SEMPRA ENERGY - 10-K Annual Report

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

CALIFORNIA 1-14201 33-0732627
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(State of incorporation (Commission (I.R.S. Employer
or organization) File Number) Identification No.)

101 ASH STREET, SAN DIEGO, CALIFORNIA 92101
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(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code (619)696-2000
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SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

Name of each exchange
Title of each class on which registered
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Common Stock, Without Par Value New York and Pacific

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 33. Glossary on page 40.

Aggregate market value of the voting stock held by non-affiliates
of the registrant as of February 28, 2002 was $4.6 billion.

Registrant's common stock outstanding as of February 28, 2002 was
205,057,502 shares.

DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the 2001 Annual Report to Shareholders are incorporated
by reference into Parts I, II, and IV.

Portions of the Proxy 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 . . . . . . . . . . . . . . . . . . . . . . . 4
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . .23
Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . .24
Item 4. Submission of Matters to a Vote of Security Holders. .24

PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . .25
Item 6. Selected Financial Data. . . . . . . . . . . . . . . .25
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . .25
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk . . . . . . . . . . . . . . . . .25
Item 8. Financial Statements and Supplementary Data. . . . . .26
Item 9. Changes In and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . .26

PART III
Item 10. Directors and Executive Officers of the Registrant . .26
Item 11. Executive Compensation . . . . . . . . . . . . . . . .27
Item 12. Security Ownership of Certain Beneficial Owners
and Management. . . . . . . . . . . . . . . . . . .27
Item 13. Certain Relationships and Related Transactions . . . .27

PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . .27

Independent Auditors' Consent and Report on Schedule. . . . . .29

Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . .32

Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . .33

Glossary. . . . . . . . . . . . . . . . . . . . . . . . . . . .40

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 Sempra Energy and its subsidiaries (the company) is
given in "Management's Discussion and Analysis of Financial Condition
and Results of Operations" of the 2001 Annual Report to Shareholders,
which is incorporated by reference.

GOVERNMENT REGULATION

The most significant government regulation affecting Sempra Energy is
that affecting its utility subsidiaries, which is discussed below.
Other subsidiaries are also subject to governmental regulation.

Local Regulation
Southern California Gas Company (SoCalGas) has gas franchises with the
239 legal jurisdictions in its service territory. These franchises
allow SoCalGas to locate facilities for the transmission and
distribution of natural gas in the streets and other public places.
Some franchises have fixed terms, such as that for the city of Los
Angeles, which expires in 2012. Most of the franchises do not have
fixed terms and continue indefinitely. The range of expiration dates
for the franchises with definite terms is 2003 to 2048.

San Diego Gas and Electric (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 and SoCalGas' 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 and SoCalGas' 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.

International Utility Regulation
The company's consolidated and unconsolidated affiliates have
locations in Argentina, Canada, Chile, Mexico, Peru and Uruguay. These
operations are subject to the local, federal and other regulations of
the countries in which they are located.

Other Regulation
As a trading company, Sempra Energy Trading has locations and
operations in North America, Europe, Asia and South America, and is
subject to regulation as to its operations and its financial position.
Other subsidiaries are also subject to varying amounts of regulation
by various governments, including other states in the United States.

Licenses and Permits
SoCalGas and SDG&E obtain a number of permits, authorizations and
licenses in connection with the transmission and distribution of
natural gas. In addition, SDG&E obtains a number of permits,
authorizations and licenses in connection with the transmission and
distribution of electricity. Both require periodic renewal, which
results in continuing regulation by the granting agency. The company's
unregulated affiliates are also required to obtain permits,
authorizations and licenses in the normal course of business.

Other regulatory matters are described in Notes 14 and 15 of the 2001
Annual Report to Shareholders, which is incorporated by reference.

SOURCES OF REVENUE
Industry segment information is contained in "Management's Discussion
and Analysis of Financial Condition and Results of Operations" and in
Note 16 of the notes to Consolidated Financial Statements of the 2001
Annual Report to Shareholders, which is incorporated by reference.
Various information concerning revenue and revenue recognition is
provided in Note 2 of the notes to Consolidated Financial Statements
of the 2001 Annual Report to Shareholders, which is incorporated by
reference.

NATURAL GAS OPERATIONS
The company purchases, sells, distributes, stores and transports
natural gas. SoCalGas owns and operates a natural gas distribution,
transmission and storage system that supplies natural gas to 5.1
million end-use customers throughout a 23,000-square-mile service
territory from central California to the Mexican border. SoCalGas also
transports gas to about 1,300 utility electric generation (UEG),
wholesale, large commercial, industrial and off-system (outside the
company's normal service territory) customers. SDG&E purchases and
distributes natural gas to 774,000 end-use customers throughout the
western portion of San Diego county. SDG&E also transports gas to over
1,000 customers who procure their gas from other sources. On a smaller
scale, Sempra Energy International (SEI) operates natural gas
distribution systems in Mexico through 60 percent, 95 percent and 100
percent ownership of companies operating in Mexicali, Chihuahua and La
Laguna Durango, respectively. SEI also has a 10-year contract to
deliver up to 300 million cubic feet per day of natural gas to a power
plant in Rosarito, Mexico. These North American operations are
included in the following discussion of the company's natural gas
operations. SEI also has interests in natural gas operations in South
America which are not consolidated and, therefore, are not included in
these discussions. Additional information on international operations
is provided in "Management's Discussion and Analysis of Financial
Condition and Results of Operations."

In December 1999, Sempra Atlantic Gas (SAG), a subsidiary of SEI, was
awarded a 25-year franchise by the provincial government of Nova
Scotia to build and operate a natural gas distribution system. In
September 2001, due to new conditions required by the government of
Nova Scotia, SAG notified the government that it intended to surrender
its natural gas distribution franchise.

