

Southwest
Project (Dollars in millions) SONGS Powerlink
- --------------------------------------------------------------------
Percentage ownership 20% 88%
Utility plant in service $70 $219
Accumulated depreciation and amortization $41 $127
Construction work in progress $ 4 $ 1
- --------------------------------------------------------------------

Each of the company and the other owners holds its interest as
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. The amounts specified above for
SONGS include nuclear production, transmission and other facilities.
Certain substation equipment at SONGS is wholly owned by the company.

SONGS Decommissioning
Objectives, work scope and procedures for the future dismantling and
decontamination of the SONGS units must meet the requirements of the
Nuclear Regulatory Commission, the Environmental Protection Agency,
the CPUC and other regulatory bodies.
The company's share of decommissioning costs for the SONGS units
has been estimated to be $468 million in 2001 dollars, based on
escalation of a cost study completed in 1998. Cost studies are updated
every three years and approved by the CPUC. The next such update is
scheduled to be filed with the CPUC in the first half of 2002. Rate
recovery of decommissioning costs is allowed until the time that the
costs are fully recovered, and is subject to adjustment every three
years based on costs allowed by regulators. The amount accrued each
year is currently being collected in rates. Collections are
authorized to continue until 2013, but may be extended until 2022 upon
approval by the CPUC. This amount is considered sufficient to cover
the company's share of future decommissioning costs. Payments to the
nuclear decommissioning trusts (described below under "Nuclear
Decommissioning Trusts") are expected to continue until sufficient
funds have been collected to fully decommission SONGS, which is not
expected to occur before 2022.
Unit 1 was permanently shut down in 1992 and physical
decommissioning began in January 2000. Several structures, foundations
and equipment have been dismantled and removed. Preparations have been
made for the remaining major work to be performed in 2002 and beyond.
That work will include dismantling, removal and disposal of all
remaining Unit 1 equipment and facilities (both nuclear and non-
nuclear components), decontamination of the site and construction of
an on-site storage facility for Unit 1 spent fuel. These activities
are expected to be completed by 2008.
The amounts collected in rates are invested in externally managed
trust funds (described below under "Nuclear Decommissioning Trusts").
The securities held by the trusts are considered available for sale
and the trust assets are shown on the Consolidated Balance Sheets at
market value. These values reflect unrealized gains of $122 million
and $158 million at December 31, 2001, and 2000, respectively, with
the offsetting credit recorded to accumulated depreciation and
decommissioning on the Consolidated Balance Sheets.
In July 2001, the FASB approved SFAS No. 143 "Accounting for
Asset Retirement Obligations," which requires entities to record the
fair value of a liability that results from the acquisition,
construction, development and/or the normal operation of long-lived
assets, such as nuclear power plants. Information concerning the
estimated effect on the company's financial statements is provided in
Note 2. See further discussion regarding SONGS in Notes 11 and 12.

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

At December 31, 2001 and 2000, trust assets were allocated as follows
(dollars in millions):

Qualified Trust Nonqualified Trust
2001 2000 2001 2000
------------- -------------
Domestic equity $ 144 $ 143 $ 48 $ 57
Foreign equity 76 78 -- --
----- ----- ----- -----
Total equity 220 221 48 57
Total fixed income 225 228 33 37
----- ----- ----- -----
Total $ 445 $ 449 $ 81 $ 94
===== ===== ===== =====

The decommissioning cost studies referred to above determine the
appropriate level of contributions to be collected in utility-customer
rates to ensure adequate funding at the decommissioning date. Customer
contribution amounts are determined by estimates of after-tax
investment returns, decommissioning costs and escalation rates for
decommissioning costs. Lower actual investment returns or higher actual
decommissioning costs would result in an increase in customer
contributions.

NOTE 6. INCOME TAXES

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

Years ended December 31 2001 2000 1999
- -------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Depreciation 5.9 6.6 5.2
State income taxes - net of
federal income tax benefit 5.8 8.5 5.9
Tax credits (0.9) (1.5) (2.1)
Other - net (2.3) 0.2 (5.2)
--------------------------
Effective income tax rate 43.5% 48.8% 38.8%
- -------------------------------------------------------------

The components of income tax expense are as follows:

(Dollars in millions) 2001 2000 1999
- ------------------------------------------------------------
Current:
Federal $ 120 $ (115) $ 90
State 30 (41) 39
------------------------
Total 150 (156) 129
-------------------------
Deferred:
Federal 7 244 11
State (13) 59 (9)
-------------------------
Total (6) 303 2
-------------------------
Deferred investment
tax credits (3) (3) (5)
-------------------------
Total income tax expense $ 141 $ 144 $ 126
- ------------------------------------------------------------

Federal and state income taxes are allocated between operating income
and other income. SDG&E is included in the consolidated tax return of
Sempra Energy and is allocated income tax expense from Sempra Energy
in an amount equal to that which would result from filing a separate
return.

Accumulated deferred income taxes at December 31 result from the
following:
(Dollars in millions) 2001 2000
- -------------------------------------------------------------
Deferred tax liabilities:
Differences in financial and
tax bases of utility plant $ 391 $ 341
Balancing accounts and other
regulatory assets 432 470
Loss on reacquired debt 24 24
Other 75 83
-------------------
Total deferred tax liabilities 922 918
-------------------
Deferred tax assets:
Investment tax credits 31 33
Other 124 131
-------------------
Total deferred tax assets 155 164
-------------------
Net deferred income tax liability $ 767 $ 754
- -------------------------------------------------------------

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

(Dollars in millions) 2001 2000
- -------------------------------------------------------------
Current liability $ 128 $ 252
Noncurrent liability 639 502
---------------------
Total $ 767 $ 754
- -------------------------------------------------------------

NOTE 7. EMPLOYEE BENEFIT PLANS

The company sponsors qualified and nonqualified pension plans and
other postretirement benefit plans for its employees.
During 2001, the company participated in a voluntary separation
program. As a result, the company recorded a $13 million special
termination benefit, a $1 million curtailment cost, and a $19 million
settlement gain.
During 2000, the company participated in another voluntary
separation program. As a result, the company recorded a $5 million
special termination benefit.

