SOUTHERN CALIFORNIA GAS CO - 10-K Annual Report

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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[X] Annual report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 For the fiscal year ended December 31, 2002
OR
[ ] Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 For the transition period from to .

Exact Name of
Commission Registrant IRS Employer
File as specified State of Identification
Number in its charter Incorporation Number
- ---------- -------------- -------------- -------------
1-40 PACIFIC ENTERPRISES California 94-0743670

1-1402 SOUTHERN CALIFORNIA GAS COMPANY California 95-1240705

555 WEST FIFTH STREET, LOS ANGELES, CALIFORNIA 90013
- ---------------------------------------------- ----------
(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code (213)244-1200
--------------
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Name of each exchange
Title of each class on which registered
- ------------------- ---------------------
Pacific Enterprises Preferred Stock: American and Pacific
$4.75 dividend; $4.50 dividend;
$4.40 dividend; $4.36 dividend

Southern California Gas Co. Preferred Stock Pacific
Southern California Gas Co. First Mortgage Bonds: New York
Series BB, due 2023; Series DD, due 2023;
Series EE, due 2025; Series FF, due 2003

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Pacific Enterprises None
Southern California Gas Company 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 80. Glossary on page 83.

Aggregate market value of the voting stock held by non-affiliates of the
registrant as of January 31, 2003:
Pacific Enterprises $57.8 Million
Southern California Gas Company $16.7 Million

Common Stock outstanding without par value as of January 31, 2003:
Pacific Enterprises Wholly owned by Sempra Energy
Southern California Gas Company Wholly owned by Pacific Enterprises

DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Information Statement prepared for the May 2003 annual
meeting of shareholders are incorporated by reference into Part III.

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TABLE OF CONTENTS

PART I
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . 3
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . 12
Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . . 12
Item 4. Submission of Matters to a Vote of Security Holders. . 12

PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . . 12
Item 6. Selected Financial Data. . . . . . . . . . . . . . . . 13
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . 13
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk . . . . . . . . . . . . . . . . . 26
Item 8. Financial Statements and Supplementary Data. . . . . . 27
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . 71

PART III
Item 10. Directors and Executive Officers of the Registrant . . 71
Item 11. Executive Compensation . . . . . . . . . . . . . . . . 72
Item 12. Security Ownership of Certain Beneficial Owners
and Management. . . . . . . . . . . . . . . . . . . 72
Item 13. Certain Relationships and Related Transactions . . . . 72
Item 14 Controls and Procedures. . . . . . . . . . . . . . . . 72

PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . . 73

Independent Auditors' Consent and Report on Schedule. . . . . . 75

Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . 78

Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . 80

Glossary. . . . . . . . . . . . . . . . . . . . . . . . . . . . 83

Certifications. . . . . . . . . . . . . . . . . . . . . . . . . 85

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INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report contains statements that are not historical fact and
constitute forward-looking statements within the meaning of the Private
Securities Litigation Reform Act of 1995. The words "estimates,"
"believes," "expects," "anticipates," "plans," "intends," "may," "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 California Public
Utilities Commission (CPUC), the California Legislature, and the Federal
Energy Regulatory Commission (FERC); capital market conditions,
inflation rates, interest rates and exchange rates; energy and trading
markets, including the timing and extent of changes in commodity prices;
weather conditions and conservation efforts; war and terrorist attacks;
business, regulatory and legal decisions; the 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
companies. 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 companies'
business described in this report and other reports filed by the
companies from time to time with the Securities and Exchange Commission.

PART I

ITEM 1. BUSINESS

Description of Business

Pacific Enterprises (PE or the company) is an energy services company
whose only direct subsidiary is Southern California Gas Company
(SoCalGas), the nation's largest natural gas distribution utility. PE's
common stock is wholly owned by Sempra Energy, a California-based
Fortune 500 holding company, and PE owns all of the common stock of
SoCalGas. The financial statements herein are, in one case, the
Consolidated Financial Statements of PE and its subsidiary, SoCalGas,
and, in the second case, the Consolidated Financial Statements of
SoCalGas and its subsidiaries, which comprise less than one percent of
SoCalGas' consolidated financial position and results of operations.
Sempra Energy also indirectly owns all of the common stock of San Diego
Gas & Electric (SDG&E). SoCalGas and SDG&E are collectively referred to
herein as "the California Utilities." A description of PE and SoCalGas
is given in "Management's Discussion and Analysis of Financial Condition
and Results of Operations" herein.

As PE itself has no operations, PE's financial position and operations
consist of those of SoCalGas and some additional items attributable to
PE's position as a holding company (e.g. cash, intercompany accounts,
debt and equity).

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Company Website

SoCalGas' website address is http://www.socalgas.com/ and the website
address of PE's parent company, Sempra Energy, is
http://www.sempra.com/investor.htm. The company makes available free of
charge via a hyperlink on its website to Sempra Energy's website, its
annual report on Form 10-K, quarterly reports on Form 10-Q, current
reports on Form 8-K, and any amendments to those reports as soon as
reasonably practicable after such material is electronically filed with
or furnished to the Securities and Exchange Commission.

GOVERNMENT REGULATION

Local Regulation

SoCalGas has gas franchises with the 240 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.

California Utility Regulation

The State of California Legislature, from time to time, passes laws that
regulate SoCalGas' operations. For example, in 1999, the legislature
enacted a law addressing natural gas industry restructuring.

The CPUC, which consists of five commissioners appointed by the Governor
of California for staggered six-year terms, regulates 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 CPUC also regulates the relationship of utilities
with their holding companies and is currently conducting an
investigation into this relationship.

United States Utility Regulation

The FERC regulates the interstate sale and transportation of natural
gas, the uniform systems of accounts and rates of depreciation. Both the
FERC and CPUC are currently investigating prices charged to the
California investor-owned utilities (IOUs) by various suppliers of
natural gas and electricity.

Licenses and Permits

SoCalGas obtains a number of permits, authorizations and licenses in
connection with the transmission and distribution of natural gas. They
require periodic renewal, which results in continuing regulation by the
granting agency.

Other regulatory matters are described in Note 9 of the notes to
Consolidated Financial Statements herein.

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SOURCES OF REVENUE

Information on this topic is provided in Note 1 of the notes to
Consolidated Financial Statements herein.

NATURAL GAS OPERATIONS

SoCalGas purchases, sells, distributes, stores and transports natural
gas. It owns and operates a natural gas distribution, transmission and
storage system that supplies natural gas to 18.9 million end-use
customers throughout a 23,000-square mile service territory from San
Luis Obispo in the north, to the Mexican border in the south, and 535
cities, excluding the City of Long Beach and SDG&E's service territory
in the County of San Diego. 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.

SoCalGas offers two basic utility services: sale of natural gas and
transportation of natural gas. Natural gas service is also provided on a
wholesale basis to the distribution systems of the City of Long Beach,
Southwest Gas Corporation and SDG&E, an affiliated company.

Supplies of Natural Gas

SoCalGas buys natural gas under several short-term and long-term
contracts. Short-term purchases are from various suppliers and are
primarily based on monthly spot-market prices. SoCalGas transports
natural 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.

Most of the natural gas purchased and delivered by SoCalGas is produced
outside of California. These supplies are delivered to SoCalGas'
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.

5

The following table shows the sources of natural gas deliveries from
1998 through 2002:

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 SoCalGas. The annual average price of
natural gas at the California/Arizona border was $3.14/million British
thermal units (mmbtu) in 2002, compared with $7.27/mmbtu in 2001 and
$6.25/mmbtu in 2000. Supply/demand imbalances and a number of other
factors associated with California's energy crisis from late 2000
through early 2001 resulted in higher natural gas prices during that
period. Prices for natural gas decreased in the later part of 2001 and
increased toward the end of 2002. As of December 31, 2002, the average
spot cash price at the California/Arizona border was $4.47/mmbtu. The
cost of gas purchased may vary and can exceed the annual average price.

During 2002, SoCalGas delivered 1,004 billion cubic feet (bcf) of
natural gas. Approximately 65 percent of these deliveries were customer-
owned natural gas for which SoCalGas provided transportation services.
The remaining natural gas deliveries were purchased by SoCalGas and
resold to customers.

6

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 UEG, wholesale, large commercial,
industrial and off-system (outside the company's normal service
territory) customers. Of the 5.3 million meters in SoCalGas' service
territory, only 1,300 serve the noncore market.

Most core customers purchase natural gas directly from SoCalGas. Core
customers are permitted to aggregate their natural gas requirement and,
for up to 10 percent of SoCalGas' core market, to purchase natural gas
directly from brokers or producers. The CPUC tentatively authorized the
removal of the 10 percent limit, but this has yet to be implemented.
SoCalGas continues to be obligated to purchase reliable supplies of
natural gas to serve the requirements of its core customers. In early
2002, the California Utilities filed an application with the CPUC to
combine their core procurement portfolios. On August 22, 2002, the CPUC
issued an interim decision denying the request, pending completion of
the CPUC's ongoing investigation of market power issues.

The CPUC ordered that utility procurement services offered to noncore
customers be phased out sometime in 2003. Noncore customers would 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 would also have to make arrangements to deliver their
purchases to SoCalGas' receipt points for delivery through SoCalGas'
transmission and distribution system. The proposed implementation of the
order has encountered significant opposition and the CPUC is
reconsidering its decision.

In 2002, 85 percent of the CPUC-authorized natural gas margin was
allocated to the core customers, with 15 percent allocated to the
noncore customers.

Although revenues from transportation throughput is less than for
natural gas sales, SoCalGas generally earns the same margin whether
SoCalGas buys the natural gas and sells it to the customer or transports
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, 2002, SoCalGas was storing approximately 34 bcf of
customer-owned gas.

Demand for Natural Gas

Natural gas is a principal energy source for residential, commercial,
industrial and UEG 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 and UEG uses. Growth in the natural gas markets is largely
dependent upon the health and expansion of the southern California
economy. SoCalGas added 61,000 new customer meters in 2002 and 59,000 in

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2001, representing growth rates of 1.2 percent and 1.1 percent,
respectively. SoCalGas expects that its growth rate for 2003 will
approximate that of 2002.

During 2002, 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.

Demand for natural gas by noncore customers is very sensitive to the
price of competing fuels. Although the number of noncore customers in
2002 was only 1,300 they accounted for approximately 8 percent of the
authorized natural gas revenues and 65 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 electric utilities the option of purchasing energy for their
customers from 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 SoCalGas 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 SoCalGas'
service area.

Other

The Pipeline Safety Improvement Act of 2002, which became public law on
December 17, 2002, requires that baseline inspections be completed over
a ten-year period, with 50 percent of the inspections complete at the
end of five years. Related to these inspections and potential retrofits,
the company estimates that it will have $2.8 million in operating and
maintenance expense each year and $23 million in capital expenditures.

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
9 and 10 of the notes to Consolidated Financial Statements herein.

RATES AND REGULATION

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 SoCalGas and other market participants.
During 2002 the California Utilities filed a proposed implementation
schedule and revised tariffs and rules required for implementation.
However, protests of these compliance filings were filed, and the CPUC
has not yet authorized implementation of most of the provisions of its
decision. Additional information on natural gas industry restructuring
is provided in "Management's Discussion and Analysis of Financial

8

Condition and Results of Operations" and in Note 9 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, fluctuations in commodity costs and consumption levels do not
affect earnings from SoCalGas' operations. In December 2002, the CPUC
issued a decision approving 100 percent balancing account treatment for
variances between forecast and actual for SoCalGas' noncore revenues and
throughput (see BCAP below). Additional information on balancing
accounts is provided in "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and in Note 1 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 mechanism in effect through the
end of 2002 largely eliminated the effect on SoCalGas' income of
variances in customer demand and natural gas transportation costs and is
subject to the limitations of the Gas Cost Incentive Mechanism (GCIM)
described below. In December 2002, the CPUC issued a decision approving
100 percent balancing account treatment for variances between forecast
and actual for SoCalGas' noncore revenues and throughput. The change
eliminates the impact on earnings from any throughput and revenue
variances compared to adopted forecast levels, effective January 1,
2003. Additional information on the BCAP is provided in Note 9 of the
notes to Consolidated Financial Statements herein.

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 9 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 SoCalGas' cost of capital is provided in "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" and in Note 9 of the notes to Consolidated Financial
Statements herein.

Performance-Based Regulation (PBR)

To promote efficient operations and improved productivity and to move
away from reasonableness reviews and disallowances, the CPUC adopted PBR
for SoCalGas effective in 1997. PBR has resulted in modification to the
general rate case and certain other regulatory proceedings for SoCalGas.
Under PBR, regulators require future income potential to be tied to
achieving or exceeding specific performance and productivity goals,
rather than relying solely on expanding utility plant to increase

9

earnings. The three areas that are eligible for PBR rewards are
operational incentives based on measurements of safety, reliability and
customer satisfaction; demand-side management (DSM) rewards based on the
effectiveness of the programs; and natural gas procurement rewards.
Rewards resulting from PBR are not included in the company's earnings
before they are approved by the CPUC. Additional information on
SoCalGas' PBR mechanism is provided in "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and in Note 9
of the notes to Consolidated Financial Statements herein.

ENVIRONMENTAL MATTERS

Discussions about environmental issues affecting the company are
included in Note 10 of the notes to Consolidated Financial Statements
herein. The following additional information should be read in
conjunction with those discussions.