Supplies of Natural Gas
The company 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. SoCalGas and SDG&E transport gas under long-term firm pipeline
capacity agreements that provide for annual reservation charges, which
are recovered in rates. SoCalGas has commitments for firm pipeline
capacity under contracts with pipeline companies that expire at
various dates through 2006. SDG&E has long-term natural gas
transportation contracts with various interstate pipelines which
expire on various dates between 2003 and 2023.

Most of the natural gas purchased and delivered by the company is
produced outside of California. These supplies are delivered to the
company's intrastate transmission system 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.

The following table shows the sources of natural gas deliveries for
SoCalGas and SDG&E (collectively, the California utilities) from 1997
through 2001:

* Fixed charges primarily include pipeline demand charges, take or pay
settlement costs and other direct-billed amounts allocated over the
quantities delivered by the interstate pipelines serving the
California utilities.

Market-sensitive natural gas supplies (supplies purchased on the spot
market as well as under longer-term contracts, ranging from one month
to two years, based on spot prices) accounted for 100 percent 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.

During 2001, the California utilities delivered 1,131 bcf of natural
gas through their systems. Approximately 64 percent of these
deliveries were customer-owned natural gas for which the California
utilities provided transportation services. The remaining natural gas
deliveries were purchased by the California utilities and resold to
customers. The California utilities estimate that sufficient natural
gas supplies will be available to meet the requirements of their
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. Noncore customers consist primarily of utility electric
generation (UEG), wholesale, large commercial, industrial and off-
system (outside the company's normal service territory) customers. Of
the 5.9 million customer meters in the California utilities' service
territories, only 1,400 serve the noncore market.

Most core customers purchase natural gas directly from the California
utilities. Core customers are permitted to aggregate their natural gas
requirement and, up to a limit of 10 percent of each 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
SD&GE 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 from other sources, such as brokers or producers. Noncore
customers will also have to make arrangements to deliver their
purchases to the California utilities' receipt points for delivery
through the California utilities' transmission and distribution
system.

In 2001, for SoCalGas, 87 percent of the CPUC-authorized natural gas
margin was allocated to the core customers, with 13 percent allocated
to the noncore customers. In 2001, for SDG&E, 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 California utilities generally earn the same
margin whether they buy the gas and sell it to the customer or
transport natural gas already owned by the customer.

SoCalGas also provides natural gas storage services for noncore and
off-system customers on a bid and negotiated contract basis. The
storage service program provides opportunities for customers to store
natural gas on an "as available" basis, usually during the summer to
reduce winter purchases when natural gas costs are generally higher.
As of December 31, 2001, SoCalGas was storing approximately 35 bcf of
customer-owned gas.

Demand for Natural Gas
Natural gas is a principal energy source for residential, commercial,
industrial and UEG customers. Natural gas competes with electricity
for residential and commercial cooking, water heating, space heating
and clothes drying, and with other fuels for large industrial,
commercial and UEG uses. Growth in the natural-gas markets is largely
dependent upon the health and expansion of the southern California
economy. The California utilities added approximately 71,000 and
82,000 new customer meters in 2001 and 2000, respectively,
representing growth rates of 1.2 percent and 1.4 percent,
respectively. The California utilities expect that their growth rate
for 2002 will approximate that of 2001.

During 2001, 99 percent of residential energy customers in SoCalGas'
service area used natural gas for water heating, 96 percent for space
heating, 76 percent for cooking and 55 percent for clothes drying. In
SDG&E's service area, 90 percent of residential energy customers 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 1,400, they accounted for approximately 8 percent of the
authorized natural gas revenues and 63 percent of total natural gas
volumes. External factors such as weather, the price of electricity,
electric deregulation, the use of hydroelectric power, competing
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 California utilities' 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 California
utilities' 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 13, 14 and 15 of the notes to Consolidated Financial Statements
of the 2001 Annual Report to Shareholders, which is incorporated by
reference.

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 13 and 14 of the notes to Consolidated Financial Statements of
the 2001 Annual Report to Shareholders, which is incorporated by
reference.

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 14 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 6, 13 and 14 of the notes to
Consolidated Financial Statements of the 2001 Annual Report to
Shareholders, which is incorporated by reference.

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
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Total 84
======
Other Contracts:

Qualifying Facilities (QFs) --

Applied Energy December 2019 102 Cogeneration

Yuma Cogeneration June 2024 50 Cogeneration

Goal Line Limited
Partnership December 2025 50 Cogeneration

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

Various (3) December 2003 125 System Supply
------
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 13 of the
notes to Consolidated Financial Statements of the 2001 Annual Report
to Shareholders, which is incorporated by reference.

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."

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 13 of the notes to Consolidated Financial Statements of the 2001
Annual Report to Shareholders, which is incorporated by reference.

SEMPRA ENERGY TRADING

Sempra Energy Trading (SET), a leading marketer of natural gas, power,
petroleum and other commodities headquartered in Stamford,
Connecticut, was acquired on December 31, 1997. SET is a full-service
energy trading company and also has offices in Europe, Canada and
Asia.

In February 2002, SET acquired London-based Enron Metals Limited, the
leading metals trader on the London Metals Exchange, for $145 million
and changed its name to Sempra Metals Services Corp. It will be
operated as part of the SET business.

For the year ended December 31, 2001, SET recorded net income of $196
million, compared to net income of $155 million and $19 million in
2000 and 1999, respectively. The increase in net income in 2001
compared to 2000 was primarily due to high volatility in energy
markets during the first half of 2001 and an increase in trading
volumes, partially offset by reduced profitability in Europe. The
increase in net income for 2000 compared to 1999 was due to increased
volatility in the U.S energy markets and higher earnings from European
crude oil trading.

