SOUTHERN CALIFORNIA GAS CO - 10-K Annual Report

Back to GetFilings.com

SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[X] Annual report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the fiscal year ended December 31, 1998
--------------------
OR
[ ] Transition report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934 for the transition period from
to
- ------ -------
SOUTHERN CALIFORNIA GAS COMPANY
- -------------------------------------------------------------------
(Exact name of registrant as specified in its charter)

CALIFORNIA 1-1402 95-1240705
- -------------------------------------------------------------------
(State of incorporation (Commission (I.R.S. Employer
or organization) File Number) Identification No.

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
- ------------------- ---------------------
Preferred Stock Pacific
First Mortgage Bonds:
Series Y, due 2021
Series Z, due 2002
Series BB, due 2023 New York
Series DD, due 2023
Series EE, due 2025
Series FF, due 2003

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

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

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

Exhibit Index on page 53. Glossary on page 56.

Aggregate market value of the voting preferred stock held by non-
affiliates of the registrant as of March 26, 1999 was
$19.9 million.

Registrant's common stock outstanding as of March 26, 1999 was
wholly owned by Pacific Enterprises.

DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Information Statement prepared for the May 1999
annual meeting of shareholders are incorporated by reference into
Part III.

TABLE OF CONTENTS

PART I
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . 3
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . 11
Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . . 11
Item 4. Submission of Matters to a Vote of Security Holders. . 11
Executive Officers of the Registrant . . . . . . . . . 12

PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . . 12
Item 6. Selected Financial Data. . . . . . . . . . . . . . . . 13
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . 13
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk . . . . . . . . . . . . . . . . . 26
Item 8. Financial Statements and Supplementary Data. . . . . . 27
Item 9. Changes In and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . 50

PART III
Item 10. Directors and Executive Officers of the Registrant . . 50
Item 11. Executive Compensation . . . . . . . . . . . . . . . . 50
Item 12. Security Ownership of Certain Beneficial Owners
and Management. . . . . . . . . . . . . . . . . . . 51
Item 13. Certain Relationships and Related Transactions . . . . 51

PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . . 51

Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . 52

Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . 53

Glossary. . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

This report includes forward-looking statements within the
definition of Section 27A of the Securities Act of 1933 and Section
21E of the Securities Exchange Act of 1934. The words "estimates,"
"believes," "expects," "anticipates," "plans" and "intends,"
variations of such words, and similar expressions, are intended to
identify forward-looking statements that involve risks and
uncertainties which could cause actual results to differ materially
from those anticipated.

These statements are necessarily based upon various assumptions
involving judgments with respect to the future including, among
others, local, regional, national and international economic,
competitive, political and regulatory conditions and developments,
technological developments, capital market conditions, inflation
rates, interest rates, energy markets, weather conditions, business
and regulatory or legal decisions, the pace of deregulation of
retail natural gas and electricity industries, the timing and
success of business development efforts, and other uncertainties,
all of which are difficult to predict and many of which are beyond
the control of the Company. Accordingly, while the Company believes
that the assumptions are reasonable, there can be no assurance that
they will approximate actual experience, or that the expectations
will be realized. Readers are urged to carefully review and
consider the risks, uncertainties and other factors which affect
the Company's business described in this annual report and other
reports filed by the Company from time to time with the Securities
and Exchange Commission.

PART I

ITEM 1. BUSINESS

DESCRIPTION OF BUSINESS

Southern California Gas Company (SoCalGas or the Company) is the
nation's largest natural gas distribution utility, serving 4.8
million meters throughout most of southern California and part of
central California. SoCalGas is the principal subsidiary of Pacific
Enterprises (PE). Effective June 26, 1998, PE and Enova Corporation
(Enova) combined to form Sempra Energy, a California-based Fortune
500 energy-services company (PE/Enova Business Combination). San
Diego Gas & Electric Company (SDG&E), an operating public utility
providing electric and natural gas services to San Diego County and
southern Orange County, is the principal subsidiary of Enova.
Further discussion of SoCalGas and the PE/Enova Business
Combination are included in "Management's Discussion and Analysis
of Financial Condition and Results of Operations" and in Note 1 of
the "Notes to Consolidated Financial Statements," herein.

GOVERNMENT REGULATION

Local Regulation
SoCalGas has gas franchises with the 236 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. Most of the franchises do not
have fixed terms and continue indefinitely. The range of expiration
dates for the franchises with definite terms is 2003 to 2041.

State Regulation
The California Public Utilities Commission (CPUC) regulates
SoCalGas' rates and conditions of service, sales of securities,
rate of return, rates of depreciation, uniform systems of accounts,
examination of records, and long-term resource procurement. The
CPUC also conducts various reviews of utility performance and
conducts investigations into various matters, such as deregulation,
competition and the environment, to determine its future policies.