Hazardous Substances

In 1994, the CPUC approved the Hazardous Waste Collaborative Memorandum
account, allowing California's IOUs to recover their hazardous waste
cleanup costs, including those related to Superfund sites or similar
sites requiring cleanup. Recovery of 90 percent of hazardous waste
cleanup costs and related third-party litigation costs and 70 percent of
the related insurance-litigation expenses is permitted. In addition, the
company has the opportunity to retain a percentage of any insurance
recoveries to offset the 10 percent of costs not recovered in rates.

During the early 1900s, SoCalGas 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. SoCalGas has
identified 42 such sites at which it (together with other users as to 21
of these sites) may have cleanup obligations. Preliminary
investigations, at a minimum, have been completed on 41 of the sites. As
of December 31, 2002, 22 of these sites have been remediated, of which
18 have received certification from the California Environmental
Protection Agency (EPA). At December 31, 2002, SoCalGas' estimated
remaining investigation and remediation liability for all of these sites
was $42.6 million.

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

SoCalGas has been named as a potentially responsible party (PRP) for two
landfill sites and five industrial waste disposal sites, from which
releases have occurred.

Remedial actions and negotiations with other PRPs and the United States
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 $0.7 million for the first site and $10.4 million for
the second site. Since 1987, $11.9 million has been spent ($6.5 million
in 2002), including $6.4 million for two consent decrees to settle and
liquidate all remaining liabilities at the second site.

10

At December 31, 2002, the company's estimated remaining investigation
and remediation liability related to hazardous waste sites, including
the manufactured gas sites, was $42.6 million, of which 90 percent is
authorized to be recovered through the Hazardous Waste Collaborative
mechanism. 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.

Air and Water Quality

California's air quality standards are more restrictive than federal
standards. 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.

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 $5.9 million over the past
three years.

Employees of Registrant

As of December 31, 2002 SoCalGas had 6,230 employees, compared to 6,063
at December 31, 2001.

Labor Relations

Field, technical and most clerical employees at SoCalGas are represented
by the Utility Workers' Union of America or the International Chemical
Workers' Council. The new collective bargaining agreement for field,
technical and most clerical employees at SoCalGas has been negotiated.
The new agreement on wages, hours and working conditions is in effect
through December 31, 2004, and the agreement covering medical, dental
and vision benefits is in effect through December 31, 2003. At December
31, 2002, the agreement covering the pension plan, savings plan and life
insurance expired. The company and the union have agreed to two
successive one-month extensions with the last extension to expire on
February 28, 2003. Negotiations are continuing and an agreement is
expected in the next several weeks.

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ITEM 2. PROPERTIES

Natural Gas Properties

At December 31, 2002, SoCalGas' natural gas facilities included
approximately 2,846 miles of transmission and storage pipeline, 46,181
miles of distribution pipeline and 45,215 miles of service piping. They
also included 11 transmission compressor stations and 4 underground
storage reservoirs, with a combined working capacity of 118 bcf.

Other Properties

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.

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

ITEM 3. LEGAL PROCEEDINGS

Except for the matters described in Note 10 of the notes to Consolidated
Financial Statements or referred to elsewhere in this Annual Report,
neither the companies nor their subsidiaries 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 PE is owned by 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.

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ITEM 6. SELECTED FINANCIAL DATA

Since SoCalGas is a wholly owned subsidiary of Pacific Enterprises, per
share data is not provided.

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

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS -- Pacific Enterprises and Southern California Gas
Company

INTRODUCTION

This section includes management's discussion and analysis of operating
results from 2000 through 2002, and provides information about the
capital resources, liquidity and financial performance of Pacific

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Enterprises (PE) and Southern California Gas Company (SoCalGas).
SoCalGas, PE or the two together are referred to as "the company"
herein, the distinction being indicated by the context. This section
also focuses on the major factors expected to influence future operating
results and discusses investment and financing activities and plans. It
should be read in conjunction with the Consolidated Financial Statements
included herein.

PE is an energy services company whose only direct subsidiary is
SoCalGas, the nation's largest natural gas distribution utility.
SoCalGas owns and operates a natural gas distribution, transmission and
storage system supplying natural gas throughout a 23,000-square mile
service territory. Its service territory extends from San Luis Obispo
on the north to the Mexican border in the south, and 535 cities,
excluding the City of Long Beach and San Diego County. SoCalGas provides
natural gas service to residential, commercial, industrial, utility
electric generation and wholesale customers, through 5.3 million meters
in a service area with a population of 18.9 million.

Business Combination

Sempra Energy (the Parent) was formed to serve as a holding company for
PE, the parent corporation of SoCalGas, and Enova Corporation (Enova),
the parent corporation of San Diego Gas & Electric (SDG&E), in a tax-
free business combination that became effective on June 26, 1998.

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

SoCalGas is regulated primarily by the California Public Utilities
Commission (CPUC). It is the responsibility of the CPUC to regulate
investor-owned utilities (IOUs) in a manner that serves the best
interests of their customers while providing the IOUs the opportunity to
earn a reasonable return on investment.

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 related to natural gas
industry restructuring, adopting several provisions that the company
believes will make natural gas service more reliable, more efficient and
better tailored to the desires of customers. The CPUC anticipated
implementation during 2002; however, implementation has been delayed.

In connection with restructuring of the natural gas industry, the
company 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, such as demand side
management and customer growth, rather than solely to expanding utility
plant.

See additional discussion of these situations under "Factors Influencing
Future Performance" and in Note 9 of the notes to Consolidated Financial
Statements.

The table below summarizes SoCalGas' natural gas volumes and revenues by
customer class:

14

NATURAL GAS SALES, TRANSPORTATION AND EXCHANGE
(Dollars in millions, volumes in billion cubic feet)
For the years ended December 31

2002 Compared to 2001

Natural Gas Revenue and Cost of Gas Distributed. Natural gas
revenues decreased to $2.9 billion in 2002 from $3.7 billion in 2001,
and the cost of natural gas distributed decreased to $1.2 billion in
2002 from $2.1 billion in 2001. These decreases were due to lower
average natural gas commodity prices and decreased transportation for
electric generation plants. For the fourth quarter, natural gas revenues
increased to $859 million in 2002 from $681 million in 2001, and the
cost of natural gas distributed increased to $384 million in 2002 from
$270 million in 2001. These increases were due primarily to increased
natural gas prices in the fourth quarter of 2002.

Under the current regulatory framework, changes in core-market natural
gas prices (natural gas purchased for customers that are primarily
residential and small commercial and industrial customers, without
alternative fuel capability) or consumption levels do not affect net
income, since core customer rates generally recover the actual cost of
natural gas on a substantially concurrent basis and consumption levels
are fully balanced. However, SoCalGas' Gas Cost Incentive Mechanism
(GCIM) allows SoCalGas to share in the savings or costs from buying

15

natural gas for customers below or above monthly benchmarks. The
mechanism permits full recovery of all costs within a tolerance band
above the benchmark price and refunds all savings within a tolerance
band below the benchmark price. The costs or savings outside the
tolerance band are shared between customers and shareholders. See
further discussion in Notes 1 and 9 of the notes to Consolidated
Financial Statements.

Other Operating Expenses. Other operating expenses increased in
2002 compared to 2001 due to higher legal costs, labor and employee
benefits costs, and an increase in operating costs, including operating
costs that are associated with balancing accounts.

Other Income. Other income and deductions consist primarily of
interest income from short-term investments and interest income/expense
from regulatory balancing accounts. This increased in 2002 due to lower
regulatory interest expense, offset by lower interest income from
affiliates. Additionally, PE earned higher rental income in 2002.

Interest Expense. Interest expense decreased in 2002 due to
SoCalGas' repayments of $270 million in long-term debt during the fourth
quarter of 2001, and due to lower interest expense to affiliates.

Income Taxes. Income tax expense at SoCalGas increased in 2002 as
compared to 2001 due to higher income before taxes.

Net Income. Net income for SoCalGas increased to $213 million in
2002 compared to $208 million in 2001. This increase was due primarily
to decreased interest expense in 2002, offset partially by increased
depreciation and the 2000 GCIM award recorded in 2001. Additionally,
PE's net income included less interest income from affiliates in 2002.
Net income for the fourth quarter of 2002 decreased compared to the
fourth quarter of 2001 for both SoCalGas and PE due mainly to increased
operating costs, partially offset by lower interest expense in 2002.

2001 Compared to 2000

Natural Gas Revenue and Cost of Gas Distributed. Natural gas
revenues increased to $3.7 billion in 2001 from $2.9 billion in 2000,
and the cost of natural gas distributed increased to $2.1 billion in
2001 from $1.4 billion in 2000. These increases were due to higher
average gas prices and higher volumes of natural gas sales in 2001. For
the fourth quarter, natural gas revenues decreased to $681 million in
2001 from $804 million in 2000, and the cost of natural gas distributed
decreased to $270 million in 2001 from $402 million in 2000. These
decreases were attributable to lower natural gas costs in the fourth
quarter of 2001.

Other Operating Expenses. Other operating expenses increased in
2001 compared to 2000 due to higher costs for company-use fuel (as a
result of higher natural gas prices), higher employee benefit expenses
and operation costs covered by balancing accounts.

Other Income. Other income and deductions consist primarily of
interest income from short-term investments and interest income and/or
expense from regulatory balancing accounts. This decreased in 2001
compared to 2000 primarily due to lower interest from affiliates, and
due to the 2000 gain on the sale of SoCalGas' investment in Plug Power.

16

Interest Expense. Interest expense decreased in 2001 as compared
to 2000 due to SoCalGas' repayments of $270 million in long-term debt
during the fourth quarter of 2001, and due to lower interest expense to
affiliates.

Income Taxes. Income tax expense decreased in 2001 as compared to
2000 due to lower income before taxes and higher deductions related to
capitalized costs.

Net Income. Net income for SoCalGas increased to $208 million in
2001 compared to $207 million in 2000 primarily due to higher gas
volumes in 2001, offset by the gain on sale of SoCalGas' investment in
Plug Power during 2000 and less interest income from affiliates in 2001.
Net income for the fourth quarter of 2001 decreased compared to the
fourth quarter of 2000 for both SoCalGas and PE, primarily due to the
sale of the Plug Power investment mentioned above.

CAPITAL RESOURCES AND LIQUIDITY

SoCalGas' operations are the major source of liquidity. In addition,
working capital requirements can be met through the issuance of short-
term and long-term debt. Cash requirements primarily consist of capital
expenditures for utility plant. At December 31, 2002, the company had
$22 million in cash and $800 million in unused, committed lines of
credit (of which SoCalGas had $300 million in unused lines of credit and
PE had $500 million for the purpose of providing loans to Sempra Energy
Global Enterprises (Global)).

Management believes that cash flows from operations and debt issuances
will be adequate to finance capital expenditure requirements, and other
commitments. Management continues to regularly monitor SoCalGas'
ability to adequately meet the needs of its operating, financing and
investing activities.

CASH FLOWS FROM OPERATING ACTIVITIES

Net cash provided by operating activities totaled $521 million, $300
million and $772 million for 2002, 2001 and 2000, respectively. The
increase in cash flows from operations was primarily due to the payment
of higher accounts payable in 2001 and the increase in regulatory
balancing accounts, partially offset by higher accounts receivable at
the end of 2002. The increase in accounts receivable was due to higher
natural gas costs towards the end of 2002. See further discussion on the
2001 impact of regulatory balancing accounts activity below.

The decrease in cash flows from operating activities in 2001 compared to
2000 was primarily attributable to the decrease in accounts payable due
to lower natural gas costs in 2001 compared to 2000 and the result of
balancing account activity at SoCalGas. This included returns of prior
overcollections and the temporary effects of higher-than-expected costs
of natural gas and public-purpose programs and lower-than-expected sales
volumes. The decrease was partially offset by lower accounts receivable
balances at the end of 2001.

17

CASH FLOWS FROM INVESTING ACTIVITIES

Net cash used in investing activities totaled $508 million, $74 million
and $444 million for 2002, 2001 and 2000, respectively. The increase in
cash used in investing activities in 2002 compared to 2001 was primarily
due to increased capital expenditures and advances to Sempra Energy,
which are payable on demand.

For 2001, cash flows used in investing activities decreased from 2000
due to loan repayments made by Sempra Energy to the company in 2001
compared to loans made to Sempra Energy in 2000, partially offset by an
increase in capital expenditures for utility plant.

Capital Expenditures for Utility Plant

Capital expenditures were $331 million in 2002, compared to $294 million
and $198 million in 2001 and 2000, respectively. Increases in capital
expenditures in 2002 and 2001 were primarily due to improvements to the
natural gas distribution systems and expansion of pipeline capacity to
meet increased demand by electric generators and by commercial and
industrial customers. The expansion of SoCalGas' pipeline capacity was
completed in 2002.

Future Capital Expenditures

Significant capital expenditures in 2003 are expected to include $350
million for improvements to the distribution system. These expenditures
are expected to be financed by operations and security issuances.

Over the next five years, the company expects to make capital
expenditures of approximately $2 billion. Construction programs are
periodically reviewed and revised by the company in response to changes
in economic conditions, competition, customer growth, inflation,
customer rates, the cost of capital, and environmental and regulatory
requirements.

The company's level of construction expenditures in the next few years
may vary substantially, and will depend on the availability of financing
and business opportunities providing desirable rates of return. The
company's intention is to finance any sizeable expenditures so as to
maintain the company's strong investment-grade ratings and capital
structure. Smaller expenditures will be made by the use of existing
liquidity.