Additional information concerning the company's trading operations is
provided under "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and in Notes 2 and 10 of the
notes to Consolidated Financial Statements of the 2001 Annual Report
to Shareholders, which is incorporated by reference.

SEMPRA ENERGY INTERNATIONAL

SEI develops, operates and invests in energy-infrastructure systems.
SEI has interests in natural gas and/or electric transmission and
distribution projects in Argentina, Chile, Mexico, Peru and the
eastern United States, and is pursuing other projects, primarily in
Mexico.

In October 2001, SEI and CMS Energy Corporation announced plans to
jointly develop an LNG receiving facility on a 300-acre site along the
Pacific coast near Ensenada, Mexico. The joint venture will develop
the $400 million facility and related port infrastructure, which will
provide one billion cubic feet per day of natural gas. SEI has entered
into a memorandum of understanding with a Bolivian consortium for the
supply of LNG to the facility. Commercial operation of the facility is
scheduled to begin in late 2005.

In June 2000, SEI and PG&E Corporation announced an agreement to
construct the North Baja Pipeline, a $230 million, 215-mile natural
gas pipeline which will extend from Arizona to the Rosarito Pipeline
south of Tijuana. The agreement calls for SEI to construct, own and
operate the 135-mile segment of the pipeline within Mexico, and PG&E
Corporation to construct, own and operate the 80-mile segment within
the United States. The 30-inch pipeline will deliver 500 million cubic
feet per day of natural gas to new generation facilities in Baja
California, including SER's Termoelectrica de Mexicali power plant
discussed below. SEI has begun construction of the pipeline, with
completion anticipated in the summer of 2002.

In December 1999, SAG was awarded a 25-year franchise by the
government of Nova Scotia to build and operate a natural gas
distribution system. In September 2001, due to new conditions required
by the government of Nova Scotia, SAG notified the government that it
intended to surrender its natural gas distribution franchise. SAG
recorded an after-tax expense of $25 million related to the surrender
of the franchise.

Net income for international operations in 2001 was $25 million
compared to net income of $33 million and $2 million for 2000 and
1999, respectively. The decrease in net income for 2001 was primarily
due to SAG's surrender of the natural gas franchise in Nova Scotia,
partially offset by increased earnings at SEI's Latin American
subsidiaries. The increase in net income for 2000 was primarily due to
additional investments in South American subsidiaries and improved
operating results at existing South American investments.

Additional information concerning the company's international
operations is provided under "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and in Notes 2, 3 and
13 of the notes to Consolidated Financial Statements of the 2001
Annual Report to Shareholders, which is incorporated by reference.

SEMPRA ENERGY RESOURCES (SER)

SER develops power plants for the competitive market, and owns natural
gas storage, production and transportation assets. SER is planning to
develop 5,000 to 10,000 megawatts of generation within the next
decade, primarily in the southwestern United States.

In May 2001, SER entered into a ten-year agreement with the DWR to
supply up to 1,900 megawatts of power to the state. SER intends to
deliver most of this electricity from its projected portfolio of
plants in the western United States and Baja California, Mexico. Sales
under the contract comprise more than two-thirds of the projected
capacity of these facilities and the profits therefrom are significant
to the company's ability to increase its earnings. SER began providing
250 megawatts of discounted summer capacity to the DWR on June 1,
2001. This electricity was supplied through market purchases and SER's
share of the El Dorado generating facility. In accordance with the
contract, sales to the DWR ceased from October 1, 2001 through March
31, 2002, the period during which expected demands for energy are
lower due to cooler weather. Deliveries under the contract are
scheduled to recommence on April 1, 2002 (without discounting) and end
on September 30, 2011. Subsequent to the state's signing of this
contract and electricity-supply contracts with other vendors, various
state officials have contended that the rates called for by the
contracts are too high. The rates under the SER contract exceed
current spot-market prices for electricity, but are lower than those
prevailing at the time the contract was signed and are reflective of
rates needed to support new plant development. There have been
discussions between state representatives and SER and other suppliers
concerning possible renegotiation of the contracts. In February 2002,
the state requested the Federal Energy Regulatory Commission to
determine that the contracts do not provide just and reasonable rates,
and to abrogate or reform the contracts. The company believes that
SER's contract prices are just and reasonable, but has offered to
renegotiate certain aspects of the contract (which would not affect
the long-term profitability) in a manner mutually beneficial to SER
and the state.

In February 2001, the company announced plans to construct
Termoelectrica de Mexicali, a $350 million, 600-megawatt power plant
near Mexicali, Mexico. Fuel for the plant will be supplied via the
planned pipeline from Arizona to Tijuana referred to above. It is
anticipated that the electricity produced by the plant will be
exported for consumption in the United States via the 230,000-volt
transmission line which is also under construction. Construction of
the power plant began in the second half of 2001 with completion
scheduled for mid-2003.

In December 2000, SER obtained approval from the appropriate state
agencies to construct the Mesquite Power Plant. Located near Phoenix,
Arizona, Mesquite Power is a $700 million, 1200-megawatt project which
will provide electricity to wholesale energy markets in the Southwest
region. Ground was broken in March 2001, with project completion
anticipated in 2003. The project is being financed via the synthetic
lease agreement described in Note 13 of the notes to Consolidated
Financial Statements.

In December 2000, SER obtained approvals from the appropriate state
agencies to construct the Elk Hills Power Project, a $410 million 570-
megawatt power plant near Bakersfield, California. Elk Hills is being
developed in joint venture with Occidental Energy Ventures
Corporation.

In mid-2000, El Dorado Energy, a 50/50 partnership between SER and
Reliant Energy Power Generation, completed construction of a $280
million, 500-megawatt merchant power plant near Las Vegas, Nevada.