Pension and Other Postretirement Benefits

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

Other
Pension Benefits Postretirement Benefits
-----------------------------------------------
(Dollars in millions) 2001 2000 2001 2000
- -------------------------------------------------------------------------------

WEIGHTED-AVERAGE ASSUMPTIONS AS OF
DECEMBER 31:
Discount rate 7.25% 7.25%(1) 7.25% 7.25%
Expected return on plan assets 8.00% 8.00% 4.00% 4.00%
Rate of compensation increase 5.00% 5.00% 5.00% 5.00%
Cost trend of covered
Health-care charges - - 7.25%(2) 7.50%(2)

CHANGE IN BENEFIT OBLIGATION:
Net benefit obligation at
January 1 $ 477 $ 476 $ 49 $ 45
Service cost 13 10 1 1
Interest cost 32 36 3 3
Actuarial (gain) loss 4 9 (5) 3
Curtailments (7) (1) - -
Settlements 1 - - -
Special termination benefits 13 5 - -
Benefits paid (85) (58) (3) (3)
----------------------------------------------
Net benefit obligation at
December 31 448 477 45 49
----------------------------------------------
CHANGE IN PLAN ASSETS:
Fair value of plan assets
at January 1 604 713 22 18
Actual return on plan assets (55) (51) 1 3
Employer contributions - - 4 4
Transfer of assets (3) 1 - - -
Benefits paid (85) (58) (3) (3)
----------------------------------------------
Fair value of plan assets
at December 31 465 604 24 22
----------------------------------------------
Plan assets net of obligation
at December 31 17 127 (21) (27)
Unrecognized net actuarial gain (62) (182) (6) -
Unrecognized prior service cost 13 16 - -
----------------------------------------------
Net recorded liability
at December 31 $ (32) $ (39) $ (27) $ (27)
- --------------------------------------------------------------------------------
(1) Discount rate decreased from 7.75% to 7.25%, effective March 1, 2000.
(2) Decreasing to ultimate trend of 6.50% in 2004.
(3) To reflect transfer of plan assets and liability from affiliates.

The following table provides the amounts recognized under "Deferred
credits and other liabilities" on the Consolidated Balance Sheets at
December 31:

Other
Pension Benefits Postretirement Benefits
--------------------------------------------
(Dollars in millions) 2001 2000 2001 2000
- -----------------------------------------------------------------------------------

Accrued benefit cost $(29) $(36) $(27) $(27)
Accumulated other
comprehensive income, pretax (3) (3) - -
--------------------------------------------
Net recorded liability $(32) $(39) $(27) $(27)
- -----------------------------------------------------------------------------------

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

Other
(Dollars in millions) Pension Benefits Postretirement Benefits
-----------------------------------------------
For the years ended December 31 2001 2000 1999 2001 2000 1999
-----------------------------------------------

Service cost $ 13 $ 10 $ 11 $ 1 $ 1 $ 1
Interest cost 32 36 34 3 3 3
Expected return on assets (42) (57) (47) (1) (1) -
Amortization of:
Transition obligation - - - 2 2 2
Prior service cost 3 3 3 - - -
Actuarial gain (7) (17) (9) - - -
Special termination benefits 13 5 - - 1 -
Curtailment cost 1 - - 1 - -
Settlement credit (19) - - - - -
Regulatory adjustment - - - 1 (2) -
-----------------------------------------------
Total net periodic benefit cost
(income) $ (6) $(20) $ (8) $ 7 $ 4 $ 6
- ---------------------------------------------------------------------------------

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

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

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

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

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

Savings Plan
The company offers a savings plan, administered by plan trustees, to
all eligible employees. Eligibility to participate in the plan begins
after one month of completed service. Employees may contribute,
subject to plan provisions, from one percent to 15 percent of their
regular earnings. After one year of completed service, the company
begins to make matching contributions. Employer contributions are
equal to 50 percent of the first 6 percent of eligible base salary
contributed by employees. Employer contributions are invested in
Sempra Energy common stock (new issuances or market purchases) and
must remain so invested until termination of employment. At the
direction of the employees, the employees' contributions are invested
in Sempra Energy common stock, mutual funds or institutional trusts.
Company contributions to the savings plan were $5 million in 2001, $5
million in 2000 and $4 million in 1999.

NOTE 8. STOCK-BASED COMPENSATION

Sempra Energy has stock-based compensation plans intended to align
employee and shareholder objectives related to Sempra Energy's long-
term growth. The plans permit a wide variety of stock-based awards,
including Sempra Energy non-qualified stock options, incentive stock
options, restricted stock, stock appreciation rights, performance
awards, stock payments and dividend equivalents.
In 1995, SFAS No. 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 No. 123, Sempra Energy
and its subsidiaries adopted only its disclosure requirements and
continues to account for stock-based compensation in accordance with
the provisions of Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees."
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 $2 million and $1 million in 2001
and 2000, respectively. There were no expenses recorded in 1999.

NOTE 9. FINANCIAL INSTRUMENTS

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

Carrying Fair Carrying Fair
Amount Value Amount Value
- -------------------------------------------------------------------------------
(Dollars in millions) 2001 2000
- ------------------------------------------------------------------------------

First-mortgage bonds $ 674 $ 704 $ 614 $ 629
Rate-reduction bonds 395 411 461 462
Other long-term debt 253 265 272 281
-------- -------- -------- --------
Total long-term debt $1,322 $1,380 $1,347 $1,372
- -------------------------------------------------------------------------------
Preferred stock $ 104 $ 98 $ 104 $ 89
- -------------------------------------------------------------------------------

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

Accounting for Derivative Instruments and Hedging Activities
Effective January 1, 2001, the company adopted SFAS 133, as amended by
SFAS 138 "Accounting for Certain Derivative Instruments and Certain
Hedging Activities." As amended, SFAS 133 requires that an entity
recognize all derivative instruments as either assets or liabilities
in the statement of financial position, measure the instruments at
fair value and recognize changes in the fair value of derivatives in
earnings in the period of change unless the derivative instrument
qualifies as an effective hedge that offsets certain exposures.
At December 31, 2001, $1 million in other current assets, $89
million in current liabilities and $673 million in noncurrent
liabilities were recorded in the Consolidated Balance Sheets for
fixed-priced contracts and other derivatives. Regulatory assets and
liabilities were established to the extent that derivative gains and
losses are recoverable or payable through future rates. As such, $88
million in current regulatory assets, $673 million in noncurrent
regulatory assets, and $1 million in other current liabilities were
recorded in the Consolidated Balance Sheets as of December 31, 2001.
For the year ended December 31, 2001, $1 million in non-operating
losses was recorded in "Other--net" in the Statements of Consolidated
Income.

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

Interest-Rate Risk Management
The company periodically enters into interest-rate swap agreements to
moderate exposure to interest-rate changes and to lower the overall
cost of borrowing. At December 31, 2001, SDG&E has one interest-rate
swap agreement that matures in 2002 and effectively fixes the interest
rate on $45 million of SDG&E's variable-rate underlying debt at 5.4
percent. This floating-to-fixed-rate swap does not qualify for hedge
accounting and therefore the gains and losses associated with the
change in fair value are recorded in the Statements of Consolidated
Income. For the year ended December 31, 2001, the effect on income was
a $1 million loss as noted above. Although this financial instrument
does not meet the hedge accounting criteria of SFAS 133, it continues
to be effective in achieving the risk management objectives for which
it was intended.