CASH FLOWS FROM FINANCING ACTIVITIES

Net cash used in financing activities totaled $4 million, $418 million
and $134 million for 2002, 2001 and 2000, respectively.

Net cash used in financing activities decreased from 2001 due primarily
to the decrease in common dividends paid and lower debt repayments,
partially offset by the issuance of long-term debt of $250 million. Net
cash used in financing activities increased in 2001 compared to 2000
primarily due to the increase in long-term debt repayments and higher
dividends paid by PE in 2001.

18

Long-Term and Short-Term Debt

In October 2002, SoCalGas publicly offered and sold $250 million of
4.80% first-mortgage bonds, maturing on October 1, 2012. The bonds are
not subject to a sinking fund and are not redeemable prior to maturity
except through a make-whole mechanism. Proceeds from the bond sale have
become part of the company's general treasury funds to replenish amounts
previously expended to refund and retire indebtedness and will be used
for working capital and other general corporate purposes.

On September 30, 2002, SoCalGas cancelled a fixed-to-variable interest-
rate swap on $175 million of first-mortgage bonds. The $6 million gain
on the transaction is being amortized over the life of the bonds, which
mature in 2025.

In August 2002, SoCalGas paid off $100 million of 6.875% first-mortgage
bonds at maturity.

In 2002, cash was used for the repayment of $50 million of short-term
debt. Cash was used for the repayment of $150 million of first-mortgage
bonds and $120 million of unsecured notes in 2001. Also in 2001, PE had
an offsetting increase of $50 million in short-term debt.

In May 2002, SDG&E and SoCalGas replaced their individual revolving
lines of credit with a combined revolving credit agreement under which
each utility may individually borrow up to $300 million, subject to a
combined borrowing limit for both utilities of $500 million. Each
utility's revolving credit line expires on May 16, 2003, at which time
it may convert its then outstanding borrowings to a one-year term loan
subject to having obtained any requisite regulatory approvals.
Borrowings under the agreement, which are available for general
corporate purposes including back-up support for commercial paper and
variable-rate long-term debt, would bear interest at rates varying with
market rates and the borrowing utility's credit rating. The agreement
requires each utility to maintain a debt-to-total capitalization ratio
(as defined in the agreement) of not to exceed 60 percent. The rights,
obligations and covenants of each utility under the agreement are
individual rather than joint with those of the other utility, and a
default by one utility would not constitute a default by the other.

Dividends

Dividends paid to Sempra Energy amounted to $100 million in 2002,
compared to $190 million in 2001 and $100 million in 2000. Dividends
paid by SoCalGas to PE amounted to $200 million, $190 million and $200
million in 2002, 2001 and 2000, respectively.

The payment of future dividends and the amount thereof are within the
discretion of the companies' boards of directors. The CPUC's regulation
of SoCalGas' capital structure limits the amounts that are available for
loans and dividends to Sempra Energy from SoCalGas. At December 31,
2002, the company could have provided a total of $250 million to Sempra
Energy. At December 31, 2002, SoCalGas had loans to Sempra Energy of
$86 million.

Capitalization

Total capitalization, including the current portion of long-term debt at
December 31, 2002 was $2.5 billion of which $2.2 billion applied to

19

SoCalGas. The debt-to-capitalization ratios were 33 percent and 38
percent at December 31, 2002 for PE and SoCalGas, respectively.
Significant changes in capitalization during 2002 included long-term
borrowings and dividends.

Cash and Cash Equivalents

Cash and cash equivalents are available for investment in projects
consistent with the company's strategic direction, retirement of debt,
payment of dividends and other corporate purposes. In addition to cash
generated from ongoing operations, PE has a credit agreement which
permits short-term borrowings of up to $500 million. This agreement,
which expires in April 2003, has not yet been used as of December 31,
2002.

At December 31, 2002, SoCalGas had $22 million of cash and $300 million
of revolving lines of credit. Management believes these amounts and
cash flows from operations and new debt issuances will be adequate to
finance capital expenditures and other commitments.

Commitments

The following is a summary of the company's principal contractual
commitments at December 31, 2002 (dollars in millions). Liabilities
reflecting fixed price contracts and other derivatives are excluded as
they are primarily offset against regulatory assets and would be
recovered from customers through the ratemaking process. Additional
information concerning commitments is provided above and in Notes 3 and
10 of the notes to Consolidated Financial Statements.

20

As of January 31, 2003, SoCalGas has a stable outlook rating from all
three credit rating agencies.

FACTORS INFLUENCING FUTURE PERFORMANCE

Performance of PE in the near future will depend on the results of
SoCalGas. The factors influencing future performance are summarized
below.

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, with SoCalGas' shareholders at risk for whether
market demand for these rights will cover the cost of these facilities;
a further unbundling of SoCalGas' storage services, giving SoCalGas
greater upward pricing flexibility (except for storage service for core
customers) but with increased shareholder risk for whether market demand
will cover storage costs; 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 natural gas marketers serving
core customers; and the elimination of noncore customers' option to
obtain natural gas procurement service from SoCalGas and SDG&E. During
2002 the California Utilities filed a proposed implementation schedule
and revised tariffs and rules required for implementation. However,
protests of these compliance filings were filed and the CPUC has not yet
authorized implementation of most of the provisions of its decision. On
December 30, 2002, the CPUC deferred acting on a plan to implement its
decision.

Allowed Rates of Return

Effective January 1, 2003, SoCalGas' authorized rate of return on
ratebase (ROR) is 8.68 percent and its rate of return on common equity
(ROE) is 10.82 percent. These rates will be effective until the next
periodic review by the CPUC unless market interest-rate changes are
large enough to trigger an automatic adjustment prior thereto, which
last occurred in October 2002 and adjusted rates downward from the
previous 9.49 percent (ROR) and 11.6 percent (ROE) to the current
levels. This change results in a revenue requirement decrease of $10.5
million. SoCalGas 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 customer growth.

Cost of Service (COS) and Performance-Based Regulation

The COS and PBR cases for SoCalGas were filed on December 20, 2002. The
filings outline projected expenses (excluding the commodity cost of
natural gas consumed by customers or expenses for programs such as low-
income assistance) and revenue requirements for 2004 and a formula for
2005 through 2008. SoCalGas' cost of service study proposes an increase
in natural gas base rate revenues of $130 million. The filings also
requested a continuance and expansion of PBR in terms of earnings

21

sharing and performance service standards that include both reward and
penalty provisions related to customer satisfaction, employee safety and
system reliability. The resulting new base rates are expected to be
effective on January 1, 2004. A CPUC decision is expected in late 2003.
SoCalGas' profitability is dependent upon its ability to control costs
within base rates. SoCalGas' PBR mechanism is in effect through
December 31, 2003, at which time the mechanism will be updated. That
update will include, among other things, a reexamination of the
company's reasonable costs of operation to be allowed in rates. The
October 10, 2001 decision also denied the company's request to continue
equal sharing between ratepayers and shareholders of the estimated
savings for the merger discussed in Note 1 and, instead, ordered that
all of the estimated 2003 merger savings go to ratepayers. This decision
will adversely affect the company's 2003 net income by $24 million.

Utility Integration

On September 20, 2001, the CPUC approved Sempra Energy's request to
integrate the management teams of SoCalGas and SDG&E. 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 the majority of shared support services previously 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, an August 2002 CPUC interim decision denied a
request by SoCalGas and SDG&E to combine their natural gas procurement
activities at this time, pending completion of the CPUC's ongoing
investigation of market power issues.

MARKET RISK

Market risk is the risk of erosion of the company's cash flows, net
income, asset values and equity due to adverse changes in prices for
various commodities, and in interest rates.

The company's policy is to use derivative physical and financial
instruments to reduce its exposure to fluctuations in interest rates,
and commodity prices. The company also uses and trades derivative
physical and financial instruments in its energy trading and marketing
activities. Transactions involving these financial instruments are with
major exchanges and other firms believed to be credit worthy. The use of
these instruments exposes the company to market and credit risks which,
at times, may be concentrated with certain counterparties. There were no
unusual concentrations at December 31, 2002, that would indicate an
unacceptable level of risk. Credit risks associated with concentration
are discussed below under "Credit Risk."

The company has adopted corporate-wide policies governing its market-
risk management and trading activities. Assisted by the company's Energy
Risk Management Group (ERMG), the company's 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. Utility management receives
daily information on positions and the ERMG receives information on a
delayed basis detailing positions creating market and credit risk for

22

the company, consistent with affiliate rules. The ERMG independently
measures and reports the market and credit risk associated with these
positions. In addition, the company'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. VaR is calculated independently by the
ERMG for the company. Historical volatilities and correlations between
instruments and positions are used in the calculation. As of December
31, 2002, the total VaR of the company's natural gas positions was not
material.

The company uses energy derivatives to manage natural gas price risk
associated with servicing its load requirements. In addition, the
company makes limited use of natural gas derivatives for trading
purposes. These instruments can include forward contracts, futures,
swaps, options and other contracts. In the case of both price-risk
management and trading activities, the use of derivative financial
instruments is subject to certain limitations imposed by company policy
and regulatory requirements. See the continuing discussion below and
Note 7 of the notes to Consolidated Financial Statements for further
information regarding the use of energy derivatives by the company.

The following discussion of the company's primary market-risk exposures
as of December 31, 2002 includes a discussion of how these exposures are
managed.

Commodity-Price Risk

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

The company's market risk exposure is limited due to CPUC authorized
rate recovery of natural gas purchase, sale and storage activity.
However, the company may, at times, be exposed to market risk as a
result of activities under SoCalGas' GCIM, which is discussed in Note 9
of the notes to Consolidated Financial Statements. The company manages
its risk within the parameters of the company's market-risk management
and trading framework. As of December 31, 2002, the company's exposure
to market risk was not material.

Interest-Rate Risk

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

23

restructuring of the regulatory process, the CPUC has permitted greater
flexibility in the use of debt. As a result, some 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, 2002, the company had $833 million of fixed-rate debt
and no variable-rate debt. Interest on fixed-rate utility debt is fully
recovered in rates on a historical cost basis and interest on variable-
rate debt is provided for in rates on a forecasted basis. At December
31, 2002, SoCalGas' fixed-rate debt had a one-year VaR of $166 million.

At December 31, 2002, the company did not have any outstanding interest-
rate swap transactions. See Notes 3 and 7 of the notes to Consolidated
Financial Statements for further information regarding these swap
transactions.

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

Credit Risk

Credit risk is the risk of loss that would be incurred as a result of
nonperformance by counterparties of their contractual obligations. As
with market risk, the company has adopted corporate-wide policies
governing the management of credit risk. Credit risk management is under
the oversight of the Energy Risk Management Oversight Committee,
assisted by the ERMG and the company's credit department. Using rigorous
models, the company's credit department continuously calculates current
and potential credit risk to counterparties to ensure the risk stays
within approved limits, and reports this information to the ERMG. The
company avoids concentration of counterparties and management believes
its credit policies with regard to counterparties significantly reduce
overall credit risk. These policies include an evaluation of prospective
counterparties' financial condition (including credit ratings),
collateral requirements under certain circumstances, 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. See the "Interest-Rate Risk" section above for additional
information regarding the company's use of interest-rate swap
agreements.

CRITICAL ACCOUNTING POLICIES

Certain accounting policies are viewed by management as critical because
their application is the most relevant, judgmental and/or material to

24

the company's financial position and results of operations, and/or
because they require the use of material judgments and estimates.

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

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

SFAS 133 "Accounting for Derivative Instruments and Hedging
Activities" and SFAS 138 "Accounting for Certain Derivative
Instruments and Certain Hedging Activities," have a significant
effect on the balance sheets of the Company but have no
significant effect on its income statements because of the
principles contained in SFAS 71.

In connection with the application of these and other accounting
policies, the company makes estimates and judgments about various
matters. The most significant of these involve:

The collectibility of regulatory and other assets.

The likelihood of recovery of various deferred tax assets.

Differences between estimates and actual amounts have had significant
impacts in the past and are likely to do so in the future.

As discussed elsewhere herein, the company uses exchange quotations or
other third-party pricing to estimate fair values whenever possible.
When no such data is available, it uses internally developed models and
other techniques. The assumed collectibility of regulatory assets
considers legal and regulatory decisions involving the specific items or
similar items. The assumed collectibility of other assets considers the
nature of the item, the enforceability of contracts where applicable,
the creditworthiness of the other parties and other factors. Costs to
fulfill marked-to-market contracts are based on prior experience. The
likelihood of deferred tax recovery is based on analyses of the deferred
tax assets and the company's expectation of future financial and/or
taxable income, based on its strategic planning.