SER recorded a net loss of $27 million in 2001, compared to net income
of $29 million and $5 million in 2000 and 1999, respectively. The
decline in results for 2001 was due to the sale of electricity to the
State of California at a discounted price in the first phase of the
long-term contract described above and the successful operations of
the El Dorado power plant in 2000 when market prices for electricity
were higher than in 2001 or 1999.

Additional information concerning the SER's operations is provided
under "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and in Notes 2, 3 and 13 of the notes to
Consolidated Financial Statements of the 2001 Annual Report to
Shareholders, which is incorporated by reference.

OTHER OPERATIONS

Sempra Energy's retail energy services, concentrated primarily in
Sempra Energy Solutions (SES), provides integrated energy-related
products and services to commercial, industrial, government,
institutional and consumer markets. In August 2000, SES purchased
Connectiv Thermal Systems' 50-percent interests in Atlantic-Pacific
Las Vegas and Atlantic-Pacific Glendale for $40 million, thereby
acquiring full ownership of these companies. The retail energy
services' operations recorded net income of $2 million in 2001,
compared to net losses of $23 million and $11 million in 2000 and
1999, respectively. The increase in net income for 2001 is primarily
due to the sale of Energy America, a subsidiary selling electric
commodities to small consumers. The losses for 2000 and 1999 are
primarily attributable to start-up costs.

Additional information concerning the SES's operations is provided
under "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and in Notes 2, 3 and 10 of the notes to
Consolidated Financial Statements of the 2001 Annual Report to
Shareholders, which is incorporated by reference.

Sempra Energy Financial (SEF) invests as a limited partner in
affordable-housing properties. SEF's portfolio includes 1,300
properties throughout the United States, Puerto Rico and the Virgin
Islands. These investments are expected to provide income tax benefits
(primarily from income tax credits) over 10-year periods. SEF also
invests in alternative-fuel projects. SEF recorded net income of $28
million in each of 2001, 2000 and 1999. SEF's future investment policy
is dependent on the company's future income tax position.

RATES AND REGULATION--CALIFORNIA UTILITIES

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 14 of the
notes to Consolidated Financial Statements of the 2001 Annual Report
to Shareholders, which is incorporated by reference.

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 the California utilities
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 15 of the notes to Consolidated Financial Statements of the
2001 Annual Report to Shareholders, which is incorporated by
reference.

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 of the 2001 Annual Report to
Shareholders, which is incorporated by reference.

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 and, for SoCalGas, is subject to the
limitations of the Gas Cost Incentive Mechanism (GCIM) described
below. Additional information on the BCAP is provided in
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" and in Note 15 of the notes to Consolidated
Financial Statements of the 2001 Annual Report to Shareholders,
which is incorporated by reference.

Gas Cost Incentive Mechanism
The GCIM is a process SoCalGas uses to evaluate its natural gas
purchases, substantially replacing the previous process of
reasonableness reviews. Additional information on the GCIM is
provided in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and in Note 15 of the notes to
Consolidated Financial Statements of the 2001 Annual Report to
Shareholders, which is incorporated by reference.

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 the California utilities' cost
of capital is provided in "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and in Note 15 of
the notes to Consolidated Financial Statements of the 2001 Annual
Report to Shareholders, which is incorporated by reference.

ENVIRONMENTAL MATTERS

Discussions about environmental issues affecting the company are
included in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" of the 2001 Annual Report to
Shareholders, which is incorporated by reference. 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 the California
utilities 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, the California utilities and their
predecessors manufactured gas from coal or oil. The manufacturing
sites often have become contaminated with the hazardous residual
by-products of the process. SoCalGas has identified 42 former
manufactured-gas plant sites at which it (together with other users
as to 21 of these sites) may have cleanup obligations. As of
December 31, 2001, 18 of these sites have been remediated, of which
14 have received certification from the California Environmental
Protection Agency. Preliminary investigations, at a minimum, have
been completed on 41 of the sites. At December 31, 2001, SoCalGas'
estimated remaining investigation and remediation liability for all
of these sites is $54.5 million. SDG&E has identified three former
manufactured-gas plant sites. All three sites have been remediated
and closure letters received for all but one of the sites. At
December 31, 2001 estimated remaining remediation liability on
these sites is less than $0.2 million.

SDG&E sold its fossil-fuel generating facilities in 1999. As a part of
its due diligence for the sale, SDG&E conducted a thorough
environmental assessment of the facilities. Pursuant to the sale
agreements for such facilities, SDG&E and the buyers have apportioned
responsibility for such environmental conditions generally based on
contamination existing at the time of transfer and the cleanup level
necessary for the continued use of the sites as industrial sites.
While the sites are relatively clean, the assessments identified some
instances of significant contamination, principally resulting from
hydrocarbon releases, for which SDG&E has a cleanup obligation under
the agreement. Estimated costs to perform the necessary remediation
are $11 million. These costs were offset against the sales price for
the facilities, together with other appropriate costs, and the
remaining net proceeds were included in the calculation of customer
rates. Remediation of the plants commenced in early 2001. During 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.

The California utilities 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.

The company and certain subsidiaries have been named as potentially
responsible parties (PRPs) for two landfill sites and six
industrial waste disposal sites, from which releases have occurred,
as described below.

Remedial actions and negotiations with other PRPs and the United
States Environmental Protection Agency (EPA) have been in progress
since 1986 and 1993 for the two landfill sites. The company's share
of costs to remediate these sites is estimated to be $10.4 million
($0.7 million for the first site and $9.7 million for the second
site). Of this, $5.0 million has been spent since 1987 ($140,000 in
2001) and the company recently signed a Consent Decree to settle
and liquidate all remaining liabilities at the second site for $5.7
million.

