PACIFIC ENTERPRISES INC - 10-K Annual Report

Back to GetFilings.com

SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K

(Mark One)
[X] Annual report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 For the fiscal year ended December 31, 2003
-----------------------
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

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]

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

Exhibit Index on page 90. Glossary on page 94.

Aggregate market value of the voting stock held by non-affiliates of
the registrant as of January 31, 2004:
Pacific Enterprises $68.6 Million
Southern California Gas Company $19.1 Million

Common Stock outstanding without par value as of January 31, 2004:
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 2004 annual
meeting of shareholders are incorporated by reference into Part III.

2

TABLE OF CONTENTS

PART I
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . 3
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . 11
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 . . . . . . . . 14
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk . . . . . . . . . . . . . . . . . 27
Item 8. Financial Statements and Supplementary Data. . . . . . 28
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . 80
Item 9A. Controls and Procedures. . . . . . . . . . . . . . . . 80

PART III
Item 10. Directors and Executive Officers of the Registrant . . 80
Item 11. Executive Compensation . . . . . . . . . . . . . . . . 82
Item 12. Security Ownership of Certain Beneficial Owners
and Management and Related Stockholder Matters. . . 82
Item 13. Certain Relationships and Related Transactions . . . . 82
Item 14 Principal Accountant Fees and Services . . . . . . . . 82

PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . . 83

Independent Auditors' Consent and Report on Schedule. . . . . . 85

Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . 88

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

Glossary. . . . . . . . . . . . . . . . . . . . . . . . . . . . 94

3

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

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

Forward-looking statements are necessarily based upon various
assumptions involving judgments with respect to the future and other
risks, including, among others, local, regional and national economic,
competitive, political, legislative and regulatory conditions and
developments; actions by the California Public Utilities Commission
(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 status of deregulation of retail
natural gas and electricity delivery; the timing and success of
business development efforts; and other uncertainties, all of which are
difficult to predict and many of which are beyond the control of the
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 significant 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 SoCalGas is
given in "Management's Discussion and Analysis of Financial Condition
and Results of Operations" herein.

4

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.)

Company Website

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

RISK FACTORS

The following risk factors and all other information contained in this
report should be considered carefully when evaluating the company.
These risk factors could affect the actual results of the company and
cause such results to differ materially from those expressed in any
forward-looking statements of, or made by or on behalf of, the company.
Other risks and uncertainties, in addition to those that are described
below, may also impair its business operations. If any of the following
risks occurs, the company's business, cash flows, results of operations
and financial condition could be seriously harmed. These risk factors
should be read in conjunction with the other detailed information
concerning the company set forth in the notes to Consolidated Financial
Statements and in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" herein.

SoCalGas is subject to extensive regulation by state, federal and local
legislation and regulatory authorities, which may adversely affect the
operations, performance and growth of its business.

The 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, rates
of return, rates of depreciation, uniform systems of accounts,
examination of records and long-term resource procurement. The CPUC
conducts various reviews of utility performance (including
reasonableness and prudency reviews) and conducts audits and
investigations into various matters which may, from time to time,
result in disallowances and penalties adversely affecting earnings and
cash flows. The CPUC also regulates the relationship of utilities with
their affiliates and is currently conducting an investigation into this
relationship. Various proceedings involving the CPUC and relating to
SoCalGas' rates, costs, incentive mechanisms, performance-based
regulation and affiliate and holding company rule compliance are
discussed in the notes to Consolidated Financial Statements and in
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" herein.

Periodically SoCalGas' rates are approved by the CPUC based on
forecasts of capital and operating costs. If SoCalGas' actual capital
and operating costs were to exceed the amount included in its base

5

rates approved by the CPUC, it would adversely affect earnings and cash
flows.

To promote efficient operations and improved productivity and to move
away from reasonableness reviews and disallowances, the CPUC adopted
Performance-Based Regulation (PBR) effective in 1997. 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.
Although SoCalGas has received significant PBR rewards in the past,
there can be no assurance that SoCalGas will receive rewards at similar
levels in the future, or at all. Additionally, if SoCalGas fails to
achieve certain minimum performance levels established under the PBR
mechanisms, it may be assessed financial disallowances or penalties
which could adversely affect its earnings and cash flows.

SoCalGas may be impacted by new regulations, decisions, orders or
interpretations of the CPUC or other regulatory bodies. New
legislation, regulations, decisions, orders or interpretations could
change how SoCalGas operates, could affect its ability to recover its
various costs through rates or adjustment mechanisms, or could require
SoCalGas to incur additional expenses.

SoCalGas' future results of operations, cash flows and financial
condition may be materially adversely affected by the outcome of
pending litigation against it.
Lawsuits filed in 2000 and currently consolidated in San Diego Superior
Court seek class-action certification and damages, alleging Sempra
Energy and the California Utilities, along with El Paso Energy Corp.
and several of its affiliates, unlawfully sought to control natural gas
markets. Similar lawsuits have been filed by the Attorneys General of
Arizona and Nevada and by others. Although the California Utilities
expect to prevail in these cases, they have expended or accrued
substantial amounts to pay the costs of defending these claims. If the
plaintiffs in these cases were to prevail in their claims, the future
results of operations, cash flows and financial condition of the
company may be materially adversely affected.

These proceedings are discussed in the notes to Consolidated Financial
Statements and in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" herein.

SoCalGas' cash flows, ability to pay dividends and ability to meet its
debt obligations largely depend on the performance of its utility
operations.
SoCalGas' utility operations are its major source of liquidity.
SoCalGas' cash flows, ability to meet its obligations to creditors and
its ability to pay dividends on its common stock are largely dependent
upon the sufficiency of utility earnings and cash flows in excess of
utility needs.

6

Natural disasters, catastrophic accidents or acts of terrorism could
materially adversely affect SoCalGas' business, earnings and cash
flows.

Like other major industrial facilities, SoCalGas' natural gas pipelines
may be damaged by natural disasters, catastrophic accidents or acts of
terrorism. Any such incidents could result in severe business
disruptions, significant decreases in revenues and/or significant
additional costs to the company, which could have a material adverse
effect on SoCalGas' earnings and cash flows. Given the nature and
location of these facilities, any such incidents also could cause
fires, leaks, explosions, spills or other significant damage to natural
resources and/or property belonging to third parties, or personal
injuries, which could lead to significant claims against the company
and its subsidiaries. Insurance coverage may become unavailable for
certain of these risks and the insurance proceeds received for any loss
of or damage to any of its facilities, or for any loss of or damage to
natural resources or property or personal injuries caused by its
operations, may be insufficient to cover the company's losses or
liabilities without materially adversely affecting the company's
financial condition, earnings and cash flows.

GOVERNMENT REGULATION

California Utility Regulation

The CPUC, which consists of five commissioners appointed by the
Governor of California for staggered six-year terms, regulates
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 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 the CPUC are currently investigating prices charged to the
California investor-owned utilities (IOUs) by various suppliers of
natural gas and electricity. See further discussion in Note 9 of the
notes to Consolidated Financial Statements herein.

7

Local Regulation

SoCalGas has natural 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 2005 to
2048.

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.

NATURAL GAS OPERATIONS

Resource Planning and Natural Gas Procurement and Transportation

SoCalGas is engaged in the sale, distribution, storage and
transportation of natural gas. The company's resource planning, natural
gas procurement, contractual commitments and related regulatory
matters are discussed below and in "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and in Notes
9 and 10 of the notes to Consolidated Financial Statements herein.

Customers

For regulatory purposes, customers are separated into core and noncore
customers. Core customers are primarily residential and small
commercial and industrial customers without alternative fuel
capability. Noncore customers consist primarily of electric generation
(EG), wholesale, large commercial, industrial and enhanced oil recovery
customers.

Most core customers purchase natural gas directly from SoCalGas. Core
customers are permitted to aggregate their natural gas requirement and
purchase directly from brokers or producers. SoCalGas continues to be
obligated to purchase reliable supplies of natural gas to serve the
requirements of the core customers.

Natural Gas Procurement and Transportation

Most of the natural gas purchased and delivered by SoCalGas is produced
outside of California, primarily in the southwestern U.S. and Canada.
SoCalGas purchases natural gas under short-term contracts, primarily
based on monthly spot-market prices.

To ensure the delivery of the natural gas supplies to the distribution
system and to meet the seasonal and annual needs of customers, SoCalGas
is committed to firm pipeline capacity contracts that require the

8

payment of fixed reservation charges to reserve firm transportation
entitlements. SoCalGas releases and brokers excess capacity on a short-
term basis. Interstate pipeline companies, primarily El Paso Natural
Gas Company and Transwestern Pipeline Company, provide transportation
services to SoCalGas' intrastate transmission system for supplies
purchased by SoCalGas or its transportation customers from outside of
California. The last of these contracts expires in 2007. The rates
that interstate pipeline companies may charge for natural gas and
transportation services are regulated by the FERC.

According to "Btu's Daily Gas Wire", the annual average spot price of
natural gas at the California/Arizona border was $5.10 per million
British thermal unit (mmbtu) in 2003 ($5.59 in December 2003), compared
with $3.14 per mmbtu in 2002 and $7.27 per mmbtu in 2001. A number of
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 and in 2003. The following table
summarizes the average commodity costs of natural gas sold for the last
three years, which are above previous levels:

Years ended December 31,
-------------------------------------
2003 2002 2001
-------------------------------------
Cost of natural gas $1,830 $1,192 $2,117
Volumes delivered (bcf) 347 356 358
Average cost of natural gas
(dollars per bcf) $ 5.27 $ 3.35 $ 5.91

With improved delivery capacity to California, SoCalGas expects
adequate resources to be available at prices that generally will follow
national natural gas pricing trends and volatility.

Natural Gas Storage

SoCalGas provides natural gas storage services for use by the core,
noncore and off-system customers. Core customers are allocated a
portion of SoCalGas storage capacity. Remaining customers can bid and
negotiate the desired amount of storage on a contract basis. The
storage service program provides opportunities for customers to store
natural gas, usually during the summer, to reduce winter purchases when
natural gas costs are generally higher. This allows customers to select
the level of service they desire to assist them to manage their fuel
procurement and transportation needs.

Demand for Natural Gas

SoCalGas faces competition in the residential and commercial customer
markets based on the customers' preferences for natural gas compared
with other energy products. The demand for natural gas by electric
generators is influenced by a number of factors. In the short-term,
natural gas use by EGs is impacted by the availability of alternative
sources of generation. The availability of hydroelectricity is highly
dependent on precipitation in the western United States. In addition,
natural gas use is impacted by the performance of other generation
sources in the western United States, including nuclear and coal, and

9

other natural gas facilities outside the service area. Natural gas use
is also impacted by changes in end-use electricity demand. For example,
natural gas use generally increases during summer heat waves. Over the
long-term, natural gas use will be greatly influenced by additional
factors such as the location of new power plant construction. More
generation capacity currently is being constructed outside Southern
California than within the utility service area. This new generation
will likely displace the output of older, less efficient local
generation, reducing EG natural gas use.

Effective March 31, 1998, electric industry restructuring provided out-
of-state producers the option to purchase energy for California utility
customers. As a result, natural gas demand for electric generation
within Southern California competes with electric power generated
throughout the western United States. Although electric industry
restructuring has no direct impact on 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 electric generation from SoCalGas' service area.

Growth in the natural gas markets is largely dependent upon the health
and expansion of the Southern California economy and prices of other
energy products. External factors such as weather, the price of
electricity, electric deregulation, the use of hydroelectric power,
competing pipelines and general economic conditions can result in
significant shifts in demand and market price. SoCalGas added 72,000
new customer meters in 2003 and 61,000 in 2002, representing growth
rates of 1.3 percent and 1.2 percent, respectively. SoCalGas expects
that its growth rate for 2004 will approximate that for 2003.

In the interruptible industrial market, customers are capable of
burning a fuel other than natural gas. Fuel oil is the most significant
competing energy alternative. The company's ability to maintain its
industrial market share is largely dependent on price. The relationship
between natural gas supply and demand has the greatest impact on the
price of the company's product. With the reduction of natural gas
production from domestic sources, the cost of natural gas from non-
domestic sources may play a greater role in the company's competitive
position in the future. The price of oil depends upon a number of
factors beyond the company's control, including the relationship
between supply and demand, and policies of foreign and domestic
governments.