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

NEW ACCOUNTING STANDARDS

New pronouncements by the Financial Accounting Standards Board (FASB)
that have recently become effective or are yet to be effective are SFAS
142 through SFAS 149 and Interpretations 45 and 46. SFAS 142 affects net
income by replacing the amortization of goodwill with periodic reviews
thereof for impairment with charges against income when impairment is
found. SFAS 143 requires accounting and disclosure changes concerning

25

legal obligations related to future asset retirements. SFAS 144
supercedes SFAS 121 in dealing with other asset impairment issues. SFAS
145 makes technical corrections to previous statements. SFAS 146 deals
with exit and disposal activities, replacing Emerging Issues Task Force
(EITF) Issue 94-3. SFAS 147 deals with acquisitions of financial
institutions. SFAS 148 amends SFAS 123 and adds two additional
transition methods to the fair value method of accounting for stock-
based compensation. SFAS 149 establishes standards for accounting for
financial instruments with characteristics of liabilities and equity.
Interpretation 45 clarifies that a guarantor is required to recognize a
liability for the fair value of the obligation undertaken in issuing a
guarantee. Interpretation 46 addresses consolidation by business
enterprises of variable-interest entities (previously referred to as
"special-purpose entities" in most cases). See further discussion in
Note 1 of the notes to Consolidated Financial Statements.

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report contains statements that are not historical fact and
constitute forward-looking statements within the meaning of the Private
Securities Litigation Reform Act of 1995. The words "estimates,"
"believes," "expects," "anticipates," "plans," "intends," "may," "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, and the FERC; capital market conditions,
inflation rates, interest rates and exchange rates; energy and trading
markets, including the timing and extent of changes in commodity prices;
weather conditions and conservation efforts; war and terrorist attacks;
business, regulatory and legal decisions; the 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
companies. 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 companies'
business described in this report and other reports filed by the
companies from time to time with the Securities and Exchange Commission.

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."

26

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - Pacific
Enterprises

INDEPENDENT AUDITORS' REPORT

To the Board of Directors and Shareholders of Pacific Enterprises:

We have audited the accompanying consolidated balance sheets of Pacific
Enterprises and subsidiaries (the "Company") as of December 31, 2002 and
2001, 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, 2002. 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 Pacific Enterprises
and subsidiaries as of December 31, 2002 and 2001, and the results of
their operations and their cash flows for each of the three years in the
period ended December 31, 2002, in conformity with accounting principles
generally accepted in the United States of America.

/S/ DELOITTE & TOUCHE LLP

San Diego, California
February 14, 2003

27

PACIFIC ENTERPRISES AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
Dollars in millions

28

PACIFIC ENTERPRISES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
Dollars in millions

29

PACIFIC ENTERPRISES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
Dollars in millions

30

PACIFIC ENTERPRISES AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
Dollars in millions

31

PACIFIC ENTERPRISES AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
Years ended December 31, 2002, 2001 and 2000
Dollars in millions

32

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SIGNIFICANT ACCOUNTING POLICIES

Business Combination

Sempra Energy was formed as a holding company for Enova Corporation
(Enova), the parent corporation of San Diego Gas & Electric (SDG&E), and
Pacific Enterprises (PE), the parent corporation of Southern California
Gas Company (SoCalGas), in connection with a business combination of
Enova and PE that was completed on June 26, 1998.

Principles of Consolidation

The Consolidated Financial Statements include the accounts of PE and its
subsidiary, SoCalGas. The financial statements herein are, in one case,
the Consolidated Financial Statements of PE and its subsidiary,
SoCalGas, and, in the second case, the Consolidated Financial Statements
of SoCalGas and its subsidiaries, which comprise less than one percent
of SoCalGas' consolidated financial position and results of operations.
All material intercompany accounts and transactions have been
eliminated.

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

Quasi-Reorganization

In 1993, PE divested its merchandising operations and most of its oil
and natural gas exploration and production business. In connection with
the divestitures, PE effected a quasi-reorganization for financial
reporting purposes as of December 31, 1992. Certain of the liabilities
established in connection with the quasi-reorganization, including
various income tax issues, were favorably resolved in 2001, resulting in
restoring $35 million to shareholders' equity in that year. This did not
affect the calculation of net income or comprehensive income. The
remaining liabilities will be resolved in future years. Management
believes the provisions established for these matters are adequate.

Use of Estimates in the Preparation of the Financial Statements

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

Basis of Presentation

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

33

Regulatory Matters

Effects of Regulation

The accounting policies of the company conform with generally accepted
accounting principles for regulated enterprises and reflect the policies
of the California Public Utilities Commission (CPUC) and the Federal
Energy Regulatory Commission (FERC).

The company prepares its financial statements in accordance with the
provisions of Statement of Financial Accounting Standards (SFAS) 71,
"Accounting for the Effects of Certain Types of Regulation," under which
a regulated utility records a regulatory asset if it is probable that,
through the ratemaking process, the utility will recover that asset from
customers. Regulatory liabilities represent future reductions in rates
for amounts due to customers. To the extent that portions of the utility
operations cease to be subject to SFAS 71, or recovery is no longer
probable as a result of changes in regulation or the utility's
competitive position, the related regulatory assets and liabilities
would be written off. In addition, SFAS 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" affects utility plant and
regulatory assets such that a loss must be recognized whenever a
regulator excludes all or part of an asset's cost from ratebase. The
application of SFAS 144 continues to be evaluated in connection with
industry restructuring. Information concerning regulatory assets and
liabilities is described below in "Revenues", "Regulatory Balancing
Accounts," and "Regulatory Assets and Liabilities," and industry
restructuring is described in Note 9.

Regulatory Balancing Accounts

The amounts included in regulatory balancing accounts at December 31,
2002, represent net payables (payables net of receivables) of $184
million and $158 million at December 31, 2002 and 2001, respectively.
Balancing accounts provide a mechanism for charging utility customers
the amount actually incurred for certain costs, primarily commodity
costs. As SoCalGas' natural gas operations are mostly balanced, such
fluctuations do not affect earnings. In December 2002, the CPUC issued a
decision approving 100 percent balancing account treatment for variances
between forecast and actual for SoCalGas' noncore revenues and
throughput. The change eliminates the impact on earnings from any
throughput and revenue variances compared to adopted forecast levels,
effective January 1, 2003. Additional information on regulatory matters
is included in Note 9.

Regulatory Assets and Liabilities

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

34

Regulatory assets (liabilities) as of December 31 consist of the
following:

(Dollars in millions) 2002 2001
- ------------------------------------------------------------------------

SoCalGas
- ---------
Environmental remediation $ 43 $ 55
Fixed-price contracts and other derivatives 325 232
Unamortized loss on retirement of debt - net 38 41
Deferred taxes refundable in rates (164) (158)
Employee benefit costs (142) (132)
Other 8 5
------- -------
Total 108 43

PE - Employee benefit costs 80 88
------- -------
Total PE consolidated $ 188 $ 131
======= =======

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

2002 2001
- ------------------------------------------------------------------------
SoCalGas
- --------
Current regulatory assets $ 92 $ 85
Noncurrent regulatory assets 233 150
Current regulatory liabilities (16) (18)
Noncurrent regulatory liabilities (201) (174)
------- -------
Total 108 43

PE - Noncurrent regulatory assets 80 88
------- -------
Total PE consolidated $ 188 $ 131
======= =======
- ------------------------------------------------------------------------

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

Cash and Cash Equivalents

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

Collection Allowance

The allowance for doubtful accounts receivable was $4 million, $14
million and $19 million at December 31, 2002, 2001 and 2000,
respectively. The company recorded a provision (reduction thereof) for
doubtful accounts of ($5) million, $9 million and $9 million in 2002,
2001 and 2000, respectively.

35

Inventories

At December 31, 2002, inventory included natural gas of $65 million, and
materials and supplies of $11 million. The corresponding balances at
December 31, 2001 were $34 million and $8 million, respectively. Natural
gas is valued by the last-in first-out (LIFO) method. When the inventory
is consumed, differences between this LIFO valuation and replacement
cost will be reflected in customer rates. Materials and supplies at
SoCalGas are generally valued at the lower of average cost or market.

Utility Plant

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

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

Accumulated depreciation for natural gas utility plant at SoCalGas was
$3.9 billion and $3.7 billion at December 31, 2002 and 2001,
respectively. Depreciation expense is based on the straight-line method
over the useful lives of the assets, an average of 23 years in each of
2002, 2001 and 2000, or a shorter period prescribed by the CPUC. The
provision for depreciation as a percentage of average depreciable
utility plant was 4.34, 4.33 and 4.36 in 2002, 2001 and 2000,
respectively. See Note 9 for discussion of industry restructuring.
Maintenance costs are expensed as incurred.

AFUDC, which represents the cost of funds used to finance the
construction of utility plant, is added to the cost of utility plant.
AFUDC also increases income, partly as an offset to interest charges and
partly as a component of other income, shown in the Statements of
Consolidated Income, although it is not a current source of cash. AFUDC
amounted to $13 million, $8 million and $5 million for 2002, 2001 and
2000, respectively.

Long-Lived Assets

The company periodically evaluates whether events or circumstances have
occurred that may affect the recoverability or the estimated useful
lives of long-lived assets. Impairment occurs when the estimated future
undiscounted cash flows is less than the carrying amount of the assets.
If that comparison indicates that the assets' carrying value may be
permanently impaired, such potential impairment is measured based on the
difference between the carrying amount and the fair value of the assets
based on quoted market prices or, if market prices are not available, on
the estimated discounted cash flows. This calculation is performed at
the lowest level for which separately identifiable cash flows exist. See
further discussion of SFAS 144 in "New Accounting Standards".

Comprehensive Income

Comprehensive income includes all changes, except those resulting from
investments by owners and distributions to owners, in the equity of a
business enterprise from transactions and other events, including
foreign-currency translation adjustments, minimum pension liability

36

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

Revenues

Revenues of SoCalGas are derived from deliveries of natural gas to
customers and changes in related regulatory balancing accounts. Revenues
from natural gas sales and services are generally recorded under the
accrual method and these revenues are recognized upon delivery. Natural
gas storage contract revenues are accrued on a monthly basis and reflect
reservation, storage and injection charges in accordance with negotiated
agreements, which have one-year to three-year terms. Operating revenue
includes amounts for services rendered but unbilled (approximately one-
half month's deliveries) at the end of each year.

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

Related Party Transactions - Loans to Unconsolidated Affiliates

PE has a promissory note due from Sempra Energy which bears a variable
interest rate based on short-term commercial paper rates. The balances
of the note were $416 million and $268 million at December 31, 2002 and
2001, respectively, and were included in noncurrent assets under the
caption "Due from unconsolidated affiliates". At December 31, 2001, PE
had a promissory note due from Sempra Energy Global Enterprises
(Global), which owns most of the businesses of Sempra Energy other than
the California Utilities and serves a broad range of customers' energy
needs. The note was $138 million at December 31, 2001 and was paid in
full during 2002. PE also had $3 million due from other affiliates at
both December 31, 2002 and 2001.

In addition, PE had intercompany payables due to various affiliates of
$96 million and $169 million at December 31, 2002, and 2001,
respectively, which are reported as a current liability. These balances
are due on demand. Of the total balances, $31 million and $27 million
was recorded at SoCalGas at December 31, 2002 and 2001, respectively.

New Accounting Standards

SFAS 143, "Accounting for Asset Retirement Obligations": SFAS 143,
issued in July 2001, addresses financial accounting and reporting for
obligations associated with the retirement of tangible long-lived assets
and the associated asset retirement costs. 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 long-lived assets, such as nuclear plants. It requires
entities to record the fair value of a liability for an asset retirement
obligation in the period in which it is incurred. When the liability is
initially recorded, the entity increases the carrying amount of the
related long-lived asset by the present value of the future retirement
cost. Over time, the liability is accreted to its full value and paid,
and the capitalized cost is depreciated over the useful life of the
related asset. SFAS 143 is effective for financial statements issued for
fiscal years beginning after June 15, 2002. As of January 1, 2003, the
company had asset retirement obligations estimated to be $11 million
associated with the retirement of the Montebello storage field.

37

SFAS 144, "Accounting for Impairment or Disposal of Long-Lived
Assets": In August 2001, the Financial Accounting Standards Board
(FASB) issued SFAS 144, which replaces SFAS 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed
Of." SFAS 144 applies to all long-lived assets, including discontinued
operations. SFAS 144 requires that those long-lived assets classified as
held for sale be measured at the lower of carrying amount (cost less
accumulated depreciation) or fair value less cost to sell. Discontinued
operations will no longer be measured at net realizable value or include
amounts for operating losses that have not yet occurred. SFAS 144 also
broadens the reporting of discontinued operations to include all
components of an entity with operations that can be distinguished from
the rest of the entity and that will be eliminated from the ongoing
operations of the entity in a disposal transaction. The company has
identified no material effects to the financial statements from the
implementation of SFAS 144.

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

The companies have elected to continue using the intrinsic value method
of accounting for stock-based compensation. Therefore, the amendment to
SFAS 123 will not have any effect on the companies' financial
statements. See Note 6 for additional information regarding stock-based
compensation.

SFAS 149, "Accounting for Certain Financial Instruments with
Characteristics of Liabilities and Equity": On January 22, 2003, the
FASB directed its staff to prepare a draft of SFAS 149. The final draft
is expected to be issued in March 2003. The statement will establish
standards for accounting for financial instruments with characteristics
of liabilities, equity, or both. Subsequent to the issuance of SFAS 149,
certain investments that are currently classified as equity in the
financial statements might have to be reclassified as liabilities. In
addition, the FASB decided that SFAS 149 will prohibit the presentation
of certain items in the mezzanine section (the portion of a balance
sheet between liabilities and equity) of the statement of financial
position. For example, certain mandatorily redeemable preferred stock,
which is currently included in the mezzanine section, may be classified
as a liability once SFAS 149 goes into effect. The proposed effective
date of SFAS 149 is July 1, 2003 for the company.