Energy Derivatives
SDG&E utilizes derivative financial instruments to reduce its exposure
to unfavorable changes in energy prices, which are subject to
significant and often volatile fluctuation. Derivative financial
instruments are comprised of futures, forwards, swaps, options and
long-term delivery contracts. These contracts allow SDG&E to predict
with greater certainty the effective prices to be received and to be
charged to its customers. See Note 2 for discussion of how these
derivatives are classified under SFAS 133.

Energy Contracts
SDG&E records natural gas and electric energy contracts in "Cost of
gas distributed" and "Electric fuel and net purchased power,"
respectively, in the Statements of Consolidated Income. For open
contracts not expected to result in physical delivery, changes in
market value of the contracts are recorded in these accounts during
the period the contracts are open, with an offsetting entry to a
regulatory asset or liability. The majority of the company's contracts
result in physical delivery.
There was no impact on the financial statements of consolidated
income for changes in the fair value of derivative instruments, other
than the $1 million loss on the interest-rate swap noted above.

NOTE 10. PREFERRED STOCK AND DIVIDEND RESTRICTIONS

- ------------------------------------------------------------------------------------
Call December 31,
(Dollars in millions, except call price) Price 2001 2000
- ------------------------------------------------------------------------------------

PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION
$20 par value, authorized 1,375,000 shares:
5% Series, 375,000 shares outstanding $ 24.00 $ 8 $ 8
4.50% Series, 300,000 shares outstanding $ 21.20 6 6
4.40% Series, 325,000 shares outstanding $ 21.00 7 7
4.60% Series, 373,770 shares outstanding $ 20.25 7 7
Without par value:
$1.70 Series, 1,400,000 shares outstanding $ 25.85 35 35
$1.82 Series, 640,000 shares outstanding $ 26.00 16 16
----------------------
Total $ 79 $ 79
----------------------
PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION
Without par value, $1.7625 Series, 1,000,000
shares outstanding $ 25.00 $ 25 $ 25
- ------------------------------------------------------------------------------------

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 currently callable except for
the $1.70 and $1.7625 Series (callable in 2003). The $1.7625 Series
has a sinking fund requirement to redeem 50,000 shares per year from
2003 to 2007; the remaining 750,000 shares must be redeemed in 2008.

Dividend Restrictions
The CPUC's regulation of SDG&E's capital structure limits to $178
million the portion of the company's December 31, 2001 retained
earnings that is available for dividends.

NOTE 11. COMMITMENTS AND CONTINGENCIES

Natural Gas Contracts
SDG&E buys natural gas under short-term and long-term contracts.
Short-term purchases are from various Southwest U.S. and Canadian
suppliers and are primarily based on monthly spot-market prices. SDG&E
transports gas under long-term firm pipeline capacity agreements that
provide for annual reservation charges, which are recovered in rates.
SDG&E has long-term natural gas transportation contracts with various
interstate pipelines which expire on various dates between 2003 and
2023.
SDG&E has a long-term purchase agreement with a Canadian
supplier that expires in August 2003, and in which the delivered cost
is tied to the California border spot-market price. SDG&E purchases
natural gas on a spot basis to fill its additional long-term pipeline
capacity. SDG&E intends to continue using the long-term pipeline
capacity in other ways as well, including the transport of other
natural gas for its own use and the release of a portion of this
capacity to third parties.
All of SDG&E's gas is delivered through SoCalGas pipelines under
a short-term transportation agreement. In addition, under a separate
agreement expiring in March 2003, SoCalGas provides SDG&E 4.5 billion
cubic feet of storage capacity with an option for an additional 1.5
billion cubic feet as capacity becomes available.
At December 31, 2001, the future minimum payments under natural
gas contracts were:
Storage and
(Dollars in millions) Transportation Natural Gas
- -----------------------------------------------------------------
2002 $ 16 $ 24
2003 14 16
2004 14 -
2005 14 -
2006 13 -
Thereafter 151 -
----------------------------------
Total minimum payments $ 222 $ 40
- -----------------------------------------------------------------

Total payments under the natural gas contracts were $457 million in
2001, $273 million in 2000 and $220 million in 1999.

Purchased-Power Contracts
SDG&E buys electric power under several long-term contracts. The
contracts expire on various dates between 2003 and 2025. Prior to the
electric rate ceiling described in Note 12, the above-market cost of
contracts was recovered from SDG&E's customers. In general, the market
value of these contracts was recovered by bidding them into the
California Power Exchange (PX) and receiving revenue from the PX for
bids accepted. As of January 1, 2001, in compliance with a FERC order
prohibiting sales to the PX, SDG&E no longer bids those contracts into
the PX. Those contracts are now used to serve customers in compliance
with a CPUC order. In late 2000, SDG&E entered into additional
contracts to serve customers instead of buying all of its power from
the PX. These contracts expire in 2003.
At December 31, 2001, the estimated future minimum payments under
the long-term contracts were:

(Dollars in millions)
- -----------------------------------------------------------------
2002 $ 224
2003 218
2004 172
2005 173
2006 170
Thereafter 2,000
----------
Total minimum payments $2,957
- -----------------------------------------------------------------

The payments represent capacity charges and minimum energy purchases.
SDG&E is required to pay additional amounts for actual purchases of
energy that exceed the minimum energy commitments. Total payments
under the contracts were $512 million in 2001, $257 million in 2000
and $251 million in 1999.
On January 17, 2001, the California Assembly passed a bill (AB1)
to allow the DWR to purchase power under long-term contracts for the
benefit of California consumers. In accordance with AB1, SDG&E entered
into an agreement with the DWR under which the DWR purchases SDG&E's
full net short position (the power needed by SDG&E's customers, other
than that provided by SDG&E's nuclear generating facilities or its
previously existing purchased-power contracts) through December 31,
2002. The CPUC is conducting proceedings intended to establish
guidelines and procedures for the eventual resumption of electricity
procurement by SDG&E and the other California IOUs. For additional
discussion of this matter see Note 12.

Leases
SDG&E has operating leases on real and personal property expiring at
various dates from 2002 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 determined on both fixed and percentage bases, and most leases
contain extension options, which are exercisable by SDG&E. SDG&E
terminated its capital lease agreement for nuclear fuel in mid-2001
and now owns its nuclear fuel.
At December 31, 2001, the minimum rental commitments payable in
future years under all noncancellable leases were:

(Dollars in millions)
- ------------------------------------------------------------
2002 $10
2003 8
2004 7
2005 5
2006 4
Thereafter 16
--------
Total future rental commitment $50
- ------------------------------------------------------------

Rent expense totaled $21 million in 2001, $32 million in 2000 and $39
million in 1999.