The natural gas distribution business is seasonal in nature as
variations in weather conditions generally result in greater revenues
during the winter months when temperatures are colder. As is prevalent
in the industry, the company injects natural gas into storage during
the summer months (usually April through October) for withdrawal
storage during the winter months (usually November through March) when
customer demand is higher.

10

RATES AND REGULATION

Information concerning rates and regulations applicable to SoCalGas is
provided in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and in Notes 1 and 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 manufactured-gas plants (MGPs) often have become
contaminated with the hazardous residues 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, 2003, 26 of these sites have been remediated, of
which 20 have received certification from the California Environmental
Protection Agency. At December 31, 2003, SoCalGas' estimated remaining
investigation and remediation liability for the MGPs is $42.9 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
one landfill site and one industrial waste disposal site, from which
releases have occurred, as described below.

At December 31, 2003, the company's estimated remaining investigation
and remediation liability related to hazardous waste sites, including
the MGPs, was $43.8 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.

11

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 operating
costs. The CPUC has authorized SoCalGas to recover its operating costs
associated with RD&D. SoCalGas' annual RD&D costs have averaged $6.9
million over the past three years.

Employees of Registrant

As of December 31, 2003 SoCalGas had 6,570 employees, compared to 6,230
at December 31, 2002.

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 collective bargaining
agreement for field, technical and most clerical employees at SoCalGas
covering wages, hours, working conditions, medical and various benefit
plans is in effect through December 31, 2004.

ITEM 2. PROPERTIES

Natural Gas Properties

At December 31, 2003, SoCalGas' natural gas facilities included 2,848
miles of transmission and storage pipeline, 46,712 miles of
distribution pipeline and 45,578 miles of service piping. They also
included 11 transmission compressor stations and 4 underground storage
reservoirs, with a combined working capacity of 122 bcf.

Other Properties

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

12

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 herein 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.

13

ITEM 6. SELECTED FINANCIAL DATA

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

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.

14

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

INTRODUCTION

This section includes management's discussion and analysis of operating
results from 2001 through 2003, and provides information about the
capital resources, liquidity and financial performance of Pacific
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 in this Financial Report.

PE is an energy services company whose only significant 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, which includes 535 cities,
extends from San Luis Obispo on the north to the Mexican border in the
south excluding San Diego County, the City of Long Beach and the desert
area of San Bernadino County. SoCalGas provides natural gas service to
residential, commercial, industrial, utility electric generation and
wholesale customers through 5.4 million meters in a service area with a
population of 19.2 million. SoCalGas and its affiliate, San Diego Gas &
Electric (SDG&E), are collectively referred to herein as "the
California Utilities."

RESULTS OF OPERATIONS

2003 was a successful year for the company. Net income at SoCalGas was
$210 million, which is consistent with recent years. This is discussed
further in the following pages.

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

(Dollars in millions)
- ------------------------------------------------
PE SoCalGas
------------ ------------
2003 $ 221 $ 210
2002 $ 213 $ 213
2001 $ 206 $ 208
2000 $ 211 $ 207
1999 $ 184 $ 201

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

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 subject to various regulatory bodies and rules at the
national, state and local levels. The primary California body is the
California Public Utilities Commission (CPUC), which regulates utility

15

rates and operations. The primary national body is the Federal Energy
Regulatory Commission (FERC). The FERC regulates interstate
transportation of natural gas and various related matters. Local
regulators and municipalities govern the placement of utility assets,
including natural gas pipelines.

The natural gas industry experienced an initial phase of restructuring
during the 1980s by deregulating natural gas sales to noncore
customers. Restructuring is again being considered, as discussed in
Note 9 of the notes to Consolidated Financial Statements.

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

Natural Gas Revenue and Cost of Natural Gas. Natural gas revenues
increased to $3.5 billion in 2003 from $2.9 billion in 2002, and the
cost of natural gas increased to $1.8 billion in 2003 from $1.2 billion
in 2002. Additionally, natural gas revenues increased to $922 million
for the three months ended December 31, 2003 from $859 million for the
corresponding period in 2002, and the cost of natural gas increased to
$476 million in the 2003 period from $384 million in the 2002 period.
These changes were primarily attributable to natural gas price
increases. For the year, this was partially offset by reduced volumes.
Revenues also increased due to $48 million of Gas Cost Incentive
Mechanism (GCIM) awards and $1 million of Performance-Based Regulation
(PBR) awards recognized during 2003. See discussion of performance
awards in Note 9 of the notes to Consolidated Financial Statements.

Under the current regulatory framework, the cost of natural gas
purchased for customers and the variations in that cost are passed
through to the customers on a substantially concurrent basis. However,
SoCalGas' GCIM allows SoCalGas to share in the savings or costs from
buying 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.

Natural gas revenues decreased to $2.9 billion in 2002 from $3.7
billion in 2001, and the cost of natural gas decreased to $1.2 billion
in 2002 from $2.1 billion in 2001. The decrease in natural gas revenues
was primarily due to lower natural gas prices and decreased
transportation charges related to electric generation plants and the
North Baja pipeline's beginning of service in September 2002. The
decrease in the cost of natural gas was primarily due to lower average
natural gas commodity prices. For the fourth quarter, natural gas
revenues increased to $859 million in 2002 from $681 million in 2001,
and the cost of natural gas increased to $384 million in the 2002
period from $270 million in the 2001 period due primarily to increased
natural gas prices.

16

The table below summarizes SoCalGas' natural gas volumes and revenues
by customer class for the years ended December 31, 2003, 2002 and 2001.

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

Other Operating Expenses. Other operating expenses at SoCalGas were
$954 million, $872 million and $792 million in 2003, 2002 and 2001,
respectively. The increase in 2003 compared to 2002 was primarily a
result of a $56 million before-tax charge for litigation and for losses
associated with a sublease of portions of the SoCalGas headquarters
building, as well as higher labor and employee benefits costs. The non-
recurring sublease losses pertain to pre-2003 transactions, but are
charged against current operations because they are not material to
annual financial statements. During 2002 the company recorded $13
million in litigation costs related to the California energy crisis.
Other operating expenses increased in 2002 compared to 2001 due to
higher legal costs, labor and employee benefits costs and other
operating costs, including those 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. Excluding the impact of income taxes on
non-operating income, other income at SoCalGas was $40 million, $10

17

million, and $7 million in 2003, 2002 and 2001, respectively. For the
fourth quarters the corresponding amounts were $30 million and $6
million for 2003 and 2002, respectively, compared to a loss of $8
million in 2001. The increases in 2003 were due to higher interest
income resulting from the favorable $30 million before-tax resolution
of income-tax issues with the Internal Revenue Service (IRS) in 2003.
The increases during 2002 were 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 at SoCalGas was $45 million, $44
million and $68 million in 2003, 2002 and 2001, respectively. For the
fourth quarters the corresponding amounts were $12 million, $14 million
and $8 million, respectively. The decrease for the year in 2002 was
mainly due to SoCalGas' repayments of $270 million in long-term debt
during the fourth quarter of 2001. See further discussion in "Cash
Flows from Financing Activities" below.

Income Taxes. Income tax expense at SoCalGas was $150 million, $178
million and $169 million in 2003, 2002 and 2001, respectively. The
corresponding effective income tax rates were 41.7 percent, 45.5
percent and 44.8 percent. For the fourth quarter income tax expense was
$34 million, $44 million and $33 million in 2003, 2002 and 2001,
respectively. The effective income tax rates for the respective periods
were 35.8 percent, 49.4 percent and 39.3 percent. The decreases in 2003
were due to the $12 million favorable resolution of income tax issues
in the fourth quarter of 2003. In addition, income before taxes in 2003
included $30 million in interest income arising from the income tax
settlement, resulting in an offsetting $13 million income tax expense.
The increased income tax expense in 2002 was due to higher income
before taxes.

Net Income. SoCalGas recorded net income of $210 million and $213
million in 2003 and 2002, respectively, and net income of $61 million
and $45 million for the three-month periods ended December 31, 2003 and
2002, respectively. During 2003, net income was affected by the
resolution of income-tax issues in the fourth quarter and the $29
million after-tax GCIM awards in the third quarter (see Note 9 of the
notes to Consolidated Financial Statements for a discussion of GCIM
awards), offset by a $32 million after-tax charge for litigation and
for losses associated with a long-term sublease of portions of its
headquarters building, and the end of sharing of merger savings (which
positively impacted earnings by $17 million for the year ended December
31, 2002). The non-recurring sublease losses pertain to pre-2003
transactions, but are charged against current operations because they
are not material to annual financial statements. The change for the
quarter was due primarily to the resolution of the income tax issues,
offset partially by the end of sharing of merger savings (which
positively impacted earnings by $4 million for the fourth quarter of
2002). In addition, PE's net income included lower interest expense in
2003.

Net income for SoCalGas increased to $213 million in 2002 compared to
$208 million in 2001 primarily due to decreased interest expense in
2002, offset partially by higher depreciation expense 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

18

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.

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, 2003, the company had $32 million in cash and $675
million in available unused, committed lines of credit of which PE had
$375 million for the sole purpose of providing loans to Sempra Energy
Global Enterprises (Global), another subsidiary of Sempra Energy, and
SoCalGas had $300 million.

Management believes that cash flows from operations will be adequate to
finance capital expenditure requirements (see "Future Capital
Expenditures" for forecasted capital expenditures for the next five
years) and other commitments. Management continues to regularly monitor
SoCalGas' ability to finance the needs of its operating, financing and
investing activities in a manner consistent with its intention to
maintain strong, investment-quality credit ratings.

CASH FLOWS FROM OPERATING ACTIVITIES

Net cash provided by PE's consolidated operating activities totaled
$375 million, $521 million and $300 million for 2003, 2002 and 2001,
respectively. Net cash provided by SoCalGas' operating activities
totaled $385 million, $527 million and $280 million for 2003, 2002 and
2001, respectively.

The decreases in 2003 compared to 2002 were primarily attributable to
SoCalGas' decrease in overcollected regulatory balancing accounts in
2003 resulting from higher natural gas prices and lower usage and the
refunding of customer deposits, partially offset by lower tax payments
in 2003.

The increases in cash flows from operations in 2002 compared to 2001
were 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.

During 2003, the company made a pension plan contribution of $2 million
for the 2003 plan year.

CASH FLOWS FROM INVESTING ACTIVITIES

Net cash used in PE's consolidated investing activities totaled $216
million, $508 million and $74 million for 2003, 2002 and 2001,
respectively. Net cash used in SoCalGas' investing activities totaled
$279 million, $417 million and $61 million for 2003, 2002 and 2001,
respectively.

PE's decrease in 2003 compared to 2002 was primarily due to the $97
million repayment from Sempra Energy in 2003 compared to $177 million

19

of advances to Sempra Energy in 2002. For SoCalGas, the change in 2003
compared to 2002 was the same as for PE except that SoCalGas received
$34 million of the $97 million repayment from Sempra Energy in 2003 and
made $86 million of the $177 million in advances to Sempra Energy in
2002. Advances to Sempra Energy are payable on demand.

PE's increase in cash used in investing activities in 2002 compared to
2001 was primarily due to increased capital expenditures and advances
to Sempra Energy. PE advanced $177 million to Sempra Energy in 2002
compared to being repaid $220 million by Sempra Energy in 2001. For
SoCalGas, the change in 2002 compared to 2001 was the same as for PE,
except that SoCalGas advanced $86 million of the $177 million to Sempra
Energy in 2002 compared to being repaid $233 million by Sempra Energy
in 2001.

Capital Expenditures for Utility Plant

Capital expenditures were $318 million in 2003 compared to $331 million
and $294 million in 2002 and 2001, respectively. The increase in
capital expenditures in 2002 was primarily due to improvements to the
natural gas distribution system and expansion of pipeline capacity to
provide increased access to natural gas supplies to meet the
fluctuating demand patterns of electric generators and of commercial
and industrial customers. The expansion of SoCalGas' pipeline capacity
was completed in 2002.

Future Capital Expenditures

Significant capital expenditures in 2004 are expected to be for
improvements to the distribution and transmission systems. These
expenditures are expected to be financed by cash flows from operations
and security issuances.