FASB Interpretation 45, "Guarantor's Accounting and Disclosure
Requirements for Guarantees": In November 2002, the FASB issued
Interpretation 45, which elaborates on the disclosures to be made in
interim and annual financial statements of a guarantor about its
obligations under certain guarantees that it has issued. It also
clarifies that a guarantor is required to recognize, at the inception of
a guarantee, a liability for the fair value of the obligation undertaken
in issuing a guarantee. Initial recognition and measurement provisions
of the Interpretation are applicable on a prospective basis to

38

guarantees issued or modified after December 31, 2002. The disclosure
requirements are effective for financial statements of interim or annual
periods ending after December 15, 2002. As of December 31, 2002, the
company did not have any outstanding guarantees.

Other Accounting Standards: During 2002 and 2001 the FASB and the
Emerging Issues Task Force (EITF) issued several statements that are
currently not applicable to the companies. In July 2001, the FASB
issued SFAS 142, "Goodwill and Other Intangible Assets," which addresses
how intangible assets that are acquired individually or with a group of
other assets (but not those acquired in a business combination) should
be accounted for in financial statements upon their acquisition. In
April 2002, the FASB issued SFAS 145, which rescinds SFAS 4, "Reporting
Gains and Losses from Extinguishment of Debt", and SFAS 64,
"Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements." In
June 2002, the FASB issued SFAS 146, "Accounting for Costs Associated
with Exit or Disposal Activities," which addresses accounting for
restructuring and similar costs. SFAS 146 supersedes previous accounting
guidance, principally EITF Issue 94-3, "Liability Recognition for
Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring)." In
October 2002, the FASB issued SFAS 147, "Accounting for Certain
Financial Institutions - an amendment of SFAS 72 and 144 and FASB
Interpretation 9," which applies to acquisitions of financial
institutions. In June 2002, a consensus was reached in EITF Issue 02-3,
which codifies and reconciles existing guidance on the recognition and
reporting of gains and losses on energy trading contracts and addresses
other aspects of the accounting for contracts involved in energy trading
and risk management activities. In October 2002, the EITF reached a
consensus to rescind EITF Issue 98-10, "Accounting for Energy Trading
Contracts," the basis for mark-to-market accounting used for recording
energy-trading activities. In January 2003, the FASB issued
Interpretation 46, "Consolidation of Variable Interest Entities," which
addresses consolidation by business enterprises of variable interest
entities.

NOTE 2. SHORT-TERM BORROWINGS

At December 31, 2002, SoCalGas and its affiliate, SDG&E, had a combined
revolving line of credit, under which each utility individually could
borrow up to $300 million, subject to a combined borrowing limit for
both utilities of $500 million. Borrowings under the agreement, which
are available for general corporate purposes including support for
commercial paper and variable-rate long-term debt, bear interest at
rates varying with market rates and SoCalGas' credit rating. This
revolving credit commitment expires in May 2003, at which time the
outstanding borrowings may be converted into a one-year term loan
subject to any requisite regulatory approvals related to long-term debt.
This agreement requires SoCalGas to maintain a debt-to-total
capitalization ratio (as defined in the agreement) of not to exceed 60
percent. The rights, obligations and covenants of each utility under the
agreement are individual rather than joint with those of the other
utility, and a default by one utility would not constitute a default by
the other. These lines of credit were unused at December 31, 2002. At
December 31, 2002, SoCalGas had no commercial paper outstanding.

At December 31, 2002, PE had a $500 million two-year revolving line of
credit, guaranteed by Sempra Energy, for the purpose of providing loans

39

to Global. The revolving credit commitment expires in April 2003, at
which time the outstanding borrowings may be converted into a two-year
term loan. Borrowings would be subject to mandatory repayment prior to
the maturity date should PE's credit rating cease to be at least BBB- by
Standard & Poor's (S&P) or SoCalGas' unsecured long-term credit ratings
cease to be at least BBB by S&P and Baa2 by Moody's Investor Services,
Inc. (Moody's), should Sempra Energy's or SoCalGas' debt-to-total
capitalization ratio (as defined in the agreement) exceed 65 percent, or
should there be a change in law materially and adversely affecting the
ability of SoCalGas to pay dividends or make distributions to PE.
Borrowings bear interest at rates varying with market rates and the
amount of outstanding borrowings. PE's line of credit was unused at
December 31, 2002 and December 31, 2001.

NOTE 3. LONG-TERM DEBT

- --------------------------------------------------------------
December 31,
(Dollars in millions) 2002 2001
- --------------------------------------------------------------
First-mortgage bonds

5.75% November 15, 2003 $ 100 $ 100
4.8% October 1, 2012 250 --
7.375% March 1, 2023 100 100
7.5% June 15, 2023 125 125
6.875% November 1, 2025 175 175
6.875% August 15, 2002 -- 100
-----------------------
750 600
-----------------------
Unsecured long-term debt
5.67% January 15, 2003 75 75
6.375% May 14, 2006 8 8
-----------------------
83 83
-----------------------
833 683
Less:
Current portion of long-term debt 175 100
Market value adjustment on
interest-rate swap -- 4
Unamortized discount on long-term debt 1 --
-----------------------
Total $ 657 $ 579
- --------------------------------------------------------------

Maturities of long-term debt are $175 million in 2003, $8 million in
2006, and $650 million thereafter.

First-mortgage Bonds

The first-mortgage bonds are secured by a lien on SoCalGas' utility
plant. SoCalGas may issue additional first-mortgage bonds upon
compliance with the provisions of its bond indentures, which require,
among other things, the satisfaction of pro forma earnings-coverage
tests on first-mortgage bond interest and the availability of sufficient
mortgaged property to support the additional bonds. The most restrictive
of these tests (the property test) would permit the issuance, subject to

40

CPUC authorization, of an additional $624 million of first-mortgage
bonds at December 31, 2002.

In November 2001, SoCalGas called its $150 million 8.75% first-mortgage
bonds at a premium of 3.59 percent. On December 11, 2001, SoCalGas
entered into an interest-rate swap which effectively exchanged the fixed
rate on its $175 million 6.875% first-mortgage bonds for a floating
rate. On September 30, 2002, SoCalGas terminated the swap, receiving
cash proceeds of $10 million, comprised of $4 million in accrued
interest and a $6 million amortizable gain. Additional information is
provided under "Interest-Rate Swaps" below. In August 2002, SoCalGas
paid off its $100 million 6.875% first-mortgage bonds.

In October 2002, SoCalGas publicly offered and sold $250 million of 4.8%
first-mortgage bonds, maturing on October 1, 2012. The bonds are not
subject to a sinking fund and are not redeemable prior to maturity
except through a make-whole mechanism. Proceeds from the bond sale have
become part of the company's general funds to replenish amounts
previously expended to refund and retire indebtedness, and for working
capital and other general corporate purposes. These bonds were assigned
ratings of A+ by the S&P rating agency, A1 by Moody's, and AA by Fitch,
Inc.

Callable Bonds

At SoCalGas' option, certain fixed-rate bonds may be called at a
premium, including $400 million in 2003. Of SoCalGas' remaining callable
bonds, $8 million are callable in 2006.

Unsecured Long-term Debt

Various long-term obligations totaling $83 million are unsecured at
December 31, 2002. In October 2001, SoCalGas repaid $120 million of
6.38% medium-term notes upon maturity. In July 2000, SoCalGas repaid $30
million of 8.75% medium-term notes upon maturity.

On January 15, 2003, $70 million of SoCalGas' 5.67% $75 million medium-
term notes were put back to the company. The remaining $5 million
matures on January 18, 2028.

Interest-Rate Swaps

The company periodically enters into interest-rate swap agreements to
moderate its exposure to interest-rate changes and to lower its overall
cost of borrowing. On December 11, 2001, SoCalGas executed a cancelable-
call interest-rate swap, exchanging its fixed-rate obligation of 6.875%
on its $175 million first-mortgage bonds for a floating rate of LIBOR
plus 4 basis points. On September 30, 2002, SoCalGas terminated the
swap, receiving cash proceeds of $10 million, comprised of $4 million in
accrued interest and a $6 million amortizable gain. The company
believes the remaining swap is fully effective in its purpose of
converting the underlying debt's fixed rate to a floating rate and meets
the criteria for accounting under the short-cut method defined in SFAS
133 for fair value hedges of debt instruments. Accordingly, market value
adjustments to long-term debt of $4 million and ($4) million were
recorded at December 31, 2002 and 2001, respectively, to reflect,
without affecting net income or other comprehensive income, the
favorable/unfavorable economic consequences (as measured at December 31,

41

2002 and 2001) of having entered into the swap transactions. See
additional discussion of interest-rate swaps in Note 7.

Financial Covenants

SoCalGas' first-mortgage bond indentures require the satisfaction of
certain bond interest coverage ratios and the availability of sufficient
mortgaged property to issue additional first-mortgage bonds, but do not
restrict other indebtedness. Note 2 discusses the financial covenants
applicable to short-term debt.

NOTE 4. INCOME TAXES

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

Years ended December 31 2002 2001 2000
- ---------------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Depreciation 5.2 5.4 5.2
State income taxes - net of
federal income tax benefit 5.4 6.9 6.9
Tax credits (0.8) (0.8) (0.7)
Other - net (0.4) (1.1) 0.3
------------------------
Effective income tax rate 44.4% 45.4% 46.7%
- ---------------------------------------------------------------------

The components of income tax expense are as follows:

(Dollars in millions) 2002 2001 2000
- ---------------------------------------------------------------------
Current:
Federal $ 94 $ 116 $ 139
State 29 30 41
------------------------
Total 123 146 180
------------------------
Deferred:
Federal 45 20 7
State 5 8 --
------------------------
Total 50 28 7
------------------------
Deferred investment tax credits - net (3) (3) (2)
------------------------
Total income tax expense $ 170 $ 171 $ 185
- ---------------------------------------------------------------------

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

42

Accumulated deferred income taxes at December 31 consist of the
following:

(Dollars in millions) 2002 2001
- ---------------------------------------------------------------------
Deferred Tax Liabilities:
Differences in financial and
tax bases of utility plant $ 290 $ 295
Regulatory balancing accounts 54 56
Regulatory assets 32 36
Other 53 49
--------------------
Total deferred tax liabilities 429 436
--------------------
Deferred Tax Assets:
Investment tax credits 32 34
Postretirement benefits 32 36
Other deferred liabilities 157 174
Restructuring costs 42 42
Other 45 73
--------------------
Total deferred tax assets 308 359
--------------------
Net deferred income tax liability $ 121 $ 77
- ---------------------------------------------------------------------

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

(Dollars in millions) 2002 2001
- ----------------------------------------------------------------------
Current asset $ (55) $ (33)
Noncurrent liability 176 110
--------------------
Total $ 121 $ 77
- ----------------------------------------------------------------------

NOTE 5. EMPLOYEE BENEFIT PLANS

Pension and Other Postretirement Benefits

The company sponsors several qualified and nonqualified pension plans
and other postretirement benefit plans for its employees.

During 2002, the company had amendments reflecting retiree cost of
living adjustments which resulted in an increase in the pension plan
benefit obligation of $48 million. During 2000, the company participated
in a voluntary separation program. As a result, the company recorded a
$40 million special termination benefit.

43

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

44

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

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

- ----------------------------------------------------------------------
(Dollars in millions) 1% Increase 1% Decrease
- ----------------------------------------------------------------------
Effect on total of service and interest cost
components of net periodic postretirement
health-care benefit cost $ 8 $ (6)

Effect on the health-care component of the
accumulated other postretirement
benefit obligation $111 $(89)
- ----------------------------------------------------------------------

Other postretirement benefits include retiree life insurance, medical
benefits for retirees and their spouses, and Medicare Part B
reimbursement for certain retirees.

Savings Plans

The company offers savings plans, administered by plan trustees, to all
eligible employees. Eligibility to participate in the plans is immediate
for salary deferrals. Employees may contribute, subject to plan
provisions, from one percent to 25 percent of their regular earnings.
After one year of completed service, the company begins to make matching
contributions. Employer contributions are equal to 50 percent of the
first 6 percent of eligible base salary contributed by employees and, if
certain company goals are met, an additional amount related to incentive
compensation payments. Employer contributions are invested in Sempra
Energy common stock and must remain so invested until termination of
employment. At the direction of the employees, the employees'
contributions are invested in Sempra Energy stock, mutual funds, or
institutional trusts. Employer contributions for the SoCalGas plans are
partially funded by the Sempra Energy employee stock ownership plan and
Trust. Company contributions to the savings plans were $8 million in
2002, $7 million in 2001 and $5 million in 2000.

45

NOTE 6. STOCK-BASED COMPENSATION

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

In 1995, SFAS 123, "Accounting for Stock-Based Compensation," was
issued. It encourages a fair-value-based method of accounting for stock-
based compensation. As permitted by SFAS 123, Sempra Energy and its
subsidiaries adopted only its disclosure requirements and continue to
account for stock-based compensation in accordance with the provisions
of Accounting Principles Board Opinion 25, "Accounting for Stock Issued
to Employees." See additional discussion of SFAS 148, the amendment to
SFAS 123, in Note 1.

The subsidiaries record an expense for the plans to the extent that
subsidiary employees participate in the plans, or that subsidiaries are
allocated a portion of Sempra Energy's costs of the plans. PE recorded
expenses of $1 million, $3 million and $2 million in 2002, 2001 and
2000, respectively.