In the early 1990s, the company was notified of hazards at two
industrial waste treatment facilities in the California communities
of Fresno and Carson, where the company had disposed of wastes.
During 2000, the company settled with the other PRPs at these sites
for $0.4 million and has no additional liability.

The company and 10 other entities have been named PRPs by the
Department of Toxic Substance Control (DTSC) as liable for any
required corrective action regarding contamination at an industrial
waste disposal site in Pico Rivera, California. DTSC has taken this
action because SDG&E and others sold used transformers to the
site's owner. SDG&E and the other PRPs have entered into a cost-
sharing agreement to provide funding for the implementation of a
consent order between DTSC and the site owner for the development
of a cleanup plan. SDG&E's interim share under the agreement is
10.1 percent, subject to adjustment based on ultimate
responsibility allocations. The total estimate for all PRPs is $3
million to $9 million. Since inception, SDG&E's share of the
cleanup expenses was $0.2 million, including $47,000 in 2001.

In December 1999, SoCalGas was notified that it is a PRP at a waste
treatment facility in Bakersfield, California. SoCalGas is working
with other PRPs in order to remove from the site certain liquid
wastes that threaten to be released. SoCalGas has reserved $0.8
million in contingent environmental liability for its share of site
cleanup. Amounts expended to date are $0.1 million, including
$11,000 in 2001.

In March 2000, SoCalGas was notified it is a PRP at a former
mercury recycling facility in Brisbane, California. Total potential
liability is estimated at $5,900. Settlement and payment to the
State of California is expected by mid-2002. Also in March 2000,
SoCalGas was sued in Federal District Court as a PRP in a waste oil
disposal site in Los Angeles. Plaintiffs alleged that SoCalGas had
transported various petroleum wastes to the site in the 1950s for
recycling. SoCalGas settled with plaintiffs in December 2000 for
$0.2 million.

At December 31, 2001, the company's estimated remaining
investigation and remediation liability related to hazardous waste
sites, including the manufactured gas sites, was $57 million, of
which 90 percent is authorized to be recovered through the
Hazardous Waste Collaborative mechanism. This estimated cost
excludes remediation costs associated with SDG&E's former fossil-
fuel power plants. The company believes that any costs not
ultimately recovered through rates, insurance or other means will
not have a material adverse effect on the company's consolidated
results of operations or financial position.

Estimated liabilities for environmental remediation are recorded
when amounts are probable and estimable. Amounts authorized to be
recovered in rates under the Hazardous Waste Collaborative
mechanism are recorded as a regulatory asset.

Electric and Magnetic Fields (EMFs)
Although scientists continue to research the possibility that
exposure to EMFs causes adverse health effects, science has not
demonstrated a cause-and-effect relationship between 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 now has less
significance to the company's operation, although that will change
as SER constructs more generating facilities.

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)
The SoCalGas RD&D portfolio is focused in five major areas:
operations, utilization systems, power generation, public interest and
transportation. Each of these activities provides benefits to
customers and society by providing more cost-effective, efficient
natural gas equipment with lower emissions, increased safety, and
reduced environmental mitigation and other operating costs. The CPUC
has authorized SoCalGas to recover its operating costs associated with
RD&D. SoCalGas' annual RD&D costs have averaged $7.5 million over the
past three years.

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

Employees of Registrant
As of December 31, 2001 the company had 11,511 employees, compared to
11,232 at December 31, 2000.

Wages
The California utilities employ over 9,000 persons. Field, technical
and most clerical employees at SoCalGas are represented by the Utility
Workers' Union of America or the International Chemical Workers'
Council. The collective bargaining agreement on wages, hours and
working conditions remains in effect through March 31, 2002.
Negotiations for a new agreement are currently in progress. Certain
employees at SDG&E are represented by the Local 465 International
Brotherhood of Electrical Workers. The current contract runs through
August 31, 2004.

ITEM 2. PROPERTIES

Electric Properties
SDG&E's generating capacity is described in "Electric Resources"
herein.

At December 31, 2001, SDG&E's electric transmission and distribution
facilities include substations, and overhead and underground lines.
The electric facilities are located in San Diego, Imperial county,
Orange county and 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
At December 31, 2001, the California utilities owned approximately
3,011 miles of transmission and storage pipeline, 53,069 miles of
distribution pipeline and 50,857 miles of service piping. It also
owned 12 transmission compressor stations and 6 underground storage
reservoirs, with a combined working capacity of 121.1 billion cubic
feet.

At December 31 2001, SEI's operations in Mexico included 750 miles of
distribution pipeline, 21 miles of transmission pipeline and 1
compressor station.

At December 31 2001, the company's two small natural gas utilities
located in the eastern United States owned approximately 122 miles of
transmission lines and 167 miles of distribution lines.

Other Properties
The 21-story corporate headquarters building at 101 Ash Street, San
Diego is occupied pursuant to a capital lease with an original term
through 2005. The lease has four separate five-year renewal options.

SoCalGas has a 15-percent limited partnership interest in a 52-story
office building in downtown Los Angeles. SoCalGas leases approximately
half of the building through 2011. The lease has six separate five-
year renewal options.

SDG&E occupies an office complex in San Diego pursuant to an operating
lease ending in 2007. The lease can be renewed for two five-year
periods.

The company owns or leases other offices, operating and maintenance
centers, shops, service facilities and equipment necessary in the
conduct of business.

At December 31, 2001, Sempra Energy had other projects under
construction, including 135 miles of natural gas pipeline and a 600-
megawatt power plant in Mexico, and other power plants under
construction in Arizona and California. For additional information,
see Note 13 of the Notes to Consolidated Financial Statements
incorporated by reference from Item 8 herein.