Over the next five years, the company expects to make capital
expenditures of $1.7 billion consisting of $350 million in 2004, $300
million in 2005 and $350 million in each of 2006, 2007 and 2008.

Construction programs are periodically reviewed and revised by the
company in response to changes in economic conditions, competition,
customer growth, inflation, customer rates, the cost of capital, and
environmental and regulatory requirements.

CASH FLOWS FROM FINANCING ACTIVITIES

Net cash used in PE's consolidated financing activities totaled $149
million, $4 million and $418 million for 2003, 2002 and 2001,
respectively. Net cash used in SoCalGas' financing activities totaled
$96 million, $101 million and $411 million for 2003, 2002 and 2001,
respectively.

The increase in PE's cash used in financing activities in 2003 was
attributable to higher repayments on long-term debt and an increase of
$150 million in dividends paid to Sempra Energy in 2003, partially
offset by an increase in the issuances of long-term debt. The change in
SoCalGas' net cash used in financing activities was the same as for PE,

20

except for dividends paid to PE, which reflected no change from 2002 to
2003.

Net cash used in PE's consolidated financing activities decreased in
2002 compared to 2001 due primarily to the 2002 issuance of long-term
debt of $250 million, the decrease in common dividends paid and lower
debt repayments. The change in SoCalGas' net cash used in financing
activities was the same as for PE, except for the change in dividends
paid to PE, which reflected a $10 million increase in dividends paid to
PE from 2001 to 2002.

Long-Term and Short-Term Debt

In 2003, SoCalGas issued $500 million of first mortgage bonds.
Repayments on long-term debt in 2003 included $325 million of SoCalGas'
first mortgage bonds. In addition, $70 million of SoCalGas' $75 million
medium-term notes were also put back to the company. The remaining $5
million matures in 2028.

In January 2004, SoCalGas optionally redeemed its $175 million 6.875%
first mortgage bonds.

In October 2002, SoCalGas publicly offered and sold $250 million of
4.80% first mortgage bonds, maturing in October 2012. Repayments on
long-term debt in 2002 included $100 million of first mortgage bonds.
In 2002, cash was used for the repayment of $50 million of short-term
debt.

In 2001, repayments on long-term debt consisted of $150 million of
first mortgage bonds and $120 million of unsecured notes. Also in 2001,
SoCalGas had an increase of $50 million in short-term debt.

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

Dividends

Dividends paid to Sempra Energy amounted to $250 million in 2003
compared to $100 million in 2002 and $190 million in 2001. Dividends
paid by SoCalGas to PE amounted to $200 million, $200 million and $190
million in 2003, 2002 and 2001, 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,
2003, the company could have provided a total (combined loans and
dividends) of $175 million to Sempra Energy. At December 31, 2003,
SoCalGas had actual loans, net of payables, to Sempra Energy of $21
million.

Capitalization

Total capitalization, including the current portion of long-term debt
at December 31, 2003 was $2.6 billion, of which $2.3 billion applied to
SoCalGas. The debt-to-capitalization ratios were 36 percent and 41
percent at December 31, 2003 for PE and SoCalGas, respectively.

21

Significant changes in capitalization during 2003 included long-term
borrowings and repayments, income and dividends.

Commitments
The following is a summary of the company's principal contractual
commitments at December 31, 2003. 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.

Credit Ratings
Several credit ratings of the company declined in 2003, but remain
investment grade. As of January 31, 2004, company credit ratings were
as follows:

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

As of January 31, 2004, SoCalGas had a stable outlook rating from all
three credit rating agencies.

22

FACTORS INFLUENCING FUTURE PERFORMANCE

Performance of the companies will depend primarily on the ratemaking
and regulatory process, electric and natural gas industry restructuring
and the changing energy marketplace. These factors are discussed in
Note 9 of the notes to Consolidated Financial Statements.

Natural Gas Restructuring and Rates

In December 2001 the CPUC issued a decision related to natural gas
industry restructuring; however, implementation has been delayed. A
CPUC decision could be issued in the first quarter of 2004. With the
company's natural gas supply contracts nearing expiration, the company
believes that regulation needs to consider sufficiently the adequacy
and diversity of supplies to California, transportation infrastructure
and cost recovery thereof, hedging opportunities to reduce cost
volatility, and programs to encourage and reward conservation.
Additional information on natural gas industry restructuring is
provided in Note 9 of the notes to Consolidated Financial Statements.

CPUC Investigation of Compliance with Affiliate Rules

In February 2003, the CPUC opened an investigation of the business
activities of SDG&E, SoCalGas and Sempra Energy to ensure that they
have complied with statutes and CPUC decisions in the management,
oversight and operations of their companies. In September 2003, the
CPUC suspended the procedural schedule until it completes an
independent audit to evaluate energy-related holding company systems
and affiliate activities undertaken by Sempra Energy within the service
territories of SDG&E and SoCalGas. The audit, which will cover the
years 1997 through 2003, is expected to commence in March 2004 and to
be completed by the end of 2004. In accordance with existing CPUC
requirements, the California Utilities' transactions with other Sempra
Energy affiliates have been audited by an independent auditing firm
each year, with results reported to the CPUC, and there have been no
material adverse findings in those audits.

Cost of Service Filing

The California Utilities have filed cost of service applications with
the CPUC, seeking rate increases designed to reflect forecasts of 2004
capital and operating costs. SoCalGas is requesting revenue increases
of $45 million. On December 19, 2003, settlements were filed with the
CPUC for SoCalGas and for SDG&E that, if approved, would resolve most
of the cost of service issues. A CPUC decision is likely in the second
quarter of 2004. The California Utilities have also filed for
continuation through 2004 of existing PBR mechanisms for service
quality and safety that would otherwise expire at the end of 2003. In
January 2004, the CPUC issued a decision that extended 2003 service and
safety targets through 2004, but deferred action on applying any
rewards or penalties for performance relative to these targets to a
decision to be issued later in 2004 in a second phase of these
applications. This is discussed in Note 9 of the notes to Consolidated
Financial Statements.

23

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.

Sempra Energy has adopted corporate-wide policies governing its market
risk management activities. Assisted by Sempra Energy's Energy Risk
Management Group (ERMG), Sempra Energy's Energy Risk Management
Oversight Committee (ERMOC), consisting of senior officers, oversees
company-wide energy risk management activities and monitors the results
of activities to ensure compliance with the company's stated energy
risk management policies. Utility management receives daily information
on positions and the ERMG receives information detailing positions
creating market and credit risk for the company, consistent with
affiliate rules. The ERMG independently measures and reports the market
and credit risk associated with these positions. In addition, ERMOC
monitors energy price risk management activities independently from the
groups responsible for creating or actively managing these risks.

Along with other tools, the company uses Value at Risk (VaR) to measure
its exposure to market risk. VaR is an estimate of the potential loss
on a position or portfolio of positions over a specified holding
period, based on normal market conditions and within a given
statistical confidence interval. The company has adopted the
variance/covariance methodology in its calculation of VaR, and uses
both the 95-percent and 99-percent confidence intervals. VaR is
calculated independently by the ERMG for the company. Historical
volatilities and correlations between instruments and positions are
used in the calculation. As of December 31, 2003, the total VaR of the
company's natural gas positions was not material.

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

See the revenue recognition discussion in Note 1 and the additional
market risk information regarding derivative instruments in Note 7 of
the notes to Consolidated Financial Statements.

The following discussion of the company's primary market risk exposures
as of December 31, 2003 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.

24

The company's market risk exposure is limited due to CPUC authorized
rate recovery of natural gas purchase, sale, intrastate transportation
and storage activity. However, the company may, at times, be exposed to
market risk as a result of 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
framework. As of December 31, 2003, the company's exposure to market
risk was not material. However, if commodity prices rose too rapidly,
it is likely that volumes would decline. This would increase the per-
unit fixed costs, which could lead to further volume declines, leading
to increased per-unit fixed costs and so forth.

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. As a result, some
recent debt offerings have used a combination of fixed-rate and
floating-rate debt. Subject to regulatory constraints, interest-rate
swaps may be used to adjust interest-rate exposures when appropriate,
based upon market conditions.

At December 31, 2003, the company had $788 million of fixed-rate debt
and $150 million of 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, 2003, SoCalGas' fixed-rate debt had a one-year
VaR of $131 million and SoCalGas' variable-rate debt had a one-year VaR
of $10.9 million.

At December 31, 2003, the notional amount of interest-rate swap
transactions totaled $150 million. See Note 3 of the notes to
Consolidated Financial Statements for further information regarding
interest-rate swap transactions.

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

Credit Risk

Credit risk is the risk of loss that would be incurred as a result of
nonperformance by counterparties of their contractual obligations. As
with market risk, the company has adopted corporate-wide policies
governing the management of credit risk. Credit risk management is
performed by the ERMG and the company's credit department and overseen
by the ERMOC. Using rigorous models, the groups continuously calculate
current and potential credit risk to counterparties to monitor actual
balances in comparison to approved limits and reports this information
to the ERMG. The company avoids concentration of counterparties
whenever possible 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, the use of standardized agreements that
allow for the netting of positive and negative exposures associated

25

with a single counterparty and other security such as lock-box liens
and downgrade triggers.

The company monitors credit risk through a credit approval process and
the assignment and monitoring of credit limits. These credit limits are
established based on risk and return considerations under terms
customarily available in the industry.

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

CRITICAL ACCOUNTING POLICIES AND KEY NON-CASH PERFORMANCE INDICATORS

Certain accounting policies are viewed by management as critical
because their application is the most relevant, judgmental and/or
material to the company's financial position and results of operations,
and/or because they require the use of material judgments and
estimates.

The company's 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) 5, "Accounting
for Contingencies," establishes the amounts and timing of when
the company provides for contingent losses. Details of the
company's issues in this area are discussed in Note 10 of the
notes to Consolidated Financial Statements.

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

SFAS 109, "Accounting for Income Taxes," governs the way the
company provides for income taxes. Details of the company's
issues in this area are discussed in Note 4 of the notes to
Consolidated Financial Statements.

SFAS 123, "Accounting for Stock-Based Compensation" and SFAS 148,
"Accounting for Stock-Based Compensation - Transition and
Disclosure," give companies the choice of recognizing a cost at
the time of issuance of stock options or merely disclosing what
that cost would have been and not recognizing it in its financial
statements. Sempra Energy, like most U.S. companies, has elected
the disclosure option for all options that are so eligible. The
subsidiaries record an expense for the stock-based compensation
plans to the extent that subsidiary employees participate in the
plans, or that subsidiaries are allocated a portion of Sempra

26

Energy's cost of the plans. The effect of this is discussed in
Note 1 of the notes to Consolidated Financial Statements.

SFAS 133, "Accounting for Derivative Instruments and Hedging
Activities," SFAS 138, "Accounting for Certain Derivative
Instruments and Certain Hedging Activities" and SFAS 149,
"Amendment of Statement 133 on Derivative Instruments and Hedging
Activities", have a significant effect on the balance sheets of
the company but have no significant effect on its income
statements because of the principles contained in SFAS 71.

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

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

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

The likelihood of recovery of various deferred tax assets.

The probable costs to be incurred in the resolution of litigation.
Differences between estimates and actual amounts have had significant
impacts in the past and are likely to 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 receivables considers
the aging of the receivables, the creditworthiness of customers and the
enforceability of contracts, where applicable. The assumed
collectibility of regulatory assets considers legal and regulatory
decisions involving the specific items or similar items. The assumed
collectibility of other assets considers the nature of the item, the
enforceability of contracts where applicable, the creditworthiness of
the other parties and other factors. Costs to fulfill contracts that
are carried at fair value are based on prior experience. Actuarial
assumptions are based on the advice of the company's independent
actuaries. The likelihood of deferred tax recovery is based on analyses
of the deferred tax assets and the company's expectation of future
financial and/or taxable income, based on its strategic planning.

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

Key non-cash performance indicators for the company include numbers of
customers and quantities of natural gas sold. This information is
provided in "Introduction" and "Results of Operations."

27

NEW ACCOUNTING STANDARDS

Relevant pronouncements that have recently become effective and have
had a significant effect on the company are SFAS 143, 148, 149, 150 and
FIN 45. They are described in Note 1 of the notes to Consolidated
Financial Statements. Pronouncements that could have a material effect
on the company are described below.