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 under the
federal Superfund laws and comparable state laws. Costs incurred to
operate the facilities in compliance with these laws and regulations
generally have been recovered in customer rates.
Costs that mitigate or prevent future environmental contamination
or extend the life, increase the capacity or improve the safety or
efficiency of property utilized in current operations are capitalized.
The company's capital expenditures to comply with environmental laws
and regulations were $1 million in 2001, $2 million in 2000 and
$160,000 in 1999. The increase in 2000 was due to the installation of
air quality control equipment on a compressor facility. 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. In
1994, the CPUC approved the Hazardous Waste Collaborative Memorandum
account, allowing California's energy utilities to recover their
hazardous waste cleanup costs, including those related to Superfund
sites or similar sites requiring cleanup. Cleanup costs at electric
generation related sites 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.
The environmental issues currently facing the company or resolved
during the latest three-year period include investigation and
remediation of its manufactured-gas sites (all three sites completed
as of December 31, 2001 and site-closure letters received for two),
cleanup at its 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 Potentially Responsible Party (investigations
and remediations are continuing), and mitigation of damage to the
marine environment caused by the cooling-water discharge from the
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
liability is probable, to reasonably estimate the amount or range of
amounts of the cost, or certain components thereof. Estimates of the
company's liability are further subject to other uncertainties, such
as the nature and extent of site contamination, evolving remediation
standards and imprecise engineering evaluations. The accruals are
reviewed periodically and, as investigations and remediation proceed,
adjustments are made as necessary. At December 31, 2001, the company's
accrued liability for environmental matters was $10 million related to
cleanup at SDG&E's former fossil-fueled power plants. These accruals
are expected to be paid ratably over the next two years. There are no
circumstances currently known to management that would require
adjustment to the accruals.

Nuclear Insurance
SDG&E and the co-owners of SONGS have purchased primary insurance of
$200 million, the maximum amount available, for public-liability
claims. An additional $9.3 billion of coverage is provided by
secondary financial protection required by the Nuclear Regulatory
Commission and provides for loss sharing among utilities owning
nuclear reactors if a costly accident occurs. SDG&E could be assessed
retrospective premium adjustments of up to $36 million in the event of
a nuclear incident involving any of the licensed, commercial reactors
in the United States, if the amount of the loss exceeds $200 million.
In the event the public-liability limit stated above is insufficient,
the Price-Anderson Act provides for Congress to enact further revenue-
raising measures to pay claims, which could include an additional
assessment on all licensed reactor operators.
Insurance coverage is provided for up to $2.8 billion of property
damage and decontamination liability. Coverage is also provided for
the cost of replacement power, which includes indemnity payments for
up to three years, after a waiting period of 12 weeks. Coverage is
provided primarily through mutual insurance companies owned by
utilities with nuclear facilities. If losses at any of the nuclear
facilities covered by the risk-sharing arrangements were to exceed the
accumulated funds available from these insurance programs, SDG&E could
be assessed retrospective premium adjustments of up to $7 million.
Both the public-liability and property insurance (including
replacement power coverage) include coverage for losses resulting from
acts of terrorism. This includes the risk-sharing arrangement with
other nuclear facilities.

Department Of Energy Decommissioning
The Energy Policy Act of 1992 established a fund for the
decontamination and decommissioning of the Department of Energy (DOE)
nuclear fuel enrichment facilities. Utilities which have used DOE
enrichment services are being assessed a total of $2.3 billion,
subject to adjustment for inflation, over a 15-year period ending in
2006. Each utility's share is based on its share of enrichment
services purchased from the DOE through 1992. SDG&E's annual
assessment is approximately $1 million. This assessment is recovered
through SONGS revenue.

Department Of Energy Nuclear Fuel Disposal
The Nuclear Waste Policy Act of 1982 made the DOE responsible for the
disposal of spent nuclear fuel. However, it is uncertain when the DOE
will begin accepting spent nuclear fuel from SONGS. Continued delays
by the DOE can lead to increased cost of disposal, which could be
significant. If this occurs and the company is unable to recover the
increased costs from the federal government or from its customers, the
company's profitability from SONGS would be adversely affected.

Litigation
Lawsuits filed in 2000 and currently consolidated in San Diego
Superior Court seek class-action certification and allege that Sempra
Energy, SoCalGas, SDG&E and El Paso Energy Corp. acted to drive up the
price of natural gas for Californians by agreeing to stop a pipeline
project that would have brought new and less-expensive natural gas
supplies into California. Management believes the allegations are
without merit.
Except for the matter referred to above, the company is not party
to, nor is its property the subject of, any material pending legal
proceedings other than routine litigation incidental to its business.
Management believes that these matters will not have a material
adverse effect on the company's financial condition or results of
operations.

Electric Distribution System Conversion
Under a CPUC-mandated program and through franchise agreements with
various cities, SDG&E is committed, in varying amounts, to converting
overhead distribution facilities to underground. As of December 31,
2001, the aggregate unexpended amount of this commitment was
approximately $110 million. Capital expenditures for underground
conversions were $12 million in 2001, $26 million in 2000 and $20
million in 1999.

Concentration of Credit Risk
SDG&E maintains credit policies and systems to manage overall credit
risk. These policies include an evaluation of potential
counterparties' financial condition and an assignment of credit
limits. These credit limits are established based on risk and return
considerations under terms customarily available in the industry.
SDG&E grants credit to its utility customers, substantially all of
whom are located in its service territory, which covers all of San
Diego County and an adjacent portion of Orange County.
Supply/demand imbalances and a number of other factors resulted in
abnormally high electric-commodity costs beginning in mid-2000 and
continuing into 2001. This caused SDG&E's monthly customer bills to be
substantially higher than normal. In response, legislation imposed a
ceiling of 6.5 cents/kWh on the cost of electricity that SDG&E could
pass on to its residential, small-commercial and lighting customers on
a current basis. The ceiling extends through December 31, 2002
(December 31, 2003 if deemed by the CPUC to be in the public
interest). Once SDG&E is able to pass on these costs, the company may
experience an increase in customer credit risk. Additional information
on this issue is discussed in Note 12.