ITEM 3. LEGAL PROCEEDINGS

Except for the matters referred to in the financial statements
incorporated by reference in Item 8 or referred to elsewhere in
this Annual Report, the company is not party to, nor is its
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

Common stock of Sempra Energy is traded on the New York and Pacific
stock exchanges. At January 31, 2002, there were 70,000 registered
holders of the company's common stock and a total of 175,000 record
holders. The quarterly common stock information, required by Item 5
is included in the schedule of Quarterly Financial Data of the 2001
Annual Report to Shareholders, which is incorporated by reference.

ITEM 6. SELECTED FINANCIAL DATA

(a) Includes long-term debt due within one year.

This data should be read in conjunction with the Consolidated
Financial Statements and the notes to Consolidated Financial
Statements contained in the 2001 Annual Report to Shareholders, which
is incorporated by reference.

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

The information required by Item 7 is incorporated by reference
from pages 1 through 26 of the 2001 Annual Report to Shareholders.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information required by Item 7A is incorporated by reference
from pages 20 through 23 of the 2001 Annual Report to Shareholders.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required by Item 8 is incorporated by reference
from pages 31 through 83 of the 2001 Annual Report to Shareholders.
Item 14(a)1 includes a listing of financial statements included in
the 2001 Annual Report to Shareholders.

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

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

EXECUTIVE OFFICERS OF THE REGISTRANT
Name Age* Position
- ---------------------------------------------------------------------
Stephen L. Baum 60 Chairman, Chief Executive Officer and
President

Donald E. Felsinger 54 Group President, Sempra Energy Global
Enterprises

Edwin A. Guiles 52 Group President, Regulated Business
Units

John R. Light 60 Executive Vice President and General
Counsel

Neal E. Schmale 55 Executive Vice President and Chief
Financial Officer

Frank H. Ault 57 Senior Vice President and Controller

Darcel L. Hulse 54 Senior Vice President, International

Frederick E. John 55 Senior Vice President, External Affairs

Margot A. Kyd 48 Senior Vice President, Business Solutions

G. Joyce Rowland 47 Senior Vice President, Human Resources

* As of December 31, 2001.

Each Executive Officer has been an officer of the company or one of its
subsidiaries for more than five years, with the exception of Mssrs.
Hulse, Light and Schmale. Prior to joining the company in 1999, Mr.
Hulse was President of Unocal Asia-Pacific Ventures. Prior to joining
the company in 1998, Mr. Light was a partner in the law firm of Latham &
Watkins. Prior to joining the company in 1997, Mr. Schmale was Chief
Financial Officer of Unocal Corporation.

ITEM 11. EXECUTIVE COMPENSATION

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

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT

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

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
None.

PART IV

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

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

1. Financial statements
Page in
Annual Report*

Statement of Management Responsibility for
Consolidated Financial Statements. . . . . . . . . . . 28

Independent Auditors' Report . . . . . . . . . . . . . . 29

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

Consolidated Balance Sheets at December 31,
2001 and 2000. . . . . . . . . . . . . . . . . . . . . 32

Statements of Consolidated Cash Flows for the
years ended December 31, 2001, 2000 and 1999 . . . . . 34

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

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

*Incorporated by reference from the indicated pages of the 2001
Annual Report to Shareholders.

2. Financial statement schedules

The following document may be found in this report at the indicated
page number.

Schedule I--Condensed Financial Information of Parent. . 30

Any other schedules for which provision is made in Regulation S-X
are not required under the instructions contained therein or are
inapplicable.

3. Exhibits

See Exhibit Index on page 33 of this report.

(b) Reports on Form 8-K

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

Current Report on Form 8-K filed October 26, 2001, filing as an
exhibit Sempra Energy's press release of October 25, 2001,
giving the financial results for the three-month period ended
September 30, 2001.

Current Report on Form 8-K filed January 28, 2002, filing as an
exhibit Sempra Energy's press release of January 24, 2002,
giving the financial results for the three-month period ended
December 31, 2001.

INDEPENDENT AUDITORS' CONSENT AND REPORT ON SCHEDULE

To the Board of Directors and Shareholders of Sempra Energy:

We consent to the incorporation by reference in Registration
Statement Numbers 333-51309, 333-52192, 333-77843 and 333-70640 on
Form S-3 and Registration Statement Numbers 333-56161, 333-50806
and 333-49732 on Form S-8 of Sempra Energy of our report dated
February 4, 2002 (February 21, 2002 as to Note 14 and March 5,
2002 as to Note 15), incorporated by reference in this Annual
Report on Form 10-K of Sempra Energy for the year ended December
31, 2001.

Our audits of the financial statements referred to in our
aforementioned report also included the financial statement
schedule of Sempra Energy, listed in Item 14. This financial
statement schedule is the responsibility of the company's
management. Our responsibility is to express an opinion based on
our audits. In our opinion, such financial statement schedule,
when considered in relation to the basic financial statements
taken as a whole, presents fairly in all material respects the
information set forth therein.

/S/ DELOITTE & TOUCHE LLP

San Diego, California
March 15, 2002

Schedule I -- CONDENSED FINANCIAL INFORMATION OF PARENT

SEMPRA ENERGY

Condensed Statement of Income
(Dollars in millions, except per share amounts)

Condensed Balance Sheet
(Dollars in millions)

SEMPRA ENERGY

Condensed Statement of Cash Flows
(Dollars in millions)

SIGNATURES

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

SEMPRA ENERGY

By: /s/ Stephen L. Baum
.
Stephen L. Baum
Chairman, Chief Executive Officer
and President

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

Name/Title Signature Date

EXHIBIT INDEX

The Forms 8, 8-B/A, 8-K, S-4, 10-K and 10-Q referred to herein were filed
under Commission File Number 1-14201 (Sempra Energy), Commission File Number
1-40 (Pacific Enterprises), Commission File Number 1-3779 (San Diego Gas &
Electric), Commission File Number 1-1402 (Southern California Gas Company),
Commission File Number 1-11439 (Enova Corporation) and/or Commission File
Number 333-30761 (SDG&E Funding LLC).