SFAS 143, "Accounting for Asset Retirement Obligations": SFAS 143,
requires entities to record the fair value of liabilities for legal
obligations related to asset retirements in the period in which they
are incurred. It also requires the company to reclassify amounts
recovered in rates for future removal costs not covered by a legal
obligation from accumulated depreciation to a regulatory liability.

SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities": SFAS 149 amends and clarifies accounting for
derivative instruments, including certain derivative instruments
embedded in other contracts, and for hedging activities under SFAS 133.
Under SFAS 149 natural gas forward contracts that are subject to
unplanned netting (see Note 1 of the Notes to Consolidated Financial
Statements) do not qualify for the normal purchases and normal sales
exception. The company has determined that all natural gas contracts
are subject to unplanned netting and as such, these contracts will be
marked-to-market. Implementation of SFAS 149 on July 1, 2003 did not
have a material impact on reported net income.

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."

28

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, 2003
and 2002, 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, 2003. 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, 2003 and 2002, and the results of
their operations and their cash flows for each of the three years in
the period ended December 31, 2003, in conformity with accounting
principles generally accepted in the United States of America.

/S/ DELOITTE & TOUCHE LLP

San Diego, California
February 23, 2004

29

PACIFIC ENTERPRISES AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
(Dollars in millions)

30

PACIFIC ENTERPRISES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)

31

PACIFIC ENTERPRISES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)

32

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

33

PACIFIC ENTERPRISES AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
Years ended December 31, 2003, 2002 and 2001
(Dollars in millions)

34

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The Consolidated Financial Statements include the accounts of Pacific
Enterprises (PE or the company) and its subsidiary, Southern California
Gas Company (SoCalGas or the company). 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 substantially all of its non-utility business and
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, resulting in restoring $35 million and $18
million to shareholders' equity in 2001 and 2003, respectively. These
restorations did not affect the calculation of net income or
comprehensive income. The remaining liabilities will be resolved in
future years and 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.

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). SoCalGas and its

35

affiliate, San Diego Gas & Electric (SDG&E), are collectively referred
to herein as "the California Utilities."

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

Regulatory Balancing Accounts

The amounts included in regulatory balancing accounts at December 31,
2003 represent net payables (payables net of receivables) of $86
million and $184 million at December 31, 2003 and 2002, respectively.
The payables normally are returned by reducing future rates.

Balancing accounts provide a mechanism for charging utility customers
the amount actually incurred for certain costs, primarily commodity
costs. However, fluctuations in most operating and maintenance costs
affect earnings. The CPUC approved 100 percent balancing account
treatment for variances between forecast and actual for SoCalGas'
noncore revenues and throughput, eliminating the impact on earnings
from any throughput and revenue variances from adopted forecast levels.
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 and regulatory liabilities as discussed
above.

36

Regulatory assets (liabilities) as of December 31 relate to the
following matters:

(Dollars in millions) 2003 2002
- -----------------------------------------------------------------------

SoCalGas
- ---------
Fixed-price contracts and other derivatives $ 233 $ 325
Environmental remediation 44 43
Unamortized loss on retirement of debt - net 45 38
Cost of removal obligations* (1,392) (1,324)
Deferred taxes refundable in rates (192) (164)
Employee benefit costs (77) (142)
Other 8 8
--------- ---------
Total (1,331) (1,216)

PE - Employee benefit costs 72 80
--------- ---------
Total PE consolidated $ (1,259) $ (1,136)
========= =========
- -----------------------------------------------------------------------
* See discussion of SFAS 143 in "New Accounting Standards"

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

(Dollars in millions) 2003 2002
- -----------------------------------------------------------------------
SoCalGas
- --------
Current regulatory assets $ 93 $ 92
Noncurrent regulatory assets 148 233
Current regulatory liabilities -- (16)
Noncurrent regulatory liabilities (1,572) (1,525)
--------- ---------
Total (1,331) (1,216)

PE - Noncurrent regulatory assets 72 80
--------- ---------
Total PE consolidated $ (1,259) $ (1,136)
========= =========
- -----------------------------------------------------------------------

All of the assets either earn a return, generally at short-term rates,
or the cash has not yet been expended and the assets are offset by
liabilities that do not incur a carrying cost.

Cash and Cash Equivalents

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

37

Collection Allowances

The allowance for doubtful accounts was $4 million, $4 million and $14
million at December 31, 2003, 2002 and 2001, respectively. The company
recorded a provision (reduction thereof) for doubtful accounts of $3
million, ($5) million and $9 million in 2003, 2002 and 2001,
respectively.

Inventories

At December 31, 2003, inventory shown on the Consolidated Balance
Sheets included natural gas of $63 million and materials and supplies
of $11 million. The corresponding balances at December 31, 2002 were
$65 million and $11 million, respectively. Natural gas is valued by the
last-in first-out (LIFO) method. When the inventory is consumed,
differences between the LIFO valuation and replacement cost are
reflected in customer rates. Materials and supplies at SoCalGas are
generally valued at the lower of average cost or market.

Property, Plant and Equipment

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

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

Accumulated depreciation for natural gas utility plant at SoCalGas was
$2.7 billion and $2.6 billion at December 31, 2003 and 2002,
respectively. See discussion of SFAS 143 under "New Accounting
Standards." Depreciation expense is based on the straight-line method
over the useful lives of the assets, an average of 23 years in each of
2003, 2002 and 2001, or a shorter period prescribed by the CPUC. The
provision for depreciation as a percentage of average depreciable
utility plant was 4.36, 4.34 and 4.33 in 2003, 2002 and 2001,
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 - Net in the Statements of
Consolidated Income, although it is not a current source of cash.
AFUDC amounted to $12 million, $13 million and $8 million for 2003,
2002 and 2001, respectively.

Legal Fees

Legal fees that are associated with a past event and not expected to be
recovered in the future are accrued when it is probable that they will
be incurred.

38

Comprehensive Income

Comprehensive income includes all changes, except those resulting from
investments by owners and distributions to owners, in the equity of a
business enterprise from transactions and other events, including
foreign-currency translation adjustments, minimum pension liability
adjustments and certain hedging activities. The components of other
comprehensive income are shown in the Statements of Consolidated
Changes in Shareholders' Equity.

Revenues

Revenues of SoCalGas are primarily 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 recognized upon delivery. 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."

Transactions with Affiliates

At December 31, 2003, PE has intercompany receivables from Sempra
Energy and other affiliates of $73 million and $3 million,
respectively. The corresponding amounts at December 31, 2002 were $81
million and $2 million, respectively. Of the total balances, $22
million and $81 million were recorded at SoCalGas at December 31, 2003
and 2002, respectively. Such amounts are included in current assets
under the caption Due from 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 $354 million and $416 million at December 31, 2003 and 2002,
respectively, and are included in noncurrent assets as Due from
Unconsolidated Affiliates. PE also had $2 million and $3 million due
from other affiliates at December 31, 2003 and 2002, respectively.

In addition, PE had intercompany payables due to various affiliates of
$121 million and $96 million at December 31, 2003 and 2002,
respectively, which are reported as a current liability. These balances
are due on demand. Of the total balances, $55 million and $31 million
were recorded at SoCalGas at December 31, 2003 and 2002, respectively.

New Accounting Standards

SFAS 132 (revised 2003), "Employers Disclosures about Pensions and
Other Postretirement Benefits": This statement revised employers'
disclosures about pension plans and other postretirement benefit plans.
It requires disclosures beyond those in the original SFAS 132 about the
assets, obligations, cash flows and net periodic benefit cost of
defined benefit pension plans and other defined postretirement plans.
It does not change the measurement or recognition of those plans.

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

39

assets and the associated asset retirement costs. It 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.

On January 1, 2003, the company recorded asset retirement obligations
of $10 million associated with the future retirement of three storage
facilities.

The change in the asset retirement obligations for the year ended
December 31, 2003 is as follows (dollars in millions):

Balance as of January 1, 2003 $ --
Adoption of SFAS 143 10
Accretion expense 1
------
Balance as of December 31, 2003 $ 11*
======
* The current portion of the obligation is included in Other Current
Liabilities on the Consolidated Balance Sheets.

Had SFAS 143 been in effect on January 1, 2002, the asset retirement
obligation liability would have been $9 million as of that date.

Except for the items noted above, the company has determined that there
is no other material retirement obligation associated with tangible
long-lived assets.

Implementation of SFAS 143 has had no effect on results of operations
and is not expected to have a significant effect in the future.

In accordance with CPUC regulation the company collects estimated
removal costs in rates through depreciation. SFAS 143 also requires the
company to reclassify estimated removal costs, which have historically
been recorded in accumulated depreciation, to a regulatory liability.
At December 31, 2003 and 2002, these costs were $1.4 billion and $1.3
billion, respectively.

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." It
applies to all long-lived assets. Among other things 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. Adoption of this statement on January 1,
2002 had no impact on the company's financial statements.

SFAS 148, "Accounting for Stock-Based Compensation - Transition and
Disclosure": In December 2002, the FASB issued SFAS 148, an amendment

40

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.

Sempra Energy has elected to continue using the intrinsic value method
of accounting for stock-based compensation. Therefore, SFAS 148 will
not have any effect on the companies' financial statements. See Note 6
for additional information regarding stock-based compensation.

SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities": Effective July 1, 2003, SFAS 149 amended and
clarified accounting for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging
activities under SFAS 133. Under SFAS 149 natural gas forward contracts
that are subject to unplanned netting generally do not qualify for the
normal purchases and normal sales exception. ("Unplanned netting"
refers to situations whereby contracts are settled by paying or
receiving money for the difference between the contract price and the
market price at the date on which physical delivery would have
occurred.) In addition, effective January 1, 2004, power contracts that
are subject to unplanned netting and that do not meet the normal
purchases and normal sales exception under SFAS 149 will continue to be
marked to market. Implementation of SFAS 149 did not have a material
impact on reported net income.

Emerging Issues Task Force (EITF) 03-11, "Reporting Realized Gains and
Losses on Derivative Instruments that are Subject to FASB Statement No.
133, Accounting for Derivative Instruments and Hedging Activities and
Not 'Held for Trading Purposes' as Defined in EITF Issue No. 02-3,
Issues Involved in Accounting for Derivative Contracts Held for Trading
Purposes and Contracts Involved in Energy Trading and Risk Management
Activities": During 2003, the EITF reached a consensus that determining
whether realized gains and losses on physically settled derivative
contracts not held for trading purposes should be reported in the
income statement on a gross or net basis is a matter of judgment that
depends on the relevant facts and circumstances. Adoption of EITF 03-11
in 2003 did not have a significant impact to the company's financial
statements and the company does not expect a significant impact in the
future.

FASB Interpretation No. (FIN) 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees": In November 2002, the FASB
issued FIN 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. As of December 31, 2003, the company
did not have any outstanding guarantees.

FASB Staff Position (FSP) 106-1, "Accounting and Disclosure
Requirements Related to the Medicare Prescription Drug, Improvement and
Modernization Act of 2003": Issued January 12, 2004, FSP 106-1 permits
a sponsor of a postretirement health care plan that provides a

41

prescription drug benefit to make a one-time election to defer
accounting for the effects of the Medicare Prescription Drug,
Improvement and Modernization Act of 2003 (the Act). The company has
elected to defer the effects of the Act as provided by FSP 106-1. Any
measure of the accumulated postretirement benefit obligation or net
periodic postretirement benefit cost in the financial statements or the
accompanying notes do not reflect the impact of the Act on the plans.
At this time, specific authoritative guidance on the accounting for the
federal subsidy provided by the Act is pending and that guidance could
require the company to change previously reported information.

Other Accounting Standards: During 2003 and 2002 the FASB and the EITF
issued several statements that are not applicable to the companies but
could be in the future. In July 2001, the FASB issued SFAS 142,
"Goodwill and Other Intangible Assets." 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." SFAS 146 supersedes previous accounting guidance,
principally EITF 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (including
Certain Costs Incurred in a Restructuring)." In 2003 the FASB issued
SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of Both Liabilities and Equity." In 2002, consensuses
were reached in EITF 02-3 and the rescission of EITF 98-10, both
dealing with mark-to-market accounting for energy-trading activities.
In January 2003, the FASB issued Interpretation 46, "Consolidation of
Variable Interest Entities an Interpretation of ARB No. 51."