NOTE 12. ELECTRIC INDUSTRY RESTRUCTURING

Background
In 1996, California enacted legislation (AB 1890) restructuring
California's investor-owned electric utility industry. The legislation
and related decisions of the CPUC were intended to stimulate
competition and reduce electric rates.
As part of the framework for a competitive electric-generation
market, the legislation established the PX, which served as a
wholesale power pool to which the California IOUs were required to
sell all of their power supply (including owned generation and
purchased-power contracts) and, except to the extent otherwise
authorized by the CPUC, from which they were required to buy all of
the electricity needed to serve their retail consumers. The PX also
purchased power from nonutility generators through an auction process
intended to establish competitive market prices for the power that it
sells to the IOUs. An Independent System Operator (ISO) scheduled
power transactions and access to the transmission system. In
connection with the deregulation of California's electric-utility
industry, during 1999 and 2000, the company sold and purchased
electricity to and from the PX. Net purchase power reflects sales and
purchases to and from the PX/ISO commencing April 1, 1998, at market
prices of energy from SDG&E's power plants and from long-term
purchase-power contracts. Due to subsequent industry restructuring
developments (described below), the PX suspended its trading
operations on January 31, 2001.
The restructuring legislation also established a rate freeze on
amounts that the IOUs could charge their customers. The rate freeze
was designed to generate revenue levels assumed to be sufficient to
provide the IOUs with a reasonable opportunity to recover, by December
31, 2001, their costs of generation and purchased power that are fixed
and unavoidable and included in customer rates. The rate freeze was to
end as to each IOU when it completed recovery of the costs, but in no
event later than March 31, 2002.
In June 1999, SDG&E completed the recovery of its stranded costs,
other than the future above-market portion of its purchased-power
contracts that were in effect at December 31, 1995, and SONGS costs,
both of which continue to be collected in rates. Recovery of the other
costs was effected by, among other things, the sale of SDG&E's fossil
power plants and combustion turbines during the quarter ended June 30,
1999. Therefore, SDG&E is no longer subject to the rate freeze imposed
by AB 1890.
With the rate freeze no longer applicable, SDG&E lowered its base
rates (the portion of its rates not attributable to electric-commodity
costs) and began to pass through to its customers, without markup, the
cost of electricity purchased from the PX. SDG&E's overall rates were
lower than during the rate freeze, but they also became subject to
fluctuation with the actual cost of electricity purchases.

Effect on Customer Rates
As noted above supply/demand imbalances and a number of other factors
resulted in abnormally high electric-commodity prices beginning in
mid-2000 and continuing into 2001. This caused SDG&E's monthly
customer bills to be substantially higher than normal.
These higher prices were initially passed through to SDG&E's
customers and resulted in customer bills that in most cases were
double or triple those from 1999 and early 2000. This resulted in
several legislative and regulatory responses.
California Assembly Bill 265 (AB 265), enacted in September 2000,
imposed a ceiling of 6.5 cents/kWh on the cost of the electric
commodity that SDG&E could pass on to its small-usage customers on a
current basis. Customers covered under the commodity rate ceiling
generally include residential, small-commercial and lighting
customers. The ceiling, retroactive to June 1, 2000, extends through
December 31, 2002, and may be extended through December 31, 2003, if
the CPUC determines that it is in the public interest to do so. The
6.5-cent rate ceiling is a "floating cap" that can float downward as
prices decrease, but cannot exceed actual commodity costs without the
approval of the CPUC. The CPUC subsequently approved an increase to
the system average rate paid by SDG&E customers (to 7.96 cents per
kWh) in order to pass through, without markup, the rates to repay the
DWR for its purchases of power, as described below. The agreement for
the ending of the earlier rate freeze provided for future recovery of
SDG&E's electricity costs that could not be passed on to customers on
a current basis. Although it delayed such recovery, AB 265 reaffirmed
SDG&E's right to later collect undercollections resulting from the
reasonable and prudent costs of procuring the commodity. The
reasonableness reviews related to the commodity costs have been
settled, as discussed below.
SDG&E accumulates the amount that it pays for electricity in
excess of the ceiling rate (the undercollected costs) in an interest-
bearing balancing account. SDG&E expects to amortize these amounts,
together with interest, in rates charged to customers following the
end of the rate-ceiling period. Due to their long-term nature, these
undercollected costs are classified as a noncurrent regulatory asset
on the company's Consolidated Balance Sheets. The undercollection was
$447 million (of which $352 million was included in regulatory assets
and $95 million was included in regulatory balancing accounts on the
Consolidated Balance Sheets) at December 31, 2000. It increased to
approximately $750 million in the first quarter of 2001 and decreased
to $392 million at December 31, 2001. The decrease was due primarily
to the $100 million refund related to prudence of purchase-power costs
and the application of overcollections in other balancing accounts.

Role of the Department of Water Resources
In February 2001, through the passage of AB 1, the DWR began to
purchase power from generators and marketers, who had previously sold
their power to the PX/ISO, and has entered into long-term contracts
for the purchase of a portion of the power requirements of the state's
population that is served by IOUs. SDG&E and the DWR have entered into
an agreement under which the DWR will continue to purchase power for
SDG&E's customers until December 31, 2002.
As the DWR is now purchasing SDG&E's full net short position (the
power needed by SDG&E's customers, other than that provided by SDG&E's
nuclear generating facilities or its previously existing purchased-
power contracts) significant growth in these undercollections has
ceased.
In April 2001, California law AB 43X took effect, extending the
temporary 6.5-cent rate cap to include SDG&E's large customers (the
only customer class not previously covered by the rate cap)
retroactive to February 7, 2001. The reduced future bills did not add
to the undercollection nor did the fourth quarter refunds of past
charges above 6.5 cents, since, in large part, the purchases for these
customers are covered by the agreement between SDG&E and the DWR.

Memorandum of Understanding
On June 18, 2001 representatives of California Governor Davis, the
DWR, Sempra Energy and SDG&E entered into a Memorandum of
Understanding (MOU) contemplating the implementation of a series of
transactions and regulatory settlements and actions to resolve many of
the issues affecting SDG&E and its customers arising out of the
California energy crisis. The MOU contemplated the elimination from
SDG&E's rate-ceiling balancing account of the undercollected costs
that otherwise would be recovered in future customer rates; settlement
of reasonableness reviews, electricity purchase contract issues and
other regulatory matters.
On August 2, 2001, the CPUC approved a reduction of the rate-
ceiling balancing account, as contemplated by the MOU, by the
application thereto of overcollections in certain other balancing
accounts totaling $70 million.
On October 10, 2001, the CPUC issued a decision approving the
delay until 2004 of the effects of revised revenue requirements for
SDG&E and SoCalGas. However, the decision also denied the request by
SDG&E and SoCalGas to continue equal sharing between ratepayers and
shareholders of estimated savings stemming from the 1998 merger
between PE and Enova. Instead, the CPUC ordered that all of the
estimated 2003 merger savings go to ratepayers. The portion to be
refunded to electric ratepayers would be credited to the Transition
Cost Balancing Account (TCBA), based on the net present value (NPV) in
2001 of the savings for 2003. Merger savings related to 2001 and 2002
also would be so credited. The combined NPV is estimated to be $39
million. Merger savings allocable to natural gas ratepayers would be
refunded through once-a-year bill credit, as has been the case.
On November 8, 2001, the CPUC approved a $100 million reduction
of the rate-ceiling balancing account, in settlement of the
reasonableness of SDG&E's electric procurement practices between July
1, 1999 through February 7, 2001.
In January 2002, the CPUC rejected the part of the MOU dealing
with a settlement on electricity purchase contracts held by SDG&E. The
MOU would have granted SDG&E ownership of its power sale profits in
exchange for crediting $219 million to customers to offset the rate-
ceiling balancing account. Instead, the CPUC asserted that all the
profits associated with the energy purchase contracts should accrue to
the benefit of customers. The CPUC estimated these profits as $363
million. The company believes the CPUC's calculation is incorrect and
the CPUC has not explained to the company how it arrived at that
amount. In addition, the company believes the CPUC's position is
incorrect and has challenged the CPUC's original disallowance in the
Court of Appeals. The court challenge was put on hold when the MOU was
reached. SDG&E has now reactivated the case and has also filed a
similar suit in federal court.