3.a The following exhibits relate to Sempra Energy and its subsidiaries

Exhibit 1 -- Underwriting Agreements

Enova Corporation and San Diego Gas & Electric Company
- ------------------------------------------------------
1.01 Underwriting Agreement dated December 4, 1997 (Incorporated by
reference from Form 8-K filed by SDG&E Funding LLC on
December 23, 1997 (Exhibit 1.1)).

Exhibit 3 -- Bylaws and Articles of Incorporation

Bylaws

Sempra Energy
- -------------
3.01 Amended and Restated Bylaws of Sempra Energy effective May 26, 1998
(Incorporated by reference from the Registration Statement on Form
S-8 Sempra Energy Registration No. 333-56161 dated June 5, 1998
(Exhibit 3.2)).

Articles of Incorporation

Sempra Energy
- -------------
3.02 Amended and Restated Articles of Incorporation of Sempra Energy
(Incorporated by reference to the Registration Statement on Form S-3
File No. 333-51309 dated April 29, 1998, Exhibit 3.1).

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

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

Enova Corporation and San Diego Gas & Electric Company
- ------------------------------------------------------

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

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

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

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

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

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

Pacific Enterprises and Southern California Gas
- -----------------------------------------------

4.07 First Mortgage Indenture of Southern California Gas Company to
American Trust Company dated as of October 1, 1940 (Registration
Statement No. 2-4504 filed by Southern California Gas Company on
September 16, 1940; Exhibit B-4).

4.08 Supplemental Indenture of Southern California Gas Company to American
Trust Company dated as of July 1, 1947 (Registration Statement No. 2-
7072 filed by Southern California Gas Company on March 15, 1947;
Exhibit B-5).

4.09 Supplemental Indenture of Southern California Gas Company to American
Trust Company dated as of August 1, 1955 (Registration Statement No.
2-11997 filed by Pacific Lighting Corporation on October 26, 1955;
Exhibit 4.07).

4.10 Supplemental Indenture of Southern California Gas Company to American
Trust Company dated as of June 1, 1956 (Registration Statement No.
2-12456 filed by Southern California Gas Company on April 23, 1956;
Exhibit 2.08).

4.11 Supplemental Indenture of Southern California Gas Company to Wells
Fargo Bank, National Association dated as of August 1, 1972
(Registration Statement No. 2-59832 filed by Southern California Gas
Company on September 6, 1977; Exhibit 2.19).

4.12 Supplemental Indenture of Southern California Gas Company to Wells
Fargo Bank, National Association dated as of May 1, 1976 (Registration
Statement No. 2-56034 filed by Southern California Gas Company on
April 14, 1976; Exhibit 2.20).

4.13 Supplemental Indenture of Southern California Gas Company to Wells
Fargo Bank, National Association dated as of September 15, 1981
(Pacific Enterprises 1981 Form 10-K; Exhibit 4.25).

4.14 Supplemental Indenture of Southern California Gas Company to
Manufacturers Hanover Trust Company of California, successor to Wells
Fargo Bank, National Association, and Crocker National Bank as
Successor Trustee dated as of May 18, 1984 (Southern California Gas
Company 1984 Form 10-K; Exhibit 4.29).

4.15 Supplemental Indenture of Southern California Gas Company to Bankers
Trust Company of California, N.A., successor to Wells Fargo Bank,
National Association dated as of January 15, 1988
(Pacific Enterprises 1987 Form 10-K; Exhibit 4.11).

4.16 Supplemental Indenture of Southern California Gas Company to First
Trust of California, National Association, successor to Bankers Trust
Company of California, N.A. dated as of August 15, 1992 (Registration
Statement No. 33-50826 filed by Southern California Gas Company on
August 13, 1992; Exhibit 4.37).

Exhibit 10 -- Material Contracts (Previously filed exhibits are
incorporated by reference from Forms 8-K, S-4, 10-K or
10-Q as referenced below).

Sempra Energy
- -------------
10.01 Energy Purchase Agreement between Sempra Energy Resources and
the California Department of Water Resources, executed
May 4, 2001.

10.02 Amendment to Employment Agreement, effective December 1, 1998.
(Employment agreement, dated as of October 12, 1996 between
Mineral Energy Company and Stephen L. Baum (Enova 8-K filed
October 15, 1996, Exhibit 10.2))

10.03 Amendment to Employment Agreement effective December 1, 1998.
(Employment contract, dated as of October 12, 1996 between
Mineral Energy Company and Donald E. Felsinger (Enova 8-K filed
October 15, 1996, Exhibit 10.4))

Enova Corporation and San Diego Gas & Electric Company
- ------------------------------------------------------
10.04 Restated Letter Agreement between San Diego Gas & Electric
Company and the California Department of Water Resources dated
April 5, 2001.

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

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

Compensation

Sempra Energy
- -------------
10.07 Form of Sempra Energy Severance Pay Agreement for Executives.

10.08 Sempra Energy Executive Security Bonus Plan effective January 1,
2001.

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

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

10.11 Sempra Energy Deferred Compensation Agreement for Directors
effective June 1, 1998 (1998 Form 10-K Exhibit 10.10).

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

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

10.14 Sempra Energy Retirement Plan for Directors effective June 1, 1998
(1998 Form 10-K Exhibit 10.13).

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

10.16 Sempra Energy 1998 Non-Employee Directors' Stock Plan (Incorporated by
reference from the Registration Statement on Form S-8 Sempra Energy
Registration No. 333-56161 dated June 5, 1998 (Exhibit 4.2)).