NOTE 2. SHORT-TERM BORROWINGS

Committed Lines of Credit

SoCalGas and its affiliate, SDG&E, have a combined revolving line of
credit, under which each utility individually may borrow up to $300
million, subject to a combined borrowing limit for both utilities of
$500 million. Borrowings under the agreement bear interest at rates
varying with market rates and SoCalGas' credit rating. The revolving
credit commitment expires in May 2004, at which time outstanding
borrowings may be converted into a one-year term loan subject to any
requisite regulatory approvals related to long-term debt. The agreement
requires SoCalGas to maintain a debt-to-total capitalization ratio (as
defined in the agreement) of not to exceed 60 percent. Borrowings under
the agreement are individual obligations of the borrowing utility and a
default by one utility would not constitute a default or preclude
borrowings by the other. These lines of credit have never been drawn
upon. At December 31, 2003 and 2002, SoCalGas had no commercial paper
outstanding.

PE has a $375 million revolving agreement, guaranteed by Sempra Energy,
for the purpose of providing loans to Sempra Energy Global Enterprises
(Global). The revolving credit commitment, initially $500 million and
$375 million at December 31, 2003, declines semi-annually by $125
million until expiration on April 5, 2005. Borrowings are guaranteed by
Sempra Energy and are subject to mandatory repayment prior to the
maturity date should SoCalGas' unsecured long-term credit ratings cease

42

to be at least BBB by Standard & Poor's (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, PE's credit ratings and the amount of outstanding
borrowings. This line of credit has never been used.

NOTE 3. LONG-TERM DEBT

- --------------------------------------------------------------
December 31,
(Dollars in millions) 2003 2002
- --------------------------------------------------------------
First Mortgage bonds
4.375% January 15, 2011 $ 100 $ --
Variable rates after fixed
to floating rate swaps (1.43% at
December 31, 2003) January 15, 2011 150 --
4.8% October 1, 2012 250 250
5.45% April 15, 2018 250 --
6.875% November 1, 2025 175 175
5.75% November 15, 2003 -- 100
7.375% March 1, 2023 -- 100
7.5% June 15, 2023 -- 125
-----------------------
925 750
-----------------------
Other long-term debt
5.67% January 18, 2028 5 75
6.375% May 14, 2006 8 8
-----------------------
13 83
-----------------------
938 833
Current portion of long-term debt (175) (175)
Unamortized discount on long-term debt (1) (1)
-----------------------
Total $ 762 $ 657
- --------------------------------------------------------------

Maturities of long-term debt are $175 million in 2004, $8 million in
2006 and $755 million thereafter. On January 26, 2004, SoCalGas
optionally redeemed its $175 million 6.875% first mortgage bonds.
Therefore that liability is classified as current at December 31, 2003.

Callable Bonds

At SoCalGas' option, certain bonds are callable at various dates. Of
SoCalGas' callable bonds, $175 million are callable in 2004 and $8
million in 2006.

First Mortgage Bonds

The first mortgage bonds are secured by a lien on SoCalGas' utility
plant. SoCalGas may issue additional first mortgage bonds upon

43

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, after
giving effect to prior bond redemptions. The most restrictive of these
tests (the property test) would permit the issuance, subject to CPUC
authorization, of an additional $490 million of first mortgage bonds at
December 31, 2003.

In November 2001, SoCalGas optionally redeemed its $150 million 8.75%
first mortgage bonds. In December 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. In
September 2002, SoCalGas terminated the swap, receiving cash proceeds
of $10 million, comprised of $4 million in accrued interest and a $6
million amortizable gain.

In August 2002, SoCalGas paid at maturity 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 redeemable prior to
maturity only through a make-whole mechanism. Proceeds from the bond
sale were used to replenish amounts previously expended to refund and
retire indebtedness, and for working capital and other general
corporate purposes.

On April 7, 2003, SoCalGas optionally redeemed its $100 million 7.375%
first mortgage bonds. On August 21, 2003, SoCalGas optionally redeemed
its $125 million 7.5% first mortgage bonds.

On October 17, 2003, SoCalGas issued $250 million of 5.45% first
mortgage bonds due in April 2018. The proceeds were used to replenish
amounts previously expended to refund and retire indebtedness and for
general corporate purposes. On November 17, 2003, SoCalGas paid off its
$100 million 5.75% first mortgage bonds.

On December 15, 2003, SoCalGas issued $250 million of 4.375% first
mortgage bonds maturing in January 2011. The proceeds were used to
retire outstanding debt and for other general corporate purposes. On
December 15, 2003, SoCalGas entered into an interest-rate swap which
effectively exchanged the fixed rate on $150 million of the 4.375%
first mortgage bonds for a floating rate.

Unsecured Long-term Debt

Various long-term obligations totaling $13 million are unsecured at
December 31, 2003.

In October 2001, SoCalGas paid at maturity its $120 million of 6.38%
medium-term notes.

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.

44

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. The schedule of long-term debt reflects past swap
interest rates. The company believes the swaps have been fully
effective in their purpose of converting the underlying debt's fixed
rates to floating rates and meet the criteria for accounting under one
of the methods defined in SFAS 133 for fair value hedges of debt
instruments.

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,
2003 2002 2001
- -----------------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Depreciation 6.1 5.2 5.4
State income taxes - net of
federal income tax benefit 5.8 5.4 6.9
Tax credits (0.8) (0.8) (0.8)
Settlement of Internal Revenue Service audit (3.1) -- --
Other - net (4.2) (0.4) (1.1)
--------------------------
Effective income tax rate 38.8% 44.4% 45.4%
- ----------------------------------------------------------------------

The components of income tax expense are as follows:

(Dollars in millions) 2003 2002 2001
- ---------------------------------------------------------------------
Current:
Federal $ 52 $ 94 $ 116
State 23 29 30
------------------------
Total 75 123 146
------------------------
Deferred:
Federal 58 45 20
State 10 5 8
------------------------
Total 68 50 28
------------------------
Deferred investment tax credits (3) (3) (3)
------------------------
Total income tax expense $ 140 $ 170 $ 171
- ---------------------------------------------------------------------

On the Statements of Consolidated Income, federal and state income
taxes are allocated between operating income and other income. The
companies are included in the consolidated income tax return of Sempra
Energy and are allocated income tax expense from Sempra Energy in an
amount equal to that which would result from their having always filed
a separate return.

45

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

(Dollars in millions) 2003 2002
- ----------------------------------------------------------------------
Deferred tax liabilities:
Differences in financial and
tax bases of utility plant $ 301 $ 290
Regulatory balancing accounts 93 54
Regulatory assets 32 32
Global settlement 15 11
Loss on reacquired debt 17 16
Unbilled revenue -- 36
Other 29 77
--------------------
Total deferred tax liabilities 487 516
--------------------
Deferred tax assets:
Investment tax credits 31 32
Postretirement benefits 77 100
Deferred compensation 19 13
State income taxes 11 20
Workers compensation 20 20
Contingent liabilities 95 117
Lease 18 21
Restructuring costs -- 42
Other 7 30
--------------------
Total deferred tax assets 278 395
--------------------
Net deferred income tax liability $ 209 $ 121
- ----------------------------------------------------------------------

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

(Dollars in millions) 2003 2002
- ----------------------------------------------------------------------
Current (asset) liability $ 24 $ (55)
Noncurrent liability 185 176
--------------------
Total $ 209 $ 121
- ----------------------------------------------------------------------

Resolution of Certain Internal Revenue Service Matters

The company favorably resolved matters related to various prior years'
returns during 2003. The primary issue involving the treatment of
utility balancing accounts for the company was resolved following the
issuance of an IRS Revenue Ruling and resolution of factual issues
involving these claims with the IRS. The total after-tax earnings for
this issue was $29 million.

46

NOTE 5. EMPLOYEE BENEFIT PLANS

Pension and Other Postretirement Benefits

The company has funded and unfunded noncontributory defined benefit
plans that together cover substantially all of its employees. The
plans provide defined benefits based on years of service and final
average salary.

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

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.

There were no amendments to the company's pension and other
postretirement benefit plans in 2003.

December 31 is the measurement date for the pension and other
postretirement benefit plans.

47

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

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

49

The significant assumptions related to the company's pension and other
postretirement benefit plans are as follows:

The expected long-term rate of return on plan assets is derived from
historical returns for broad asset classes consistent with expectations
from a variety of sources, including pension consultants and investment
advisors.

2003 2002
- ----------------------------------------------------------------------
ASSUMED HEALTH CARE COST
TREND RATES AT DECEMBER 31:
Health-care cost trend rate 30.00%(1) 7.00%
Rate to which the cost trend rate is assumed to
decline (the ultimate trend) 5.50% 6.50%
Year that the rate reaches the ultimate trend 2008 2004
- ----------------------------------------------------------------------
(1) This is the weighted average of the increases for all health plans.
The 2003 rate for these plans ranged from 15% to 40%.

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

- -----------------------------------------------------------------------
(Dollars in millions) 1% Increase 1% Decrease
- -----------------------------------------------------------------------
Effect on total of service and interest cost
components of net periodic postretirement
health-care benefit cost $ 12 $ (9)

Effect on the health-care component of the
accumulated other postretirement
benefit obligation $ 141 $ (112)
- -----------------------------------------------------------------------

50

Pension Plan Investment Strategy

The asset allocation for Sempra Energy's pension trust (which includes
SoCalGas' pension plan and other postretirement benefit plans, except
for the plans described below) at December 31, 2003 and 2002 and the
target allocation for 2004 by asset categories are as follows:

Target Percentage of Plan
Allocation Assets at December 31
-------------------------------------------
Asset Category 2004 2003 2002
- ----------------------------------------------------------------------
U.S. Equity 45% 45% 44%
Foreign Equity 25% 30% 26%
Fixed Income 30% 25% 30%
-------------------------------------------
Total 100% 100% 100%
- ----------------------------------------------------------------------

The company's goal is to remain within a reasonable risk tolerance
shown above. Its investment strategy is to stay fully invested at all
times and maintain its strategic asset allocation, keeping the
investment structure relatively simple. The equity portfolio is
balanced to maintain risk characteristics similar to the S&P 1500 with
respect to market capitalization, industry and sector exposures. The
foreign equity portfolios are managed to track the MSCI Europe, Pacific
Rim and Emerging Markets indexes. Bond portfolios are managed with
respect to the Lehman Aggregate Index. The plan does not invest in
Sempra Energy securities.

Investment Strategy for Other Postretirement Benefit Plans

The asset allocation for the company's other postretirement benefit
plans at December 31, 2003 and 2002 and the target allocation for 2004
by asset categories are as follows:

Target Percentage of Plan
Allocation Assets at December 31
-------------------------------------------
Asset Category 2004 2003 2002
- ----------------------------------------------------------------------
U.S. Equity 70% 71% 63%
Fixed Income 30% 27% 34%
Cash -- 2% 3%
-------------------------------------------
Total 100% 100% 100%
- ----------------------------------------------------------------------

The company's other postretirement benefit plans, which are distinct
from other postretirement benefit plans included in Sempra Energy's
pension trust (see above), are funded by cash contributions from the
company and the retirees. The asset allocation is designed to match the
long-term growth of the plan's liability. This plan is managed using
100% index funds.

Future Payments

The company expects to contribute $1 million to the pension plan and
$55 million to its other postretirement benefit plans in 2004.

51

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

Other
(Dollars in millions) Pension Benefits Postretirement Benefits
- -----------------------------------------------------------------------
2004 $ 98 $ 27
2005 $ 103 $ 32
2006 $ 107 $ 35
2007 $ 113 $ 37
2008 $ 118 $ 39
Thereafter $ 669 $ 219

Savings Plan

The company offers trusteed savings plan to all eligible employees.
Eligibility to participate in the plan is immediate for salary
deferrals. Employees may contribute, subject to plan provisions, from
one percent to 25 percent of their regular earnings. After one year of
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 or until the
employee's attainment of age 55, when they may be transitioned into
other investments. 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 plan were $9 million in
2003, $8 million in 2002 and $7 million in 2001.

