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

Back to GetFilings.com

SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[X] Annual report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the fiscal year ended December 31, 2001
--------------------
OR
[ ] Transition report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934 for the transition period from
to
- ------ -------
SAN DIEGO GAS & ELECTRIC COMPANY
- ---------------------------------------------------------------------
(Exact name of registrant as specified in its charter)

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

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

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

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

Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months and (2) has been
subject to such filing requirements for the past 90 days.
Yes [ X ] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant's knowledge, in definitive proxy
or information statements incorporated by reference in Part III of
this Form 10-K or any amendment to this Form 10-K. [ X ]

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

Long-Term Contracts with Other Utilities:

Portland General
Electric (PGE) December 2013 84 Coal
------
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
------
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