NOTE 7. FINANCIAL INSTRUMENTS

Fair Value

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

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

46

Accounting for Derivative Instruments and Hedging Activities

SFAS 133 "Accounting for Derivative Instruments and Hedging Activities,"
as amended by SFAS 138, "Accounting for Certain Derivative Instruments
and Certain Hedging Activities" recognizes all derivatives as either
assets or liabilities in the statement of financial position, measures
those instruments at fair value and recognizes 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 commodity 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 by the company and
the prices to be charged to its customers. Since adoption of SFAS 133 on
January 1, 2001, the company classifies its forward contracts as
follows:

Normal Purchase and Sales: These contracts generally are long-term
contracts that are settled by physical delivery and, therefore, are
eligible for the normal purchases and sales exception of SFAS 133. The
contracts are accounted for at historical cost with gains and losses
reflected in the Statements of Consolidated Income at the contract
settlement date.

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

In instances where hedge accounting is applied to derivatives, cash flow
hedge accounting is elected and, accordingly, changes in fair values of
the derivatives are included in other comprehensive income, but not
reflected in the Statements of Consolidated Income until the
corresponding hedged transaction is settled. The effect on other
comprehensive income for the years ended December 31, 2002 and 2001 was
not material. In instances where derivatives do not qualify for hedge
accounting, gains and losses are recorded in the Statements of
Consolidated Income.

47

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

(Dollars in millions) 2002 2001
- -----------------------------------------------------------------------
Fixed-priced contracts and other derivatives:
Current assets $ - $ 59
Noncurrent assets - 1
----- -----
Total - 60
----- -----
Current liabilities 96 85
Noncurrent liabilities 233 154
----- -----
Total 329 239

Other comprehensive income - 1
----- -----
Net liabilities and equity $ 329 $ 180
===== =====
Regulatory assets and liabilities:
Current regulatory assets 92 85
Noncurrent regulatory assets 233 150
----- -----
Total 325 235
----- -----
Regulatory balancing account liabilities - 50
Current regulatory liabilities - 3
----- -----
Total - 53
----- -----
Net regulatory assets $ 325 $ 182
===== =====
- -----------------------------------------------------------------------

$3 million of losses in 2002 and $3 million of income in 2001 were
recorded in operating revenues in the Statements of Consolidated Income.
Additionally, a market value adjustment of $4 million was made at
December 31, 2001 to long-term debt relating to a fixed-to-floating
interest rate swap agreement discussed below. This market value
adjustment was subsequently reversed at September 30, 2002 upon
cancellation of the swap agreement.

Market Risk

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

Interest-Rate Risk Management

The company periodically enters into interest-rate swap agreements to
moderate exposure to interest-rate changes and to lower the overall cost
of borrowing.

48

SoCalGas had an agreement, which was a cancelable-call interest-rate
swap, exchanging its fixed-rate obligation of 6.875% on its $175 million
first-mortgage bonds for a floating rate of LIBOR plus four basis
points. On September 30, 2002, SoCalGas terminated the swap, receiving
cash proceeds of $10 million, comprised of $4 million in accrued
interest and a $6 million amortizable gain. The company believes both
swaps have been fully effective in their purpose of converting the fixed
rate stated in the debt to a floating rate and the swaps meet the
criteria for accounting under the short-cut method defined in SFAS 133
for fair value hedges of debt instruments. Accordingly, market value
adjustments of $20 million and $22 million (as discussed above) were
added to long-term debt during the years ended December 31, 2002 and
2001, respectively, and no net gains or losses were recorded in income
in respect to these swaps.

Energy Derivatives

SoCalGas utilizes derivative instruments to reduce its exposure to
unfavorable changes in energy prices, which are subject to significant
and often volatile fluctuation. Derivative instruments are comprised of
futures, forwards, swaps, options and long-term delivery contracts.
These contracts allow SoCalGas to predict with greater certainty the
effective prices to be received and the prices to be charged to their
customers. See Note 1 for discussion of how these derivatives are
classified under SFAS 133.

Energy Contracts

SoCalGas records natural gas contracts in "Cost of natural gas
distributed" in the Statements of Consolidated Income. For open
contracts not expected to result in physical delivery, changes in market
value of the contracts are recorded in these accounts during the period
the contracts are open, with an offsetting entry to a regulatory asset
or liability. The majority of the company's contracts result in physical
delivery.

NOTE 8. PREFERRED STOCK

Preferred Stock Of Southern California Gas Company
- -----------------------------------------------------------------
December 31,
(Dollars in millions) 2002 2001
- -----------------------------------------------------------------
$25 par value, authorized 1,000,000 shares
6% Series, 28,041 shares outstanding $ 1 $ 1
6% Series A, 783,032 shares outstanding 19 19
Without par value, authorized 10,000,000 shares -- --
--------------
$20 $20
- ----------------------------------------------------------------

None of SoCalGas' preferred stock is callable. All series have one vote
per share and cumulative preferences as to dividends, and have a
liquidation value of $25 per share plus any unpaid dividends. In
addition, the 6% Series preferred stock would also share pro rata with
common stock in the remaining assets.

49

Preferred Stock Of Pacific Enterprises
- --------------------------------------------------------------------------
December 31,
(Dollars in millions, except call price) Call Price 2002 2001
- --------------------------------------------------------------------------

$4.75 Dividend, 200,000 shares outstanding $100.00 $ 20 $ 20
$4.50 Dividend, 300,000 shares outstanding $100.00 30 30
$4.40 Dividend, 100,000 shares outstanding $101.50 10 10
$4.36 Dividend, 200,000 shares outstanding $101.00 20 20
$4.75 Dividend, 253 shares outstanding $101.00 -- --
------------------
Total preferred stock $ 80 $ 80
- --------------------------------------------------------------------------

PE is authorized to issue 15,000,000 shares of preferred stock without
par value. The preferred stock is subject to redemption at PE's option
at any time upon not less than 30 days' notice, at the applicable
redemption price for each series, together with unpaid dividends. All
series have one vote per share and cumulative preferences as to
dividends, and have a liquidation value of $100 per share plus any
unpaid dividends.

NOTE 9. REGULATORY MATTERS

Gas Industry Restructuring

In January 1998, the CPUC released a staff report initiating a project
to assess the current market and regulatory framework for California's
natural gas industry. In July 1999, after hearings, the CPUC issued a
decision stating which natural gas regulatory changes it found most
promising, encouraging parties to submit settlements addressing those
changes, and providing for further hearings if necessary.

On December 11, 2001, the CPUC issued a decision adopting much of a
settlement that had been submitted in 2000 by SoCalGas and approximately
30 other parties representing all segments of the natural gas industry
in Southern California, but opposed by some parties. The CPUC decision
adopts the following provisions: a system for shippers to hold firm,
tradable rights to capacity on SoCalGas' major natural gas transmission
lines, with SoCalGas' shareholders at risk for whether market demand for
these rights will cover the cost of these facilities; a further
unbundling of SoCalGas' storage services, giving SoCalGas greater upward
pricing flexibility (except for storage service for core customers) but
with increased shareholder risk for whether market demand will cover
storage costs; 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 natural gas marketers serving core
customers; and the elimination of noncore customers' option to obtain
natural gas procurement service from SoCalGas. The CPUC modified the
settlement to provide increased protection against the exercise of
market power by persons who would acquire rights on the SoCalGas natural
gas transmission system. The CPUC also rejected certain aspects of the
settlement that would have provided more options for natural gas
marketers serving core customers.

During 2002 the company filed a proposed implementation schedule and
revised tariffs and rules required for implementation. However, protests

50

of these compliance filings were filed, and the CPUC has not yet
authorized implementation of most of the provisions of its decision. On
December 30, 2002, the CPUC deferred acting on a plan to implement its
decision.

SoCalGas believes that implementation of the decision would make natural
gas service more reliable, more efficient and better tailored to meet
the needs of customers. The decision is not expected to adversely affect
SoCalGas' earnings.

Cost of Service (COS) and Performance-Based Regulation (PBR)

To promote efficient operations and improved productivity and to move
away from reasonableness reviews and disallowances, the CPUC adopted PBR
for SoCalGas effective in 1997. PBR has resulted in modification to the
general rate case and certain other regulatory proceedings for SoCalGas.
Under PBR, regulators require future income potential to be tied to
achieving or exceeding specific performance and productivity goals,
rather than relying solely on expanding utility plant to increase
earnings. The three areas that are eligible for PBR rewards are
operational incentives based on measurements of safety, reliability and
customer satisfaction; demand-side management (DSM) rewards based on the
effectiveness of the programs; and natural gas procurement rewards.
These incentive rewards are not included in the company's earnings
before they are approved by the CPUC.

The COS and PBR cases for SoCalGas were filed on December 20, 2002. The
filings outline projected expenses (excluding the commodity cost of
natural gas consumed by customers or expenses for programs such as low-
income assistance) and revenue requirements for 2004 and a formula for
2005 through 2008. SoCalGas' cost of service study proposes an increase
in natural gas base rate revenues of $130 million. The filings also
requested a continuance and expansion of PBR in terms of earnings
sharing and performance service standards that include both reward and
penalty provisions related to customer satisfaction, employee safety and
system reliability. The resulting new base rates are expected to be
effective on January 1, 2004. A CPUC decision is expected in late 2003.
SoCalGas' PBR mechanism is in effect through December 31, 2003, at which
time the mechanism will be updated. That update will include, among
other things, a reexamination of SoCalGas' reasonable costs of operation
to be allowed in rates.

An October 10, 2001 decision denied SoCalGas' request to continue equal
sharing between ratepayers and shareholders of the estimated savings for
the PE/Enova merger as more fully discussed in Note 1 and, instead,
ordered that all of the estimated 2003 merger savings go to ratepayers.
This decision will adversely affect the company's 2003 net income by $24
million.

On January 16, 2003, the CPUC issued a resolution approving SoCalGas'
report on its PBR results for 2000. The resolution approved SoCalGas'
calculation of the amount that should be retained by shareholders. The
resolution also approved SoCalGas' request for an $80,000 reward for
employee safety results. SoCalGas is not eligible for any other rewards
and was not found by the resolution to owe any penalties.

During 2002, SoCalGas filed its 2001 PBR report with the CPUC. Based on
the results against the performance indicator benchmarks, SoCalGas
requested a total net reward of $0.5 million.

51

Gas Cost Incentive Mechanism (GCIM)

SoCalGas' GCIM allows SoCalGas to receive a share of the savings it
achieves by buying natural gas for customers below monthly benchmarks.
The mechanism permits full recovery of all costs within a tolerance band
above the benchmark price and refunds all savings within a tolerance
band below the benchmark price. The costs or savings outside the
tolerance band are shared between customers and shareholders. The CPUC
approved the use of natural gas futures for managing risk associated
with the GCIM. SoCalGas enters into natural gas futures contracts in the
open market to mitigate risk and better manage natural gas costs.

On December 17, 2002, the CPUC issued its final decision in the GCIM
Year 6 Phase 2 proceeding, approving, with modifications, a settlement
agreement among SoCalGas, the CPUC's ORA and The Utility Reform Network,
a consumer-advocacy group, and extending the GCIM mechanism to Year 7
and beyond.

SoCalGas has requested that the CPUC approve rewards of $30.8 million
and $17.4 million for GCIM Years 7 and 8, respectively. CPUC approval of
these rewards is expected in 2003, subject to possible future adjustment
as a result of its investigation into the run-up in California border
natural gas prices during the winter of 2000-2001 (discussed below). In
the past, shareholder rewards associated with the GCIM had been recorded
to SoCalGas' Purchased Gas Balancing Account after the close of the GCIM
period, covering the utility's natural gas supply operations for the
twelve months ended March 31. In June 2002, the CPUC issued a decision
allowing SoCalGas to recover its GCIM earnings through its monthly core
procurement filing beginning January 1, 2003. These awards are not
included in SoCalGas' earnings until approved by the CPUC.

Demand Side Management (DSM) and Energy Efficiency Awards

Since the 1990s, the investor-owned utilities (IOUs) have been eligible
to earn awards for implementing and/or administering energy-conservation
programs. SoCalGas has offered these programs to customers and has
consistently achieved significant earnings therefrom. Beginning in 2002,
earnings for non-low-income energy-efficiency programs were eliminated;
however, awards related to DSM and low-income energy-efficiency programs
may still be requested.

SoCalGas has outstanding before the CPUC applications to recover
shareholder rewards earned for performance under the DSM programs for
1995 through 2001. Reward requests in these applications total $9.1
million.

A CPUC Administrative Law Judge has scheduled a pre-hearing conference
to review the IOUs' DSM programs. The review may include reanalyzing the
uncollected portion of past rewards earned by IOUs (which have not been
included in SoCalGas' income), and potentially recompute the amount of
the DSM rewards. The company has opposed such a recalculation. The issue
is still pending before the CPUC.

52

Pending Incentive Awards

At December 31, 2002, the following performance incentives were pending
CPUC approval and, therefore, were not included in the company's
earnings (dollars in millions):

Program
---------------------------
PBR $ 0.5
GCIM 48.2
DSM 9.1
---------------------------
Total $ 57.8
===========================

Cost of Capital

Effective January 1, 2003, SoCalGas' authorized rate of return on common
equity (ROE) is 10.82 percent and its return on ratebase (ROR) is 8.68
percent. These rates will continue to be effective until the next
periodic review by the CPUC unless market interest-rate changes are
large enough to trigger an automatic adjustment prior thereto, which
last occurred in October 2002 and adjusted rates downward from the
previous 11.6 percent (ROE) and 9.49 percent (ROR) to the current
levels. This change results in an annual revenue requirement decrease of
$10.5 million.