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. 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

52

expenses of $9 million, $1 million and $3 million in 2003, 2002 and
2001, 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, and
customer deposits) approximate their carrying amounts. The following
table provides the carrying amounts and fair values of the remaining
financial instruments at December 31:

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

Accounting for Derivative Instruments and Hedging Activities

The company follows the guidance of SFAS 133 and related amendments
SFAS 138 and 149 (collectively SFAS 133) to account for its derivative
instruments and hedging activities. Derivative instruments and related
hedges are recognized as either assets or liabilities on the balance
sheet, measured at fair value. Changes in the fair value of derivatives
are recognized in earnings in the period of change unless the
derivative qualifies as an effective hedge that offsets certain
exposure.

SFAS 133 provides for hedge accounting treatment when certain criteria
are met. For derivative instruments designated as fair value hedges,
the gain or loss is recognized in earnings in the period of change
together with the offsetting gain or loss on the hedged item
attributable to the risk being hedged. For derivative instruments
designated as cash flow hedges, the effective portion of the derivative
gain or loss is included in other comprehensive income, but not
reflected in the Statements of Consolidated Income until the

53

corresponding hedged transaction is settled. The ineffective portion is
reported in earnings immediately. There was no effect on other
comprehensive income for the year ended December 31, 2003. For the year
ended December 31, 2002 the effect was not material. In instances where
derivatives do not qualify for hedge accounting, gains and losses are
recorded in the Statements of Consolidated Income.

The company utilizes natural gas derivatives to manage commodity price
risk associated with servicing their load requirements. These contracts
allow the company to predict with greater certainty the effective
prices to be received by the company and the prices to be charged to
its customers. The use of derivative financial instruments is subject
to certain limitations imposed by company policy and regulatory
requirements. The company classifies its forward contracts as follows:

Contracts that meet the definition of normal purchase and sales
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 under accrual
accounting and recorded in Revenues or Cost of Natural Gas in the
Statement of Consolidated Income when physical delivery occurs. Due to
the adoption of SFAS 149, the company has determined that its natural
gas contracts entered into after June 30, 2003 generally do not qualify
for the normal purchases and sales exception.

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

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

(Dollars in millions) 2003 2002
- -----------------------------------------------------------------------
Fixed-priced contracts and other derivatives:
Current liabilities $ 86 $ 96
Noncurrent liabilities 148 233
----- -----
Net liabilities $ 234 $ 329
===== =====

54

Regulatory assets and liabilities related to derivatives held by
SoCalGas are as follows:

(Dollars in millions) 2003 2002
- -----------------------------------------------------------------------
Regulatory assets and liabilities:
Current regulatory assets $ 85 $ 92
Noncurrent regulatory assets 148 233
----- -----
Net regulatory assets $ 233 $ 325
===== =====

The above had no impact on net income during 2003 and resulted in
$3 million of losses in 2002.

Market Risk

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

Interest-Rate Risk Management

The company periodically enters into interest-rate swap agreements to
moderate exposure to interest-rate changes and to lower the overall
cost of borrowing. This is described in Note 3.

Energy Contracts

SoCalGas records transactions for natural gas contracts in Cost of
Natural Gas 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 this account 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) 2003 2002
- -----------------------------------------------------------------
$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
- ----------------------------------------------------------------

55

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.

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

Natural Gas Industry Restructuring

In December 2001 the CPUC issued a decision related to natural gas
industry restructuring (GIR), with implementation anticipated during
2002. On January 12, 2004, after many delays and changes, an
administrative Law Judge issued a proposed decision that would
implement the 2001 decision. The proposed decision would result in
revising noncore balancing account treatment to exclude the balancing
of SoCalGas' transmission costs; other noncore costs/revenues would
continue to be fully balanced until the decision in the next Biennial
Cost Allocation Proceeding (BCAP) (see below). On February 11, 2004, a
member of the CPUC issued an alternative decision that would vacate the
December 2001 decision and defer GIR matters to the Natural Gas Market
Order Instituting Ratemaking (OIR)(see below). A CPUC decision could be
issued in March 2004.

Natural Gas Market OIR

The OIR concerning the Natural Gas Market was approved on January 22,
2004, and will be addressed in two concurrent phases. The schedule
calls for a Phase I decision by summer 2004 and a Phase II decision by
the end of 2004. In Phase I the CPUC's objective is to develop a
process enabling the CPUC to review and pre-approve new interstate
capacity contracts before they are executed. In addition, the
California Utilities must submit proposals on any liquefied natural gas

56

project to which interconnection is planned, providing costs and terms,
including access to the pipelines in Mexico. Phase II will primarily
address emergency reserves and ratemaking policies. The OIR invites
proposals on how utilities should provide emergency reserves consisting
of slack intrastate pipeline capacity, contracts for additional
capacity on the interstate pipelines and an emergency supply of natural
gas storage. The CPUC's objective in the ratemaking policy component of
Phase II is to identify and propose changes to policies that create
incentives that are consistent with the goal of providing adequate and
reliable long-term supplies and that do not conflict with energy
efficiency programs. The focus of the Gas OIR is 2006 to 2016. Since
GIR (see above) would end in August 2006 and there is overlap between
GIR and the Gas OIR issues, a number of parties (including SoCalGas)
are advising the CPUC not to implement GIR.

The company believes that regulation needs to consider sufficiently the
adequacy and diversity of supplies to California, transportation
infrastructure and cost recovery thereof, hedging opportunities to
reduce cost volatility, and programs to encourage and reward
conservation.

Cost of Service

The California Utilities have filed cost of service applications with
the CPUC, seeking rate increases reflecting forecasts of 2004 capital
and operating costs. SoCalGas is requesting revenue increases of $45
million. The CPUC's Office of Ratepayer Advocates (ORA) filed its
prepared testimony on the applications in August 2003, recommending
numerous rate decreases that would reduce annual revenues by $121
million from their current level. The Utility Reform Network has
proposed rates for SoCalGas that would reduce annual revenues by $178
million from their current level. Hearings concluded in November 2003.
On December 19, 2003, settlements were filed with the CPUC that, if
approved, would resolve most of the cost of service issues. The
SoCalGas settlement was signed by SoCalGas and all parties active in
its application. The CPUC adopted a schedule for briefing and
commenting on the proposed settlements that concluded on February 19,
2004. The SoCalGas settlement would reduce rates by $33 million from
2003 rates. The CPUC may accept one or both of the settlements or may
adopt an outcome differing from both of the settlements. Resolution is
likely in the second quarter of 2004.

On December 18, 2003, the CPUC issued a decision that creates
memorandum accounts as of January 1, 2004, to record the difference
between actual revenues and those that are later authorized in the
CPUC's final decision in this case. The difference would then be
amortized in rates. The California Utilities have also filed for
continuation through 2004 of existing performance-based regulation
(PBR) mechanisms for service quality and safety that would otherwise
expire at the end of 2003. In January 2004, the CPUC issued a decision
that extended 2003 service and safety targets through 2004, but
deferred action on applying any rewards or penalties for performance
relative to these targets to a decision to be issued later in 2004 in a
second phase of these applications discussed below.

The CPUC has established a procedural schedule for the second phase of
these applications, addressing issues related to PBR (see below). The

57

procedural schedule calls for hearings to be held in June 2004, with a
decision during 2004. The scope of the second phase includes: (a) a
formula for setting authorized cost of service for 2005 and succeeding
years until the next full cost of service proceeding is scheduled; (b)
whether and how rates should be adjusted if earned returns vary from
authorized returns; and (c) prospective targets and rewards/penalties
for service quality and safety.

An October 2001 decision denied the California Utilities' request to
continue equal sharing between ratepayers and shareholders of the
estimated savings for the 1998 business combination that created Sempra
Energy and, instead, ordered that all of the estimated 2003 merger
savings go to ratepayers. In 2002, merger savings to shareholders for
the fourth quarter and for the year were $4 million and $17 million,
respectively. Pursuant to the decision, SoCalGas will return the 2003
merger savings related to natural gas operations of $83 million to
ratepayers over a twelve-month period beginning January 1, 2004.

Performance-Based Regulation

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.

PBR consists of three primary components. The first is a mechanism to
adjust rates in years between general rate cases or cost of service
cases. Similar to the pre-PBR Attrition Proceeding, it annually adjusts
general rates from those of the prior year to provide for inflation,
changes in the number of customers and efficiencies.

The second component is a mechanism whereby any earnings in excess of
those authorized plus a narrow band above that are shared with
customers in varying degrees depending upon the amount of the
additional earnings.

The third component consists of a series of measures of utility
performance. Generally, if performance is outside of a band around the
specified benchmark, the utility is rewarded or penalized certain
dollar amounts.

The three areas that are eligible for PBR rewards or penalties are
operational incentives based on measurements of safety, reliability and
customer satisfaction; demand-side management (DSM) rewards based on
the effectiveness of the programs; and natural gas procurement rewards
or penalties. The CPUC is also considering a new reward/penalty related
to electricity procurement, now that the utilities are resuming this
activity. However, as noted under Cost of Service, Phase II of the
California Utilities' current cost of service proceeding is not
scheduled for completion until late 2004. As a result, it is possible
that some or all of the safety, reliability and customer satisfaction
incentive mechanisms (i.e., those that are reviewed in the cost of
service proceeding) would not be in effect for 2004. Even if that were

58

to occur, it is not expected that the effect would be other than a one-
year moratorium on the mechanisms.

The Gas Cost Incentive Mechanism (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
savings within a tolerance band below the benchmark price. The costs
outside the tolerance band are shared between customers and
shareholders.

Since the 1990s, investor-owned utilities (IOUs) have been eligible to
earn awards for implementing and administering energy conservation and
efficiency programs. The California Utilities have offered these
programs to customers and have consistently achieved significant
earnings from the program. On October 16, 2003, the CPUC issued a
decision that the pre-1998 DSM earnings proceeding would not be
reopened, leaving the earnings mechanism unchanged. The CPUC may adjust
amounts determined pursuant to the earnings mechanism consistent with
the application of known, standard measurement and verification
protocols.

The CPUC has consolidated the 2000, 2001 and 2002 award applications.
The 2003 award applications were filed on May 1, 2003. On May 2, 2003,
the CPUC released Requests for Proposals to conduct a review of the
IOUs' studies and reported program milestones/accomplishments used as
the basis for the awards claims and program expenditures. The review
should be completed in the second quarter of 2004. Additionally, the
low-income awards will be subject to an independent review expected to
commence in 2005. The majority of the outstanding claims are on hold
pending completion of the independent review.

Incentive Awards Approved in 2003

PBR and GCIM rewards are not included in the company's earnings before
CPUC approval is received. The following table reflects awards approved
in 2003 (dollars in millions):

Program
-----------------------------------
GCIM Year 7 $ 30.8
GCIM Year 8 17.4
Employee Safety PBR 2000 0.1
Employee Safety PBR 2001 0.5
Employee Safety PBR 2002 0.5
-----------------------------------
Total $ 49.3
===================================

59

Pending Incentive Awards

At December 31, 2003, the following performance incentives were pending
CPUC approval and, therefore, were not included in the company's
earnings (dollars in millions):

Program
-----------------------------------
GCIM Year 9 $ 6.3
DSM/Energy Efficiency* 9.8
-----------------------------------
Total $ 16.1
===================================

* Dollar amounts shown do not include interest, franchise fees or
uncollectible amounts.

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 is 8.68
percent. These rates will continue to be effective until market
interest-rate changes are large enough to trigger an automatic
adjustment or until the CPUC orders a periodic review.

SoCalGas' automatic adjustment mechanism provides for a trigger in any
month when the 12-month trailing average of 30-year Treasury bond rates
varies by greater than 150 basis points from the benchmark, and the
current Global Insight forecast of the 30-year Treasury bond rate 12
months ahead varies by greater than 150 basis points from the
benchmark. When these criteria are met, SoCalGas' authorized ROE is
adjusted by one-half of the difference between the trailing 12-month
average and the benchmark, and the embedded costs of debt and preferred
equity are adjusted to current levels. Any time an automatic adjustment
occurs, the new trailing 12-month average becomes the new benchmark.
The benchmark is currently 5.38 percent, the 12-month trailing average
of the 30-year Treasury bond as of October 2002. At December 31, 2003,
the 12-month average of the 30-year Treasury bond was 4.92 percent and
the estimated Global Insight year-ahead forecast was 5.90 percent and,
therefore, no triggering has occurred. The rates have not changed
significantly since then.