Recent Rate Changes
In order to provide sufficient revenues to repay the DWR for the $10
billion of power purchases it made on behalf of the state's three IOUs
during the energy crisis, the CPUC issued a decision in September 2001
that established interim rate increases for SDG&E's electric customers
in an average amount of approximately 1.46 cents per kWh, resulting in
a system average rate of 7.96 cents per kWh when added to the 6.5
cents per kWh rate ceiling discussed above.
On February 21, 2002, the CPUC issued a final decision about the
DWR revenue requirement, approving allocation of the DWR's cost of
providing power based on actual cost of service, which was lower for
SDG&E customers than for those in Northern California and, therefore,
avoids a rate hike for SDG&E customers. Based on this allocation, the
price SDG&E pays to the DWR drops from the previously proposed rate of
9.02 cents per kWh to 7.29 cents per kWh. SDG&E's system average rate
of 7.96 cents per kWh (described above) remains unchanged and will be
addressed separately. The CPUC also voted to relinquish oversight over
DWR power purchases, which allows the state to proceed with the bond
sale of up to $11.1 billion to repay the state's general fund (used
for DWR power purchases during the energy crisis) and to cover
continuing power purchases. Interested parties have 30 days to appeal
the decision.

Direct Access
In September 2001, the CPUC suspended the ability of retail
electricity customers to choose their power provider ("direct access")
until at least the end of 2003 in order to improve the probability
that enough revenue would be available to the DWR to cover the state's
power purchases. The decision forbids new direct access contracts
after September 20, 2001. In January 2002, a draft decision was issued
modifying the direct access suspension decision, suspending direct
access retroactively to July 1, 2001. This issue is on the CPUC's
agenda for March 21, 2002. Any such effect is not expected to be
material to the company's financial position or liquidity.

FERC Actions
The FERC has been investigating prices charged to the California IOUs
by various electric suppliers. The FERC appears to be proceeding in
the direction of awarding to the California IOUs a partial refund of
the amounts charged. Any such refunds would reduce SDG&E's rate-
ceiling balancing account. A FERC decision is not expected before the
second half of 2002.
More recently, FERC has launched an investigation whether there
was manipulation of short-term energy prices in the West that resulted
in unjust and unreasonable long-term power sales contracts. The
results of this investigation will be used by FERC to determine how it
should proceed on existing and future complaints about long-term
contracts, but will not address or prejudge any arguments made in
these proceedings.

NOTE 13. OTHER REGULATORY MATTERS

Gas Industry Restructuring
The natural gas industry in California experienced an initial phase of
restructuring during the 1980s, but the CPUC did not make major
changes after the early 1990s. In January 1998, the CPUC released a
staff report initiating a project to assess the current market and
regulatory framework for California's natural gas industry. In July
1999, after hearings, the CPUC issued a decision stating which natural
gas regulatory changes it found most promising, encouraging parties to
submit settlements addressing those changes, and providing for further
hearings if necessary.
On December 11, 2001, the CPUC issued a decision adopting much of
a settlement that had been submitted in 2000 by SDG&E and
approximately 30 other parties representing all segments of the gas
industry in Southern California, but which was opposed by other
parties. The CPUC decision adopts the following provisions: a system
for shippers to hold firm, tradable rights to capacity on SoCalGas'
major gas transmission lines; new balancing services including
separate core and noncore balancing provisions; a reallocation among
customer classes of the cost of interstate pipeline capacity held by
SoCalGas and an unbundling of interstate capacity for gas marketers
serving core customers; and the elimination of noncore customers'
option to obtain gas supply service from SDG&E. The CPUC modified the
settlement to provide increased protection against the exercise of
market power by persons who would acquire rights on the SoCalGas gas
transmission system. The CPUC also rejected certain aspects of the
settlement that would have provided more options for natural gas
marketers serving core customers.
The CPUC is still considering the schedule for implementation of
these regulatory changes, but it is expected that most of the changes
will be implemented during 2002.
SDG&E believes the decision will make natural gas service more
reliable, efficient and better tailored to the desires of customers.
The decision is not expected to negatively impact SDG&E's earnings.

Performance-Based Regulation (PBR)
To promote efficient operations and improved productivity and to move
away from reasonableness reviews and disallowances, the CPUC has been
directing utilities to use PBR. PBR has replaced the general rate case
and certain other regulatory proceedings for SDG&E. Under PBR,
regulators require future income potential to be tied to achieving or
exceeding specific performance and productivity goals, as well as cost
reductions, rather than relying solely on expanding utility plant in a
market where a utility already has a highly developed infrastructure.
In April 2001, SDG&E filed its 2000 PBR report with the CPUC. For
2000, SDG&E exceeded all six performance indicator benchmarks,
resulting in a request for a total net reward of $11.7 million. The
CPUC has not yet approved this report and these awards have not been
recorded. In addition, SDG&E achieved an actual 2000 rate of return
(applicable only to electric distribution and natural gas
transportation) of 8.74 percent, which is below the authorized 8.75
percent. This results in no sharing of earnings in 2000 under the PBR
sharing mechanism (as described below).
SDG&E's PBR mechanism was to have been in effect through December
31, 2002, at which time the mechanism was to be updated. That update
was to include, among other things, a reexamination of SDG&E's
reasonable costs of operation to be allowed in rates. The PBR and Cost
of Service (COS) cases for SDG&E were both due to be filed on December
21, 2001. However, SDG&E's PBR/COS cases were delayed by an October
10, 2001 CPUC decision such that the resulting rates would be
effective in 2004 instead of 2003. The decision also denies SDG&E's
request to continue equal sharing between ratepayers and shareholders
of the estimated savings for the merger discussed in Note 1 and,
instead, orders that all of the estimated 2003 merger savings go to
ratepayers. The portion to be refunded to electric ratepayers was
credited to the TCBA during the fourth quarter of 2001, based on the
NPV in 2001 of the savings for 2003. Merger savings related to 2001
and 2002 also were credited. The combined NPV was $39 million. Merger
savings allocable to gas ratepayers will be refunded through once-a-
year bill credits, as has been the case.
Key elements of the current mechanisms include an annual indexing
mechanism that adjusts rates by the inflation rate less a productivity
factor and other adjustments to accommodate major unanticipated
events, a sharing mechanism with customers that applies to earnings
that exceed the authorized rate of return on rate base, rate refunds
to customers if service quality deteriorates or awards if service
quality exceeds set standards, and a change in authorized rate of
return and customer rates if interest rates change by more than a
specified amount. The rate change is triggered by a six-month trailing
average and a 100-basis-point change in interest rates. If these
events occur, there would be an automatic adjustment of rates for the
change in the cost of capital according to a formula which applies a
percentage of the change to various capital components.