Border Price Investigation

On November 21, 2002, the CPUC instituted an investigation into the
Southern California natural gas market and the price of natural gas
delivered to the California-Arizona (CA-AZ) border during the period of
March 2000 through May 2001. The CPUC intends to examine the possible
reasons for and issues potentially related to the elevated border prices
that affected California consumers during this period.

SoCalGas is included among the respondents to the investigation. If the
investigation determines that the conduct of any respondent contributed
to the natural gas price spikes at the CA-AZ border during this period,
the CPUC may modify the respondent's applicable natural gas procurement
incentive mechanism, reduce the amount of any shareholder award for the
period involved, or order the respondent to issue a refund to ratepayers
to offset the higher rates paid. SoCalGas is fully cooperating with the
CPUC in the investigation and believe that the CPUC will ultimately
determine that the company was not responsible for the high border
prices during this period.

Biennial Cost Allocation Proceeding (BCAP)

The BCAP determines the allocation of authorized costs between customer
classes and the rates and rate design applicable to such classes for
natural gas transportation service. The BCAP adjusts SoCalGas' rates to
reflect variances in customer demand as compared to the adopted
forecasts previously used in establishing customer natural gas
transportation rates. The mechanism in effect through the end of 2002
largely eliminated the effect on SoCalGas' income of variances in
customer demand and natural gas transportation costs. SoCalGas filed its
2003 BCAP on September 21, 2001. In February 2003, a CPUC Administrative
Law Judge granted a motion to defer the BCAP. SoCalGas must submit an

53

amended application by September 2003, with new rates scheduled to be
implemented by September 2004. On December 5, 2002, the CPUC issued a
decision approving 100 percent balancing account protection for all core
and noncore transportation costs, effective in 2003.

Utility Integration

On September 20, 2001, the CPUC approved Sempra Energy's request to
integrate the management teams of SoCalGas and SDG&E. 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 the majority of shared support services previously provided by
Sempra Energy's centralized corporate center. Once implementation is
completed, the integration is expected to result in more effective
operations.

In a related development, an August 2002 CPUC interim decision denied a
request by SoCalGas and SDG&E to combine their natural gas procurement
activities at this time, pending completion of the CPUC's Border Price
Investigation referred to above.

CPUC Investigation of Energy-Utility Holding Companies

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

NOTE 10. COMMITMENTS AND CONTINGENCIES

Natural Gas Contracts

SoCalGas buys natural gas under short-term and long-term contracts.
Short-term purchases are from various suppliers and are primarily based
on monthly spot-market prices. SoCalGas transports natural 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.

54

At December 31, 2002, the future minimum payments under natural gas
contracts were:

Natural
(Dollars in millions) Transportation Gas Total
- ------------------------------------------------------------------------
2003 $ 197 $ 642 $ 839
2004 199 3 202
2005 190 3 193
2006 104 2 106
2007 2 2 4
Thereafter -- -- --
--------------------------------------------
Total minimum payments $ 692 $ 652 $1,344
- ------------------------------------------------------------------------

Total payments under natural gas contracts were $1.2 billion in 2002,
$2.1 billion in 2001, and $1.4 billion in 2000.

Leases

PE and SoCalGas have operating leases on real and personal property
expiring at various dates from 2003 to 2030. Certain leases on office
facilities contain escalation clauses requiring annual increases in rent
ranging from 4 percent to 7 percent. The rentals payable under these
leases are determined on both fixed and percentage bases, and most
leases contain extension options which are exercisable by PE or
SoCalGas.

At December 31, 2002, the minimum rental commitments payable in future
years under all noncancellable leases were as follows:

- -----------------------------------------------------------------
(Dollars in millions) PE SoCalGas
- -----------------------------------------------------------------
2003 $ 54 $ 41
2004 53 40
2005 52 39
2006 52 39
2007 54 41
Thereafter 189 154
---------------------
Total future rental commitments $ 454 $ 354
- -----------------------------------------------------------------

In connection with the quasi-reorganization described in Note 1, PE
recorded liabilities of $102 million to adjust to fair value the
operating leases related to its headquarters and other facilities at
December 31, 1992. The remaining amount of these liabilities was $42
million at December 31, 2002. These leases are included in the above
table.

Rent expense for operating leases totaled $54 million in 2002, $51
million in 2001 and $55 million in 2000, which included rent expense for
SoCalGas of $42 million, $39 million, and $41 million, respectively.

55

Environmental Issues

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

Significant costs incurred to mitigate or prevent future environmental
contamination or extend the life, increase the capacity or improve the
safety or efficiency of property utilized in current operations are
capitalized. The company's capital expenditures to comply with
environmental laws and regulations were $4 million in 2002, $4 million
in 2001 and $1 million in 2000. The cost of compliance with these
regulations over the next five years is not expected to be significant.

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

The environmental issues currently facing the company or resolved during
the latest three-year period include investigation and remediation of
its manufactured-gas sites (22 completed as of December 31, 2002 and 20
to be completed), and cleanup of third-party waste-disposal sites used
by the company, which has been identified as a PRP (investigations and
remediations are continuing).

Environmental liabilities are recorded when the company's liability is
probable and the costs are reasonably estimable. In many cases, however,
investigations are not yet at a stage where the company has been able to
determine whether it is liable or, if the liability is probable, to
reasonably estimate the amount or range of amounts of the cost or
certain components thereof. Estimates of the company's liability are
further subject to other uncertainties, such as the nature and extent of
site contamination, evolving remediation standards and imprecise
engineering evaluations. The accruals are reviewed periodically and, as
investigations and remediation proceed, adjustments are made as
necessary. At December 31, 2002, the company's accrued liability for
environmental matters was $42.6 million, of which $41.2 million related
to manufactured-gas sites, $1.0 million to waste-disposal sites used by
the company (which has been identified as a PRP) and $0.4 million to
other hazardous waste sites. The accruals for the manufactured-gas and
waste-disposal sites are expected to be paid ratably over the next four
years.

Litigation

Lawsuits filed in 2000 and currently consolidated in San Diego Superior
Court seek class-action certification and damages, alleging that Sempra
Energy, SoCalGas and SDG&E, along with El Paso Energy Corp. and several
of its affiliates, unlawfully sought to control and have manipulated
natural gas and electricity markets. On October 16, 2002, the assigned
San Diego Superior Court judge ruled that the case can proceed with

56

discovery and that the California courts, rather than the FERC, have
jurisdiction in the case. This was a preliminary ruling and not a ruling
on the merits or facts of the case. Northern California cases, which
only name El Paso as a defendant, are scheduled for trial in September
2003 and the remainder of the cases is set for trial in January
2004. During the fourth quarter of 2002, additional similar lawsuits
have been filed in various jurisdictions. Management believes the
allegations are without merit.

In response to an inquiry by FERC regarding natural gas trading,
SoCalGas has denied engaging in "wash" or "round trip" trading
transactions. It is also cooperating with the FERC and other
governmental agencies and officials in their various investigations of
the California energy markets.

Except for the matters referred to above, neither the company nor its
subsidiaries are party to, nor is their property the subject of, any
material pending legal proceedings other than routine litigation
incidental to their businesses.

Management believes that these matters will not have a material adverse
effect on the company's financial condition or results of operations.

Concentration Of Credit Risk

The company maintains credit policies and systems to manage overall
credit risk. These policies include an evaluation of potential
counterparties' financial condition and an assignment of credit limits.
These credit limits are established based on risk and return
considerations under terms customarily available in the industry.
SoCalGas grants credit to customers and counterparties, substantially
all of whom are located in its service territories, which cover most of
Southern California and a portion of central California.

57

NOTE 11. QUARTERLY FINANCIAL DATA (UNAUDITED)

The sum of the quarterly amounts does not necessarily equal the annual
totals due to rounding.

58

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA --
Southern California Gas Company

INDEPENDENT AUDITORS' REPORT

To the Board of Directors and Shareholders of Southern California Gas
Company:

We have audited the accompanying consolidated balance sheets of Southern
California Gas Company and subsidiaries (the "Company") as of December
31, 2002 and 2001, 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, 2002. 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 Southern California
Gas Company and subsidiaries as of December 31, 2002 and 2001, and the
results of their operations and their cash flows for each of the three
years in the period ended December 31, 2002, in conformity with
accounting principles generally accepted in the United States of
America.

/S/ DELOITTE & TOUCHE LLP

San Diego, California
February 14, 2003

59

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
Dollars in millions

60

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
Dollars in millions

61

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
Dollars in millions

62

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
Dollars in millions

63

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
Years ended December 31, 2002, 2001 and 2000
Dollars in millions

64

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SOUTHERN CALIFORNIA GAS COMPANY

The following notes to Consolidated Financial Statements of Pacific
Enterprises are incorporated herein by reference insofar as they relate
to Southern California Gas Company:

Note 1 - Significant Accounting Policies
Note 2 - Short-term Borrowings
Note 3 - Long-term Debt
Note 6 - Stock-based Compensation
Note 7 - Financial Instruments
Note 9 - Regulatory Matters
Note 10 - Commitments and Contingencies

The following additional notes apply only to Southern California Gas
Company:

NOTE 4. INCOME TAXES

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

Years ended December 31 2002 2001 2000
- ---------------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Depreciation 5.1 5.3 5.6
State income taxes - net of
federal income tax benefit 7.0 6.7 6.8
Tax credits (0.8) (0.8) (0.7)
Other - net (0.8) (1.4) 0.2
------------------------
Effective income tax rate 45.5% 44.8% 46.9%
- ---------------------------------------------------------------------

The components of income tax expense are as follows:

(Dollars in millions) 2002 2001 2000
- ---------------------------------------------------------------------
Current:
Federal $ 107 $ 126 $ 144
State 39 34 42
------------------------
Total 146 160 186
------------------------
Deferred:
Federal 33 8 -
State 2 4 (1)
------------------------
Total 35 12 (1)
------------------------
Deferred investment tax credits - net (3) (3) (2)
------------------------
Total income tax expense $ 178 $ 169 $ 183
- ---------------------------------------------------------------------

65

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

Accumulated deferred income taxes at December 31 consist of the
following:

(Dollars in millions) 2002 2001
- ---------------------------------------------------------------------
Deferred Tax Liabilities:
Differences in financial and
tax bases of utility plant $ 258 $ 263
Regulatory balancing accounts 54 56
Other 20 20
-------------------
Total deferred tax liabilities 332 339
-------------------
Deferred Tax Assets:
Investment tax credits 32 35
Other deferred liabilities 157 174
Other (7) 9
-------------------
Total deferred tax assets 182 218
-------------------
Net deferred income tax liability $ 150 $ 121
- ---------------------------------------------------------------------

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

(Dollars in millions) 2002 2001
- ---------------------------------------------------------------------
Current asset $ (87) $ (62)
Noncurrent liability 237 183
-------------------
Total $ 150 $ 121
- ---------------------------------------------------------------------

66

NOTE 5. EMPLOYEE BENEFIT PLANS

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

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

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

(Dollars in millions) 1% Increase 1% Decrease
- ------------------------------------------------------------------------
Effect on total of service and interest cost
components of net periodic postretirement
health-care benefit cost $ 8 $ (6)

Effect on the health-care component of the
accumulated other postretirement
benefit obligation $111 $(89)
- ------------------------------------------------------------------------

Other postretirement benefits include retiree life insurance, medical
benefits for retirees and their spouses, and Medicare Part B
reimbursement for certain retirees.

68

Savings Plans

The company offers savings plans, administered by plan trustees, to all
eligible employees. Eligibility to participate in the plans is immediate
for salary deferrals. Employees may contribute, subject to plan
provisions, from one percent to 25 percent of their regular earnings.
After one year of completed service, the company begins to make matching
contributions. Employer contributions are equal to 50 percent of the
first 6 percent of eligible base salary contributed by employees and, if
certain company goals are met, an additional amount related to incentive
compensation payments. Employer contributions are invested in Sempra
Energy common stock and must remain so invested until termination of
employment. At the direction of the employees, the employees'
contributions are invested in Sempra Energy stock, mutual funds, or
institutional trusts. Employer contributions for the SoCalGas plans are
partially funded by the Sempra Energy Employee Stock Ownership Plan and
Trust. Company contributions to the savings plans were $8 million in
2002, $7 million in 2001 and $5 million in 2000.

NOTE 8. PREFERRED STOCK

- ------------------------------------------------------------------
December 31,
(Dollars in millions) 2002 2001
- ------------------------------------------------------------------
$25 par value, authorized 1,000,000 shares
6% Series, 79,011 shares outstanding $ 3 $ 3
6% Series A, 783,032 shares outstanding 19 19
Without par value, authorized 10,000,000 shares -- --
---------------
Total preferred stock $ 22 $ 22
- -----------------------------------------------------------------

None of SoCalGas' preferred stock is callable. All series have one vote
per share and cumulative preferences as to dividends, and have a
liquidation value of $25 per share, plus any unpaid dividends. In
addition, the 6% Series preferred stock would also share pro rata with
common stock in the remaining assets.