Border Price Investigation

In November 2002, the CPUC instituted an investigation into the
Southern California natural gas market and the price of natural gas
delivered to the California-Arizona border between March 2000 and May
2001. If the investigation determines that the conduct of any party to
the investigation contributed to the natural gas price spikes, the CPUC
may modify the party's natural gas procurement incentive mechanism,
reduce the amount of any shareholder award for the period involved,
and/or order the party to issue a refund to ratepayers. On December 10,
2003, Southern California Edison filed testimony alleging that SoCalGas
significantly contributed to the price spikes and exercised market
power and recommended to the CPUC that SoCalGas divest its storage
assets and revise its GCIM to an incentive mechanism that would simply
reward SoCalGas if it managed to procure natural gas supplies in the

60

producing basins at a price below market. Hearings are scheduled to
begin in late March 2004 with a decision expected by late 2004. The
company believes that the CPUC will find that SoCalGas acted in the
best interests of its core customers.

Biennial Cost Allocation Proceeding

The BCAP determines the allocation of authorized costs between customer
classes for natural gas transportation service provided by the company
and adjusts rates to reflect variances in customer demand as compared
to the forecasts previously used in establishing transportation rates.
SoCalGas filed with the CPUC its 2005 BCAP application in September
2003, requesting updated transportation rates effective January 1,
2005. The most recent BCAP decision allocating the California Utilities
non-commodity natural gas costs of service and revising their
respective natural gas transportation rates and rate designs was issued
in April 2000 and is still in effect. In November 2003, an Assigned
Commissioner Ruling delayed the current BCAP applications until a
decision is issued in the GIR implementation proceeding discussed
above. As a result, SoCalGas is required to amend its BCAP application
within 21 days of a decision in the GIR. As a result of the deferrals
and the forecasted significant decline in noncore gas throughput on
SoCalGas' system, in December 2002 the CPUC issued a decision approving
100 percent balancing account protection for SoCalGas' risk on local
transmission and distribution revenues from January 1, 2003 until the
CPUC issues its next BCAP decision. SoCalGas is seeking to continue
this balancing account protection through 2006. A CPUC decision on GIR
could result in revising noncore balancing account treatment to exclude
the balancing of transmission costs; other noncore costs/revenues would
continue to be fully balanced until the BCAP decision.

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. In January 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. In
January 2002 the CPUC ruled on jurisdictional issues, deciding that it
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. On November 26, 2003 the California
Court of Appeal agreed to hear the company's appeal. Oral argument is
set for March 5, 2004.

61

CPUC Investigation of Compliance with Affiliate Rules

In February 2003, the CPUC opened an investigation of the business
activities of SDG&E, SoCalGas and Sempra Energy to determine if they
have complied with statutes and CPUC decisions in the management,
oversight and operations of their companies. In September 2003, the
CPUC suspended the procedural schedule until it completes an
independent audit to evaluate energy-related holding company systems
and affiliate activities undertaken by Sempra Energy within the service
territories of SDG&E and SoCalGas. The audit will cover the years 1997
through 2003, is expected to commence in March 2004 and should be
completed by the end of 2004. The scope of the audit will be broader
than the annual affiliate audit. In accordance with existing CPUC
requirements, the California Utilities' transactions with other Sempra
Energy affiliates have been audited by an independent auditing firm
each year, with results reported to the CPUC, and there have been no
material adverse findings in those audits.

FERC Standards of Conduct

On November 25, 2003, the FERC established standards of conduct
governing the relationship between transmission providers and their
energy affiliates. They broaden the definition of an energy affiliate.
Under the standards, SDG&E is a transmission provider and SoCalGas is
an energy affiliate of SDG&E. The standards require transmission
providers to offer service to all customers on a non-discriminatory
basis.

NOTE 10. COMMITMENTS AND CONTINGENCIES

Natural Gas Contracts

SoCalGas buys natural gas under short-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 with
pipeline companies for firm pipeline capacity under contracts that
expire at various dates through 2007.

At December 31, 2003, the future minimum payments under natural gas
storage and transportation contracts were:

- ---------------------------------------------------------------------
Natural
(Dollars in millions) Transportation Gas Total
- ---------------------------------------------------------------------
2004 $ 200 $ 633 $ 833
2005 191 3 194
2006 104 3 107
2007 2 2 4
2008 -- 3 3
Thereafter -- -- --
-------------------------------------------
Total minimum payments $ 497 $ 644 $ 1,141
- ---------------------------------------------------------------------

62

Total payments under natural gas contracts were $1.8 billion in 2003,
$1.2 billion in 2002 and $2.1 billion in 2001.

Leases

PE and SoCalGas have operating leases on real and personal property
expiring at various dates from 2004 to 2030. Certain leases on office
facilities contain escalation clauses requiring annual increases in
rent ranging from 3 percent to 5 percent. The rentals payable under
these leases are determined on both fixed and percentage bases, and
most leases contain extension options which are exercisable by the
companies.

At December 31, 2003, the minimum rental commitments payable in future
years under all noncancellable leases were as follows:

- -----------------------------------------------------------------
(Dollars in millions) PE SoCalGas
- -----------------------------------------------------------------
2004 $ 56 $ 43
2005 55 42
2006 54 41
2007 58 45
2008 58 44
Thereafter 151 130
---------------------
Total future rental commitments $ 432 $ 345
- -----------------------------------------------------------------

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 $35
million at December 31, 2003. These leases are included in the above
table at the amounts provided in the lease.

Rent expense for operating leases totaled $56 million in 2003, $54
million in 2002 and $51 million in 2001, which included rent expense
for SoCalGas of $43 million, $42 million and $39 million, respectively.

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

63

capitalized. The company's capital expenditures to comply with
environmental laws and regulations were $6 million in 2003, $4 million
in 2002 and $4 million in 2001. 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 expectation 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 (26 completed as of December
31, 2003 and 16 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, 2003, the company's
accrued liability for environmental matters was $43.8 million, of which
$42.9 million related to manufactured-gas sites, and $0.9 million to
waste-disposal sites used by the company (which has been identified as
a PRP). The accruals for the manufactured-gas and waste-disposal sites
are expected to be paid ratably over the next three years.

Litigation

During 2003, the company recorded $32 million of after-tax charges
related to litigation costs and a sublease. Management believes that
none of these matters will have further material adverse effect on the
company's financial condition or results of operations. Except for the
matters referred to below, 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.

Antitrust Litigation

Class-action and individual lawsuits filed in 2000 and currently
consolidated in San Diego Superior Court seek damages, alleging that
Sempra Energy, SoCalGas and SDG&E, along with El Paso Energy Corp. (El
Paso) and several of its affiliates, unlawfully sought to control
natural gas and electricity markets. In March 2003, plaintiffs in these
cases and the applicable El Paso entities announced that they had
reached a $1.5 billion settlement, of which $125 million is allocated
to customers of the California Utilities. The Court approved that
settlement in December 2003. The proceeding against Sempra Energy and
the California Utilities has not been settled and continues to be
litigated.

64

Natural Gas Cases: Similar lawsuits have been filed by the Attorneys
General of Arizona and Nevada, alleging that El Paso and certain Sempra
Energy subsidiaries unlawfully sought to control the natural gas market
in their respective states. In April 2003, Sierra Pacific Resources and
its utility subsidiary Nevada Power filed a lawsuit in U.S. District
Court in Las Vegas against major natural gas suppliers, including
Sempra Energy, the California Utilities and other company subsidiaries,
seeking damages resulting from an alleged conspiracy to drive up or
control natural gas prices, eliminate competition and increase market
volatility, breach of contract and wire fraud. On January 27, 2004, the
U.S. District Court dismissed the Sierra Pacific Resources case against
all of the defendants, determining that this is a matter for the FERC.

Price Reporting Practices

In the fourth quarter of 2002, Sempra Energy and SoCalGas were named as
defendants in a lawsuit filed in Los Angeles Superior Court against
various trade publications and other energy companies alleging that
energy prices were unlawfully manipulated by defendants' reporting
artificially inflated natural gas prices to trade publications. On July
8, 2003, the Superior Court granted the defendants' demurrer on the
grounds that the claims contained in the complaint were subject to the
Filed Rate Doctrine and were preempted by the Federal Power Act.
Plaintiffs filed an amended complaint, and in September 2003 defendants
filed a demurrer to the amended complaint, which was granted in part.
In December 2003, the plaintiffs dismissed both Sempra Energy and
SoCalGas from the lawsuit.

In January 2004, the Commodity Futures Trading Commission (CFTC)
issued a subpoena to SoCalGas and Sempra Energy Trading (SET) in
connection with the CFTC's "Activities Affecting the Price of Natural
Gas in the Fall of 2003" investigation. The company is cooperating with
the CFTC in the investigation.

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.

65

NOTE 11. QUARTERLY FINANCIAL DATA (UNAUDITED)

66

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, 2003 and 2002, 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, 2003. 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, 2003 and 2002, and the
results of their operations and their cash flows for each of the three
years in the period ended December 31, 2003, in conformity with
accounting principles generally accepted in the United States of
America.

/S/ DELOITTE & TOUCHE LLP

San Diego, California
February 23, 2004

67

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

68

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

69

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

70

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

71

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
Years ended December 31, 2003, 2002 and 2001
(Dollars in millions)

72

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,
2003 2002 2001
- -----------------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Depreciation 6.1 5.1 5.3
State income taxes - net of
federal income tax benefit 5.9 7.0 6.7
Tax credits (0.8) (0.8) (0.8)
Settlement of Internal Revenue Service audit (3.1) -- --
Other - net (1.4) (0.8) (1.4)
----------------------------
Effective income tax rate 41.7% 45.5% 44.8%
- -----------------------------------------------------------------------

73

The components of income tax expense are as follows:
- ---------------------------------------------------------------------
(Dollars in millions) 2003 2002 2001
- ----------------------------------------------------------------------
Current:
Federal $ 55 $ 107 $ 126
State 24 39 34
------------------------
Total 79 146 160
------------------------
Deferred:
Federal 63 33 8
State 11 2 4
------------------------
Total 74 35 12
------------------------
Deferred investment tax credits (3) (3) (3)
-------------------------
Total income tax expense $ 150 $ 178 $ 169
- ----------------------------------------------------------------------

On the Statements of Consolidated Income, 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 SoCalGas' having always filed a
separate return.

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

(Dollars in millions) 2003 2002
- ----------------------------------------------------------------------
Deferred tax liabilities:
Differences in financial and
tax bases of utility plant $ 304 $ 258
Regulatory balancing accounts 93 54
Global settlement 15 11
Loss on reacquired debt 17 16
Unbilled revenue -- 36
Other -- 23
--------------------
Total deferred tax liabilities 429 398
--------------------
Deferred tax assets:
Investment tax credits 31 32
Postretirement benefits 45 56
Deferred compensation 14 13
State income taxes 19 20
Workers compensation 20 20
Contingent liabilities 82 107
Other 4 --
--------------------
Total deferred tax assets 215 248
--------------------
Net deferred income tax liability $ 214 $ 150
- ----------------------------------------------------------------------

74

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

(Dollars in millions) 2003 2002
- ----------------------------------------------------------------------
Current (asset) liability $ 15 $ (87)
Noncurrent liability 199 237
--------------------
Total $ 214 $ 150
- ----------------------------------------------------------------------

NOTE 5. EMPLOYEE BENEFIT PLANS

Pension and Other Postretirement Benefits

The company has funded and unfunded noncontributory defined benefit
plans that together cover substantially all of its employees. The
plans provide defined benefits based on years of service and final
average salary.

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

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.

There were no amendments to the company's pension and other
postretirement benefit plans in 2003.

December 31 is the measurement date for the pension and other
postretirement benefit plans.

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

75

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

The significant assumptions related to the company's pension and other
postretirement benefit plans are as follows:

The expected long-term rate of return on plan assets is derived from
historical returns for broad asset classes consistent with expectations
from a variety of sources, including pension consultants and investment
advisors.

77

2003 2002
- ------------------------------------------------------------------------
ASSUMED HEALTH CARE COST
TREND RATES AT DECEMBER 31:
Health-care cost trend rate 30.00%(1) 7.00%
Rate to which the cost trend rate is assumed to
decline (the ultimate trend) 5.50% 6.50%
Year that the rate reaches the ultimate trend 2008 2004
- ------------------------------------------------------------------------
(1) This is the weighted average of the increases for all health plans.
The 2003 rate for these plans ranged from 15% to 40%.