San Diego Gas & Electric
- ------------------------

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

Pacific Enterprises/Southern California Gas Company
- ---------------------------------------------------

10.18 Pacific Enterprises Employee Stock Ownership Plan and Trust Agreement
as amended effective October 1, 1992 (Pacific Enterprises 1992
Form 10-K Exhibit 10.18).

Financing

Enova Corporation and San Diego Gas & Electric
- ----------------------------------------------

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

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

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

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

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

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

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

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

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

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

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

Natural Gas Transportation

Enova Corporation and San Diego Gas & Electric
- ----------------------------------------------

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

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

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

Nuclear

Enova Corporation and San Diego Gas & Electric
- ----------------------------------------------

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

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

10.35 Amendment No. 1 to the Qualified CPUC Decommissioning Master
Trust Agreement dated September 22, 1994 (see Exhibit 10.34
herein)(1994 SDG&E Form 10-K Exhibit 10.56).

10.36 Second Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station
(see Exhibit 10.34 herein)(1994 SDG&E Form 10-K Exhibit 10.57).

10.37 Third Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station
(see Exhibit 10.34 herein)(1996 SDG&E Form 10-K Exhibit 10.59).

10.38 Fourth Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station
(see Exhibit 10.34 herein)(1996 SDG&E Form 10-K Exhibit 10.60).

10.39 Fifth Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generation Station
(see Exhibit 10.34 herein)(1999 SDG&E Form 10-K Exhibit 10.26).

10.40 Sixth Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station
(see Exhibit 10.34 herein)(1999 SDG&E Form 10-K Exhibit 10.27).

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

10.42 First Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Non-Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station
(see Exhibit 10.41 herein)(1996 Form 10-K Exhibit 10.62).

10.43 Second Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Non-Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station
(see Exhibit 10.41 herein)(1996 Form 10-K Exhibit 10.63).

10.44 Third Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Non-Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station
(see Exhibit 10.41 herein)(1999 SDG&E Form 10-K Exhibit 10.31).

10.45 Fourth Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Non-Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station
(see Exhibit 10.41 herein)(1999 SDG&E Form 10-K Exhibit 10.32).

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

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

Exhibit 12 -- Statement re: Computation Of Ratios

12.01 Computation of Ratio of Earnings to Combined Fixed Charges
and Preferred Stock Dividends for the years ended December
31, 2001, 2000, 1999, 1998 and 1997.

Exhibit 13 -- Annual Report to Security Holders

13.01 Sempra Energy 2001 Annual Report to Shareholders. (Such report,
except for the portions thereof which are expressly incorporated by
reference in this Annual Report, is furnished for the information
of the Securities and Exchange Commission and is not to be deemed
"filed" as part of this Annual Report).

Exhibit 21 -- Subsidiaries

21.01 Schedule of Significant Subsidiaries at December 31, 2001.

Exhibit 23 -- Independent Auditors' Consent, page 29.

GLOSSARY

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

AB 265 A California Assembly bill imposing a 6.5 cent
per kWh electric commodity rate ceiling for
small usage consumers.

AB 43X A California Assembly bill to extend AB265 to
include large consumers.

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

AFUDC Allowance for Funds Used During Construction

BCAP Biennial Cost Allocation Proceeding

Bcf One Billion Cubic Feet (of natural gas)

CEC California Energy Commission

COS Cost of Service

CPUC California Public Utilities Commission

DGN Distribuidora de Gas Natural Mexico

DOE Department of Energy

DTSC Department of Toxic Substances Control

DWR Department of Water and Power

Edison Southern California Edison Company

Elk Hills Elk Hills Power Plant

EMFs Electric and Magnetic Fields

Energia Chilquinta Energia S.A.

Enova Enova Corporation

EPA Environmental Protection Agency

ESOP Employee Stock Ownership Plan

FASB Financial Accounting Standards Board

FERC Federal Energy Regulatory Commission

GCIM Gas Cost Incentive Mechanism

Global Sempra Energy Global Enterprises

Intertie Pacific Intertie

IOUs Investor-Owned Utilities

ISO Independent System Operator

kWh Kilowatt Hour

LIBOR London Interbank Offer Rate

LIFO Last in first out inventory

LNG Liquified Natural Gas

Luz Luz del Sur S.A.A.

mmbtu Million British Thermal Units (of natural gas)

MOU Memorandum of Understanding

mw Megawatt

NRC Nuclear Regulatory Commission

ORA Office of Ratepayer Advocates

OTC Over the counter

PBR Performance-Based Ratemaking/Regulation

PE Pacific Enterprises

PG&E Pacific Gas and Electric Company

PGA Purchased Gas Balancing Account

PGE Portland General Electric Company

PIER Public Interest Energy Research

PRP Potentially Responsible Party

PSEG Public Service Enterprise Group

PX Power Exchange

QFs Qualifying Facilities

QUIPS Quarterly Income Preferred Securities

ROE Return on Equity

ROR Rate of Return

SAG Sempra Atlantic Gas

SDG&E San Diego Gas & Electric Company

SEC Securities and Exchange Commission

SEF Sempra Energy Financial

SEI Sempra Energy International

SER Sempra Energy Resources

SES Sempra Energy Solutions

SET Sempra Energy Trading

SFAS Statement of Financial Accounting Standards

SoCalGas Southern California Gas Company

SONGS San Onofre Nuclear Generating Station

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

TCBA Transition Cost Balancing Account

TURN The Utility Reform Network

UEG Utility Electric Generation

VaR Value at Risk

42