Demand Side Management Awards
In recent years, the IOUs have participated in a CPUC program whereby
they could earn awards for operating and/or administering energy-
conservation efforts involving their retail customers. SDG&E has
participated in these programs and has consistently achieved
significant earnings therefrom. As part of the CPUC's review of the
program, a draft decision is proposing that the program be reduced in
scope and that award potentials for the IOUs be eliminated. An
alternate proposal would maintain the award concept, but the potential
awards would probably be reduced. The CPUC is scheduled to review both
proposals at its March 21, 2002 meeting.

Biennial Cost Allocation Proceeding(BCAP)
Rates to recover the changes in the cost of natural gas transportation
services are determined in the BCAP. The BCAP adjusts rates to reflect
variances in customer demand from estimates previously used in
establishing customer natural gas transportation rates. The mechanism
substantially eliminates the effect on income of variances in market
demand and natural gas transportation costs. SDG&E filed its 2003 BCAP
on October 5, 2001.
On April 20, 2000, the CPUC issued a decision on the 1999 BCAP,
adopting overall decreases in natural gas revenues of $37 million for
SDG&E for transportation rates effective June 1, 2000. Since the
decreases reflect anticipated changes in corresponding costs, they
have no effect on net income.

Cost of Capital
In June 1999, the CPUC adopted a 10.6 percent return on common equity
(ROE) and an 8.75 percent return on rate base (ROR) for SDG&E's
electric distribution and natural gas businesses. These rates remain
in effect through 2002. The electric-transmission cost of capital is
determined under a separate FERC proceeding. SDG&E is required to file
an application by May 8, 2002, addressing ROE, ROR and capital
structure for 2003. The application will, among other things, consider
the recent and ongoing financial impacts on SDG&E of electric industry
restructuring.

Utility Integration
On September 20, 2001 the CPUC approved Sempra Energy's request to
integrate the management teams of SDG&E and SoCalGas. The decision
retains the separate identities of each utility and is not a merger.
Instead, utility integration is a reorganization that consolidates
senior management functions of the two utilities and returns to the
utilities a significant portion of shared support services currently
provided by Sempra Energy's centralized corporate center. Once
implementation is completed, the integration is expected to result in
more efficient and effective operations.
In a related development, a CPUC draft decision would allow SDG&E
and SoCalGas to combine their natural gas procurement activities. The
CPUC is scheduled to act on the draft decision at its April 4, 2002
meeting.

CPUC Investigation of Energy-Utility Holding Companies
The CPUC has initiated an investigation into the relationship between
California's IOUs and their parent holding companies. Among the
matters to be considered in the investigation are utility dividend
policies and practices and obligations of the holding companies to
provide financial support for utility operations under the agreements
with the CPUC permitting the formation of the holding companies. On
January 11, 2002, the CPUC issued a decision to clarify under what
circumstances, if any, a holding company would be required to provide
financial support to its utility subsidiaries. The CPUC broadly
determined that it would require the holding company to provide cash
to a utility subsidiary to cover its operating expenses and working
capital to the extent they are not adequately funded through retail
rates. This would be in addition to the requirement of holding
companies to cover their utility subsidiaries' capital requirement, as
the IOUs have previously acknowledged in connection with the holding
companies' formations. On January 14, 2002, the CPUC ruled on
jurisdictional issues, deciding that the CPUC had jurisdiction to
create the holding company system and, therefore, retains jurisdiction
to enforce conditions to which the holding companies had agreed. The
company has filed to request rehearing on the issues.

NOTE 14. QUARTERLY FINANCIAL DATA (Unaudited)

Quarter ended
-----------------------------------------------------
Dollars in millions March 31 June 30 September 30 December 31
- ----------------------------------------------------------------------------------

2001
Operating revenues $ 1,129 $ 462 $ 333 $ 389
Operating expenses 1,056 405 271 362
---------------------------------------------------
Operating income $ 73 $ 57 $ 62 $ 27
---------------------------------------------------
Net income $ 54 $ 38 $ 45 $ 46
Dividends on preferred stock 2 1 2 1
---------------------------------------------------
Earnings applicable
to common shares $ 52 $ 37 $ 43 $ 45
===================================================
2000
Operating revenues $ 471 $ 574 $ 731 $ 895
Operating expenses 389 505 698 844
---------------------------------------------------
Operating income $ 82 $ 69 $ 33 $ 51
---------------------------------------------------
Net income $ 54 $ 41 $ 17 $ 39
Dividends on preferred stock 2 1 2 1
---------------------------------------------------
Earnings applicable
to common shares $ 52 $ 40 $ 15 $ 38
===================================================
The sums of the quarterly amounts do not necessarily equal the annual totals due to
rounding. Reclassifications have been made to certain of the amounts since they were
presented in the Quarterly Reports on Form 10-Q.

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

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information required on Identification of Directors is incorporated
by reference from "Election of Directors" in the Information Statement
prepared for the May 2002 annual meeting of shareholders. The
information required on the company's executive officers is provided
below.

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

Edwin A. Guiles 52 Chairman and Chief Executive Officer

Debra L. Reed 45 President and Chief Financial Officer

James P. Avery 45 Senior Vice President, Electric
Transmission

Steven D. Davis 45 Senior Vice President, Customer
Service and External Relations
Terry M. Fleskes 45 Vice President and Controller

Margot A. Kyd 48 Senior Vice President, Corporate
Business Solutions

Roy M. Rawlings 57 Senior Vice President, Distribution
Operations

William L. Reed 49 Senior Vice President, Regulatory
Affairs

Lee M. Stewart 56 Senior Vice President, Gas
Transmission

* As of December 31, 2001.

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

ITEM 11. EXECUTIVE COMPENSATION

The information required by Item 11 is incorporated by reference from
"Election of Directors" and "Executive Compensation" in the
Information Statement prepared for the May 2002 annual meeting of
shareholders.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT

The information required by Item 12 is incorporated by reference from
"Election of Directors" in the Information Statement prepared for the
May 2002 annual meeting of shareholders.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None.