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

- ------------------------------------------------------------------------
(Dollars in millions) 1% Increase 1% Decrease
- ------------------------------------------------------------------------
Effect on total of service and interest cost
components of net periodic postretirement
health-care benefit cost $ 12 $ (9)

Effect on the health-care component of the
accumulated other postretirement
benefit obligation $ 141 $ (112)
- ------------------------------------------------------------------------

Pension Plan Investment Strategy

The asset allocation for Sempra Energy's pension trust (which includes
SoCalGas' pension plan and other postretirement benefit plans, except
for the plans described below) at December 31, 2003 and 2002 and the
target allocation for 2004 by asset categories are as follows:

Target Percentage of Plan
Allocation Assets at December 31
-------------------------------------------
Asset Category 2004 2003 2002
- -----------------------------------------------------------------------
U.S. Equity 45% 45% 44%
Foreign Equity 25% 30% 26%
Fixed Income 30% 25% 30%
-------------------------------------------
Total 100% 100% 100%
- -----------------------------------------------------------------------

The company's investment strategy is to stay fully invested at all
times and maintain its strategic asset allocation, keeping the
investment structure relatively simple. The equity portfolio is
balanced to maintain risk characteristics similar to the S&P 1500 with
respect to market capitalization, industry and sector exposures. The
foreign equity portfolios are managed to track the MSCI Europe, Pacific
Rim and Emerging Markets indexes. Bond portfolios are managed with
respect to the Lehman Aggregate Index. The plan does not invest in
Sempra Energy securities.

78

Investment Strategy for Other Postretirement Benefit Plans

The asset allocation for the company's other postretirement benefit
plans at December 31, 2003 and 2002 and the target allocation for 2004
by asset categories are as follows:

Target Percentage of Plan
Allocation Assets at December 31
-------------------------------------------
Asset Category 2004 2003 2002
- -----------------------------------------------------------------------
U.S. Equity 70% 71% 63%
Fixed Income 30% 27% 34%
Cash -- 2% 3%
-------------------------------------------
Total 100% 100% 100%
- -----------------------------------------------------------------------

The company's other postretirement benefit plans, which are distinct
from other postretirement benefit plans included in Sempra Energy's
pension trust (see above), are funded by cash contributions from the
company and the retirees. The asset allocation is designed to match the
long-term growth of the plan's liability. This plan is managed using
100% index funds.

Future Payments

The company expects to contribute $1 million to the pension plan and
$55 million to its other postretirement benefit plans in 2004

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

Other
(Dollars in millions) Pension Benefits Postretirement Benefits
- -----------------------------------------------------------------------
2004 $ 98 $ 27
2005 $ 103 $ 32
2006 $ 107 $ 35
2007 $ 113 $ 37
2008 $ 118 $ 39
Thereafter $ 669 $ 219

Savings Plan

The company offers trusteed savings plan to all eligible employees.
Eligibility to participate in the plan is immediate for salary
deferrals. Employees may contribute, subject to plan provisions, from
one percent to 25 percent of their regular earnings. After one year of
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 or until the

79

employee's attainment of age 55, when they may be transitioned into
other investments. 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 $9 million in
2003, $8 million in 2002 and $7 million in 2001.

NOTE 8. PREFERRED STOCK

- ------------------------------------------------------------------
December 31,
(Dollars in millions) 2003 2002
- ------------------------------------------------------------------
$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.

NOTE 11. QUARTERLY FINANCIAL DATA (UNAUDITED)

80

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

The companies have designed and maintain disclosure controls and
procedures to ensure that information required to be disclosed in the
companies' 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 companies'
management, including their Chief Executive Officers and Chief
Financial Officers, 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.

Under the supervision and with the participation of management,
including the Chief Executive Officers and the Chief Financial
Officers, the companies as of December 31, 2003 have evaluated the
effectiveness of the design and operation of the companies' disclosure
controls and procedures. Based on that evaluation, the companies' Chief
Executive Officers and Chief Financial Officers have concluded that the
controls and procedures are effective.

There have been no significant changes in the companies' internal
controls or in other factors that could significantly affect the
internal controls subsequent to the date the companies completed their
evaluations.

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 2004 annual meeting of shareholders. The
information required on the companies' executive officers is set forth
below.

81

EXECUTIVE OFFICERS OF THE REGISTRANT
Name Age* Position
- -------------------------------------------------------------------
Pacific Enterprises --

Stephen L. Baum 62 Chairman, Chief Executive
Officer and President

M. Javade Chaudhri 51 Executive Vice President and
General Counsel

Neal E. Schmale 57 Executive Vice President and
Chief Financial Officer

Frank H. Ault 59 Senior Vice President and
Controller

Charles A. McMonagle 53 Vice President and Treasurer

Thomas C. Sanger 60 Corporate Secretary

Southern California Gas Company --

Edwin A. Guiles 54 Chairman and Chief Executive
Officer

Debra L. Reed 47 President and Chief Financial
Officer

Steven D. Davis 47 Senior Vice President, Customer
Service and External Relations

Margot A. Kyd 50 Senior Vice President, Corporate
Business Solutions

Roy M. Rawlings 59 Senior Vice President,
Distribution Operations

William L. Reed 51 Senior Vice President, Regulatory
Affairs

Lee M. Stewart 58 Senior Vice President, Gas
Transmission

Terry M. Fleskes 47 Vice President and Controller

* As of December 31, 2003.

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. Chaudhri. Prior to joining the company in 2003, Mr. Chaudhri was
Senior Vice President and General Counsel of Gateway, Inc. Each
executive officer of Southern California Gas Company holds the same
position at San Diego Gas & Electric Company.

82

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 2004 annual meeting of shareholders.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS

The security ownership information required by Item 12 is incorporated
by reference from "Share Ownership" in the Information Statement
prepared for the May 2004 annual meeting of shareholders.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information regarding principal accountant fees and services as
required by Item 14 is incorporated by reference from "Proposal 3:
Ratification of Independent Auditors" in the Proxy Statement prepared
for the May 2004 annual meeting of shareholders.

83

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 . . . . . . . . 28

Pacific Enterprises Statements of Consolidated Income
for the years ended December 31, 2003, 2002 and 2001 . . . . . . . 29

Pacific Enterprises Consolidated Balance Sheets
at December 31, 2003 and 2002. . . . . . . . . . . . . . . . . . . 30

Pacific Enterprises Statements of Consolidated Cash Flows
for the years ended December 31, 2003, 2002 and 2001 . . . . . . . 32

Pacific Enterprises Statements of Consolidated Changes in
Shareholders' Equity for the years ended
December 31, 2003, 2002 and 2001 . . . . . . . . . . . . . . . . . 33

Pacific Enterprises Notes to Consolidated
Financial Statements . . . . . . . . . . . . . . . . . . . . . . . 34

Independent Auditors' Report for Southern California Gas
Company. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

SoCalGas Statements of Consolidated Income for the years
ended December 31, 2003, 2002 and 2001 . . . . . . . . . . . . . . 67

SoCalGas Consolidated Balance Sheets at December 31,
2003 and 2002. . . . . . . . . . . . . . . . . . . . . . . . . . . 68

SoCalGas Statements of Consolidated Cash Flows for the
years ended December 31, 2003, 2002 and 2001 . . . . . . . . . . . 70

SoCalGas Statements of Consolidated Changes in
Shareholders' Equity for the years ended
December 31, 2003, 2002 and 2001 . . . . . . . . . . . . . . . . . 71

SoCalGas Notes to Consolidated Financial Statements. . . . . . . . . 72

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. . . . . . . . 86

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.

84

3. Exhibits

See Exhibit Index on page 90 of this report.

(b) Reports on Form 8-K

The following reports on Form 8-K were filed after September 30, 2003:

Current Report on Form 8-K filed November 6, 2003, filing as an exhibit
Sempra Energy's press release of November 6, 2003, giving the financial
results for the three months ended September 30, 2003.

Current Report on Form 8-K filed December 15, 2003, announcing Southern
California Gas Company's sale of $250,000,000 of 4.375-percent First
Mortgage Bonds.

Current Report on Form 8-K filed February 24, 2004, filing as an
exhibit Sempra Energy's press release of February 24, 2004, giving the
financial results for the three months ended December 31, 2003.

85

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 23, 2004, appearing in the Annual Report on Form 10-K of
Pacific Enterprises for the year ended December 31, 2003.

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 24, 2004

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 23, 2004, appearing in
the Annual Report on Form 10-K of Southern California Gas Company for
the year ended December 31, 2003.

/S/ DELOITTE & TOUCHE LLP

San Diego, California
February 24, 2004

86

Schedule I -- CONDENSED FINANCIAL INFORMATION OF PARENT

PACIFIC ENTERPRISES

Condensed Statements of Income
(Dollars in millions)

Condensed Balance Sheets
(Dollars in millions)

87

PACIFIC ENTERPRISES
Schedule 1 (continued)
Condensed Financial Information of Parent

88

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, President
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.

89

SIGNATURES

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

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.

90

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
(2001 Form 10-K Exhibit 3.02).

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 (2001 Form 10-K Exhibit 3.04).

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).

91

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

10.02 2003 Executive Incentive Plan (June 30, 2003 Sempra Energy
Form 10-Q Exhibit 10.1).

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

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

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

92

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

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

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

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

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

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

10.12 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, 2003, 2002, 2001, 2000
and 1999.

12.02 Southern California Gas Company Computation of Ratio of Earnings
to Fixed Charges for the years ended December 31, 2003, 2002,
2001, 2000 and 1999.

Exhibit 21 -- Subsidiaries

21.01 Pacific Enterprises Schedule of Subsidiaries at December 31, 2003.

21.02 Southern California Gas Company Schedule of Subsidiaries at
December 31, 2003.

Exhibit 23 -- Independent Auditor's Consents, page 85.

Exhibit 31 -- Section 302 Certifications

31.1 Statement of PE's Chief Executive Officer pursuant
to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

31.2 Statement of PE's Chief Financial Officer pursuant
to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

31.3 Statement of SoCalGas' Chief Executive Officer pursuant
to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

93

31.4 Statement of SoCalGas' Chief Financial Officer pursuant
to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

Exhibit 32 -- Section 906 Certifications

32.1 Statement of PE's Chief Executive Officer pursuant
to 18 U.S.C. Sec. 1350.

32.2 Statement of PE's Chief Financial Officer pursuant
to 18 U.S.C. Sec. 1350.

32.3 Statement of SoCalGas' Chief Executive Officer pursuant
to 18 U.S.C. Sec. 1350.

32.4 Statement of SoCalGas' Chief Financial Officer pursuant
to 18 U.S.C. Sec. 1350.

94

GLOSSARY

AFUDC Allowance for Funds Used During Construction

BCAP Biennial Cost Allocation Proceeding

Bcf One Billion Cubic Feet (of natural gas)

CEMA Catastrophic Event Memorandum Act

CFTC Commodity Futures Trading Commission

CPUC California Public Utilities Commission

DSM Demand Side Management

EITF Emerging Issues Task Force

El Paso El Paso Energy Corp.

EG Electric Generation

Enova Enova Corporation

ERMG Energy Risk Management Group

FASB Financial Accounting Standards Board

FERC Federal Energy Regulatory Commission

Gas OIR Natural Gas Market Order Instituting Ratemaking

GCIM Gas Cost Incentive Mechanism

GIR Gas Industry Restructuring

Global Sempra Energy Global Enterprises

IRS Internal Revenue Service

IOUs Investor-Owned Utilities

MGP Manufactured-Gas Plants

mmbtu Million British Thermal Units (of natural gas)

Moody's Moody's Investor Services, Inc.

ORA Office of Ratepayer Advocates

PBR Performance-Based Regulation

PE Pacific Enterprises

PRP Potentially Responsible Party

95

RD&D Research Development and Demonstration

ROE Return on Equity

ROR Rate on Rate Base

S&P Standard & Poor's

SDG&E San Diego Gas & Electric Company

SEC Securities and Exchange Commission

SFAS Statement of Financial Accounting Standards

SoCalGas Southern California Gas Company

VaR Value at Risk