69

NOTE 11. QUARTERLY FINANCIAL DATA (UNAUDITED)

The sum of the quarterly amounts does not necessarily equal the annual
totals due to rounding.

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

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information required on Identification of Directors is incorporated
by reference from "Election of Directors" in the Information Statement
prepared for the May 2003 annual meeting of shareholders. The
information required on the companies' executive officers is set forth
below.

70

Name Age* Position
- -------------------------------------------------------------------
Pacific Enterprises --

Stephen L. Baum 61 Chairman, Chief Executive
Officer and President

John R. Light 61 Executive Vice President and
General Counsel

Neal E. Schmale 56 Executive Vice President and
Chief Financial Officer

Frank H. Ault 58 Senior Vice President and
Controller

Charles A. McMonagle 52 Vice President and Treasurer

Thomas C. Sanger 59 Corporate Secretary

Southern California Gas Company --

Edwin A. Guiles 53 Chairman and Chief Executive
Officer

Debra L. Reed 46 President and Chief Financial
Officer

Steven D. Davis 46 Senior Vice President, Customer
Service and External Relations

Margot A. Kyd 49 Senior Vice President, Corporate
Business Solutions

Roy M. Rawlings 58 Senior Vice President,
Distribution Operations

William L. Reed 50 Senior Vice President, Regulatory
Affairs

Lee M. Stewart 57 Senior Vice President, Gas
Transmission

Terry M. Fleskes 46 Vice President and Controller

* As of December 31, 2002.

Each Executive Officer has been an officer or employee of Sempra Energy
or one of its subsidiaries for more than five years, with the exception
of Mr. Light. Prior to joining the company in 1998, Mr. Light was a
partner in the law firm of Latham & Watkins. Each executive officer of
Southern California Gas Company holds the same position at San Diego Gas
& Electric Company.

71

ITEM 11. EXECUTIVE COMPENSATION

The information required by Item 11 is incorporated by reference from
"Election of Directors" and "Executive Compensation" in the Information
Statement prepared for the May 2003 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
"Share Ownership" in the Information Statement prepared for the May 2003
annual meeting of shareholders.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

None.

ITEM 14. CONTROLS AND PROCEDURES.

The company has designed and maintains disclosure controls and
procedures to ensure that information required to be disclosed in the
company's reports under the Securities Exchange Act of 1934 is recorded,
processed, summarized and reported within the time periods specified in
the rules and forms of the Securities and Exchange Commission and is
accumulated and communicated to the company's management, including its
Chief Executive Officer and Chief Financial Officer, as appropriate, to
allow timely decisions regarding required disclosure. In designing and
evaluating these controls and procedures, management recognizes that any
system of controls and procedures, no matter how well designed and
operated, can provide only reasonable assurance of achieving the desired
objectives and necessarily applies judgment in evaluating the cost-
benefit relationship of other possible controls and procedures. In
addition, the company has investments in unconsolidated entities that it
does not control or manage and, consequently, its disclosure controls
and procedures with respect to these entities are necessarily
substantially more limited than those it maintains with respect to its
consolidated subsidiaries.

Under the supervision and with the participation of management,
including the Chief Executive Officer and the Chief Financial Officer,
the company within 90 days prior to the date of this report has
evaluated the effectiveness of the design and operation of the company's
disclosure controls and procedures. Based on that evaluation, the
company's Chief Executive Officer and Chief Financial Officer have
concluded that the controls and procedures are effective.

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

72

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:

1. Financial statements
Page in
This Report

Independent Auditors' Report for Pacific Enterprises . . . . . . . . 27

Pacific Enterprises Statements of Consolidated Income
for the years ended December 31, 2002, 2001 and 2000 . . . . . . . 28

Pacific Enterprises Consolidated Balance Sheets
at December 31, 2002 and 2001 . . . . . . . . . . . . . . . . . . 29

Pacific Enterprises Statements of Consolidated Cash Flows
for the years ended December 31, 2002, 2001 and 2000 . . . . . . . 31

Pacific Enterprises Statements of Consolidated Changes in
Shareholders' Equity for the years ended
December 31, 2002, 2001 and 2000 . . . . . . . . . . . . . . . . . 32

Pacific Enterprises Notes to Consolidated
Financial Statements . . . . . . . . . . . . . . . . . . . . . . . 33

Independent Auditors' Report for Southern California Gas Company. . .59

Southern California Gas Company Statements of Consolidated Income
for the years ended December 31, 2002, 2001 and 2000 . . . . . . . 60

Southern California Gas Company Consolidated Balance Sheets
at December 31, 2002 and 2001. . . . . . . . . . . . . . . . . . . 61

Southern California Gas Company Statements of Consolidated
Cash Flows for the years ended December 31, 2002, 2001 and 2000. . 63

Southern California Gas Company Statements of Consolidated
Changes in Shareholders' Equity for the years ended December 31,
2002, 2001 and 2000 . . . . . . . . . . . . . . . . . . . . . . . 64

Southern California Gas Company Notes to Consolidated Financial
Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65

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. . . . . . . . 76

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

73

3. Exhibits

See Exhibit Index on page 80 of this report.

(b) Reports on Form 8-K

The following reports on Form 8-K were filed after September 30, 2002:

None.

74

INDEPENDENT AUDITORS' CONSENTS AND REPORT ON SCHEDULE

To the Board of Directors and Shareholders of Pacific Enterprises:

We consent to the incorporation by reference in Registration Statement
Numbers 2-96782, 33-26357, 2-66833, 2-96781, 33-21908, and 33-54055 on
Form S-8 and Registration Statement Numbers 33-24830, 333-52926, and 33-
44338 on Form S-3 of Pacific Enterprises of our report dated February
14, 2003, appearing in this Annual Report on Form 10-K of Pacific
Enterprises for the year ended December 31, 2002.

Our audits of the financial statements referred to in our aforementioned
report also included the financial statement schedule of Pacific
Enterprises, listed in Item 15. 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
February 25, 2003

To the Boards of Directors and Shareholders of Southern California Gas
Company:

We consent to the incorporation by reference in Registration Statement
Numbers 333-70654, 333-45537, 33-51322, 33-53258, 33-59404, and 33-52663
on Form S-3 of our report dated February 14, 2003, appearing in this
Annual Report on Form 10-K of Southern California Gas Company for the
year ended December 31, 2002.

/S/ DELOITTE & TOUCHE LLP

San Diego, California
February 25, 2003

76

Schedule I -- CONDENSED FINANCIAL INFORMATION OF PARENT

PACIFIC ENTERPRISES

Condensed Statements of Income
(Dollars in millions)

76

Schedule I (Continued)-- CONDENSED FINANCIAL INFORMATION OF PARENT

PACIFIC ENTERPRISES

Condensed Statements of Cash Flows
(Dollars in millions)

77

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.

PACIFIC ENTERPRISES

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.

78

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.

SOUTHERN CALIFORNIA GAS COMPANY

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

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

79

EXHIBIT INDEX

The Forms 8-K, 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) and/or Commission File Number 1-1402
(Southern California Gas Company).

Exhibit 3 -- By-Laws and Articles Of Incorporation

3.01 Articles of Incorporation of Pacific Enterprises (Pacific
Enterprises 1996 Form 10-K, Exhibit 3.01).

3.02 Restated Bylaws of Pacific Enterprises dated November 6, 2001.

3.03 Restated Articles of Incorporation of Southern California Gas
Company (Southern California Gas Company 1996 Form 10-K, Exhibit
3.01).

3.04 Restated Bylaws of Southern California Gas Company dated November
6, 2001.

Exhibit 4 -- Instruments Defining The Rights Of Security Holders

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

4.01 Specimen Common Stock Certificate of Pacific Enterprises (Pacific
Enterprises 1988 Form 10-K, Exhibit 4.01).

4.02 Specimen Preferred Stock Certificates of Pacific Enterprises
(Pacific Lighting Corporation 1980 Form 10-K, Exhibit 4.02).

4.03 Specimen Preferred Stock Certificates of Southern California Gas
Company (Southern California Gas Company 1980 Form 10-K, Exhibit
4.01).

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

4.05 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).

4.06 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).

4.07 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).

80

4.08 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).

4.09 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).

4.10 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).

4.11 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).

4.12 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).

4.13 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).

4.14 Supplemental Indenture of Southern California Gas Company to
U.S. Bank, N.A., successor to First Trust of California, N.A.
dated as of October 1, 2002 (2002 Sempra Energy Form 10-K,
Exhibit 4.17).

4.15 Specimen 7 3/4% Series Preferred Stock Certificate (Southern
California Gas Company 1992 Form 10-K, Exhibit 4.15).

Exhibit 10 -- Material Contracts

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

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

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

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

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

81

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

10.07 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).

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

10.09 Amended and Restated Pacific Enterprises Employee Stock Option
Plan (Southern California Gas Company 1996 Form 10-K, Exhibit
10.10).

Exhibit 12 -- Statement Re: Computation of Ratios

12.01 Pacific Enterprises Computation of Ratio of Earnings to Fixed
Charges for the years ended December 31, 2002, 2001, 2000, 1999
and 1998.

12.02 Southern California Gas Company Computation of Ratio of Earnings
to Fixed Charges for the years ended December 31, 2002, 2001,
2000, 1999 and 1998,

Exhibit 21 -- Subsidiaries

21.01 Pacific Enterprises Schedule of Subsidiaries at December 31, 2002.

21.02 Southern California Gas Company Schedule of Subsidiaries at
December 31, 2002.

Exhibit 23 -- Independent Auditor's Consents, page 75.

82

GLOSSARY

AFUDC Allowance for Funds Used During Construction

BCAP Biennial Cost Allocation Proceeding

Bcf Billion Cubic Feet (of natural gas)

CA/AZ California/Arizona

COS Cost of Service

CPUC California Public Utilities Commission

DSM Demand Side Management

EITF Emerging Issues Task Force

Enova Enova Corporation

EPA Environmental Protection Agency

ERMG Energy Risk Management Group

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

IOUs Investor-Owned Utilities

LIFO Last in first out inventory costing method

mmbtu Million British Thermal Units (of natural gas)

ORA Office of Ratepayer Advocates

Parent Sempra Energy

PBR Performance-Based Ratemaking/Regulation

PE Pacific Enterprises

PGA Purchased Gas Balancing Account

PRP Potentially Responsible Party

RD&D Research, Development and Demonstration

ROE Return on Equity

ROR Rate of Return

S&P Standard & Poor's

83

SDG&E San Diego Gas & Electric Company

SEC Securities and Exchange Commission

SFAS Statement of Financial Accounting Standards

SoCalGas Southern California Gas Company

TURN The Utility Reform Network

UEG Utility Electric Generation

VaR Value at Risk

84

CERTIFICATIONS

I, Stephen L. Baum, certify that:

1. I have reviewed this Annual Report on Form 10-K of Pacific
Enterprises;

2. Based on my knowledge, this Annual Report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this Annual Report;

3. Based on my knowledge, the financial statements and other financial
information included in this Annual Report fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this Annual Report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:

a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
Annual Report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this Annual Report (the "Evaluation Date"); and

c) presented in this Annual Report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;

1. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and
the audit committee of registrant's board of directors (or persons
performing the equivalent function):

a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and

1. The registrant's other certifying officers and I have indicated in
this Annual Report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.

February 26, 2003
/s/ Stephen L. Baum
Stephen L. Baum
Chief Executive Officer

85

I, Neal E. Schmale, certify that:

1. I have reviewed this Annual Report on Form 10-K of Pacific
Enterprises;

2. Based on my knowledge, this Annual Report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this Annual Report;

3. Based on my knowledge, the financial statements and other financial
information included in this Annual Report fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this Annual Report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:

a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
Annual Report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this Annual Report (the "Evaluation Date"); and

c) presented in this Annual Report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;

1. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and
the audit committee of registrant's board of directors (or persons
performing the equivalent function):

a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and

1. The registrant's other certifying officers and I have indicated in
this Annual Report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.

February 26, 2003
/s/ Neal E. Schmale
Neal E. Schmale
Chief Financial Officer

86

I, Edwin A. Guiles, certify that:

1. I have reviewed this Annual Report on Form 10-K of Southern
California Gas Company;

2. Based on my knowledge, this Annual Report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this Annual Report;

3. Based on my knowledge, the financial statements and other financial
information included in this Annual Report fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this Annual Report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:

a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
Annual Report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this Annual Report (the "Evaluation Date"); and

c) presented in this Annual Report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;

1. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and
the audit committee of registrant's board of directors (or persons
performing the equivalent function):

a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and

1. The registrant's other certifying officers and I have indicated in
this Annual Report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.

February 26, 2003

/s/ Edwin A. Guiles
Edwin A. Guiles
Chief Executive Officer

87

I, Debra L. Reed, certify that:

1. I have reviewed this Annual Report on Form 10-K of Southern
California Gas Company;

2. Based on my knowledge, this Annual Report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this Annual Report;

3. Based on my knowledge, the financial statements and other financial
information included in this Annual Report fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this Annual Report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:

a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
Annual Report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this Annual Report (the "Evaluation Date"); and

c) presented in this Annual Report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;

1. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and
the audit committee of registrant's board of directors (or persons
performing the equivalent function):

a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and

1. The registrant's other certifying officers and I have indicated in
this Annual Report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.

February 26, 2003

/s/ Debra L. Reed
Debra L. Reed
Chief Financial Officer

88