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM
8-K

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

1. Financial statements
Page in
This Report
Independent Auditors' Report . . . . . . . . . . . . . . 31

Statements of Consolidated Income for the years
ended December 31, 2001, 2000 and 1999 . . . . . . . . 32

Consolidated Balance Sheets at December 31,
2001 and 2000. . . . . . . . . . . . . . . . . . . . . 33

Statements of Consolidated Cash Flows for the
years ended December 31, 2001, 2000 and 1999 . . . . . 35

Statements of Consolidated Changes in
Shareholders' Equity for the years ended
December 31, 2001, 2000 and 1999 . . . . . . . . . . . 36

Notes to Consolidated Financial Statements . . . . . . . 37

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

3. Exhibits
See Exhibit Index on page 70 of this report.

(b) Reports on Form 8-K
The following reports on Form 8-K were filed after September 30, 2001:

None

INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement
Numbers 33-45599, 33-52834, 333-52150, and 33-49837 on Form S-3 of our
report dated February 4, 2002 (February 21, 2002 as to Note 12),
appearing in the Annual Report on Form 10-K of San Diego Gas and
Electric Company for the year ended December 31, 2001.

/S/ DELOITTE & TOUCHE LLP

San Diego, California
March 15, 2002

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.

Name/Title Signature Date

Principal Executive Officer:
Edwin A. Guiles
Chairman and
Chief Executive Officer /s/ Edwin A. Guiles March 7, 2002

Principal Financial Officer:
Debra L. Reed
President and
Chief Financial Officer /s/ Debra L. Reed March 7, 2002

Principal Accounting Officer:
Terry M. Fleskes
Vice President and
Controller /s/ Terry M. Fleskes March 7, 2002

Directors:
Edwin A. Guiles
Chairman /s/ Edwin A. Guiles March 7, 2002

Debra L. Reed, Director /s/ Debra L. Reed March 7, 2002

Frank H. Ault, Director /s/ Frank H. Ault March 7, 2002

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

Exhibit 1 -- Underwriting Agreements

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

Exhibit 3 -- Bylaws and Articles of Incorporation

Bylaws
3.01 Restated Bylaws of San Diego Gas & Electric as of November 6,
2001.

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

Exhibit 4 -- Instruments Defining the Rights of Security Holders,
Including Indentures
The Company agrees to furnish a copy of each such instrument to the
Commission upon request.

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

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

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

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

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

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

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

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

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

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

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

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

10.07 Sempra Energy Supplemental Executive Retirement Plan as amended
and restated effective July 1, 1998 (1998 Sempra Energy Form
10-K Exhibit 10.09).

10.08 Sempra Energy Executive Incentive Plan effective June 1, 1998
(1998 Sempra Energy Form 10-K Exhibit 10.11).

10.09 Sempra Energy Executive Deferred Compensation Agreement
Effective June 1, 1998(1998 Sempra Energy Form 10-K Exhibit
10.12).

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

10.11 Supplemental Executive Retirement Plan restated as of
July 1, 1994 (1994 SDG&E Form 10-K Exhibit 10.14).

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

10.13 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).

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

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

10.16 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).

10.17 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).

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

10.19 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).

10.20 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).

10.21 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).

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

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

10.24 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).

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

10.26 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 10.24 herein)(1994 SDG&E Form 10-K Exhibit 10.57).

10.27 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 10.24 herein)(1996 Form 10-K Exhibit 10.59).

10.28 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 10.24 herein)(1996 Form 10-K Exhibit 10.60).

10.29 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 10.24 herein)(1999 Form 10-K Exhibit 10.26).

10.30 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 10.24 herein)(1999 Form 10-K Exhibit 10.27).

10.31 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).

10.32 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 10.31 herein)(1996 Form 10-K Exhibit 10.62).

10.33 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 10.31 herein)(1996 Form 10-K Exhibit 10.63).

10.34 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 10.31 herein)(1999 Form 10-K Exhibit 10.31).

10.35 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 10.31 herein)(1999 Form 10-K Exhibit 10.32).

10.36 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).

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

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

10.39 Master Services Contract, Schedule J, Transaction Based Storage
Service Agreement dated April 1, 2001 and expiring March 31,
2002 between San Diego Gas & Electric Company and Southern
California Gas Company.

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

10.41 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).

10.42 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).

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

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

Exhibit 12 -- Statement Re: Computation Of Ratios
12.01 Computation of Ratio of Earnings to Combined Fixed Charges
and Preferred Stock Dividends for the years ended December
31, 2001, 2000, 1999, 1998 and 1997.

Exhibit 21 - Subsidiaries

21.01 Schedule of Subsidiaries at December 31, 2001.

Exhibit 23 - Independent Auditors' Consent, page 68.

GLOSSARY

AB 1 A California Assembly bill authorizing the
California Department of Water Resources to
purchase energy for California consumers.

AB 43X A California Assembly bill to extend AB265 to
include large consumers.
AB 265 California Assembly Bill 265 (AB 265)imposed a
rate ceiling of 6.5 cents/kWh

AB 1421 A California Assembly bill requiring that
natural gas utilities provide bundled basic
gas service to certain customers.

AB 1890 A California Assembly bill restructuring the
electric energy law in California.

AFUDC Allowance for Funds Used During Construction

BCAP Biennial Cost Allocation Proceeding

Bcf One Billion Cubic Feet (of natural gas)

CEC California Energy Commission

COS Cost of Service

CPUC California Public Utilities Commission

DOE Department of Energy

DTSC Department of Toxic Substances Control

DWR Department of Water Resources

Edison Southern California Edison Company

EMFs Electric and Magnetic Fields

Enova Enova Corporation

FASB Financial Accounting Standards Board

FERC Federal Energy Regulatory Commission

Intertie Pacific Intertie

IOUs Investor-Owned Utilities

ISO Independent System Operator

kWh Kilowatt Hour

LIFO Last in first out inventory

mmbtu Million British Thermal Units (of natural gas)

MOU Memorandum of Understanding

mW Megawatt

NRC Nuclear Regulatory Commission

Parent Enova Corporation

PBR Performance-Based Ratemaking/Regulation

PIER Public Interest Energy Research

PE Pacific Enterprises

PG&E Pacific Gas and Electric Company

PGE Portland General Electric Company

PRP Potentially Responsible Party

PX Power Exchange

QFs Qualifying Facilities

ROE Return on Equity

ROR Rate of Return

SDG&E San Diego Gas & Electric Company

SEC Securities and Exchange Commission

SFAS Statement of Financial Accounting Standards

SoCalGas Southern California Gas Company

SONGS San Onofre Nuclear Generating Station

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

TCBA Transition Cost Balancing Account

UEG Utility Electric Generation

VaR Value at Risk

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