Federal Regulation
The Federal Energy Regulatory Commission (FERC) regulates the
interstate sale and transportation of natural gas, the uniform
systems of accounts and rates of depreciation.

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 throughout this report.

SOURCES OF REVENUE

(In Millions of Dollars) 1998 1997 1996
- -------------------------------------------------------------------
Revenue by type of customer:

Gas Sales, Transportation & Exchange-

Residential $ 1,987 $ 1,736 $ 1,613
Commercial/Industrial 727 757 709
Utility Electric Generation 66 76 70
Wholesale 66 67 70
--------- --------- ----------
2,846 2,636 2,462
Balancing and Other (419) 5 (40)
--------- --------- ----------
Total Gas Revenues $ 2,427 $ 2,641 $ 2,422
========= ========= ==========

Industry segment information is contained in "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" and in Note 12 of the "Notes to Consolidated Financial
Statements" herein.

NATURAL GAS OPERATIONS

UTILITY SERVICES
SoCalGas distributes natural gas throughout a 23,000-square-mile
service territory with a population of approximately 17.6 million
people. Its service territory includes most of southern California
and part of central California.

The Company offers two basic utility services, sale of natural gas
and transportation of natural gas, through two business units. One
business unit focuses on core distribution customers and the other
on large volume gas transportation customers. Natural gas service
is also provided on a wholesale basis to the distribution systems
of the City of Long Beach, affiliated company SDG&E and Southwest
Gas Corporation.

Supplies of Natural Gas
The Company buys natural gas under several short-term and long-term
contracts. Short-term purchases are based on monthly-spot-market
prices. The Company has pipeline capacity contracts with pipeline
companies that expire at various dates through 2006.

Most of the natural gas purchased and delivered by the Company is
produced outside of California. These supplies are delivered to the
Company's intrastate transmission system by interstate pipeline
companies, primarily El Paso Natural Gas Company and Transwestern
Natural Gas Company. These interstate companies provide
transportation services for supplies purchased from other sources
by the Company or its transportation customers. The rates that
interstate pipeline companies may charge for natural gas and
transportation services are regulated by the FERC. Existing
pipeline capacity into California exceeds current demand by over 1
billion cubic feet (bcf) per day. The implications of this excess
are described in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" herein.

The following table shows the sources of natural gas deliveries
from 1994 through 1998.

Year Ended December 31
-------------------------------------------------------------------
1998 1997 1996 1995 1994
- -------------------------------------------------------------------------------------------------------------

Gas Purchases (billions of cubic feet)
Market 270 229 226 206 247
Affiliates 101 95 96 99 101
California Producers &
Federal Offshore 3 5 12 29 36
------- ------- ------- ------- -------
Total Gas Purchases 374 329 334 334 384

Customer-Owned and Exchange Receipts
Affiliates 116 100 96 89 93
Other 521 514 422 531 565

Storage Withdrawal
(Injection) - Net (28) (3) 42 (13) (9)

Company Use and
Unaccounted For (21) (10) (10) (4) (13)
------- ------- ------- ------- -------
Net Deliveries 962 930 884 937 1,020
======= ======= ======= ======= =======
Cost of Gas Purchased (millions of dollars)
Commodity Costs $ 774 $ 849 $ 627 $ 478 $ 644

Fixed Charges* 174 250 276 264 368
------- ------- ------- ------- -------
Total Gas Purchases $ 948 $1,099 $ 903 $ 742 $1,012
======= ======= ======= ======= =======
Average Cost of Gas Purchased
(dollars per thousand cubic feet)** $2.07 $ 2.58 $1.88 $1.42 $ 1.68
======= ======= ======= ======= =======

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

** The average commodity cost of natural gas purchased excludes fixed charges.

Market sensitive natural gas supplies (supplies purchased on the
spot market as well as under longer-term contracts ranging from one
month to ten years based on spot prices) accounted for 72 percent
of total natural gas volumes purchased by the Company during 1998,
as compared with 70 percent and 68 percent during 1997 and 1996,
respectively. These supplies were generally purchased at prices
significantly below those of long-term sources of supply.

During 1998, the Company delivered 962 bcf of natural gas through
its system. Approximately 66 percent of these deliveries were
customer-owned natural gas for which the Company provided
transportation services. The balance of natural gas deliveries was
gas purchased by the Company and resold to customers. The Company
estimates that sufficient natural gas supplies will be available to
meet the requirements of its customers for the next several years.

Customers
For regulatory purposes, customers are separated into core and
noncore customers. Core customers are primarily residential and
small commercial and industrial customers, without alternative
fuel capability. There are approximately 4.8 million core
customers (4.6 million residential and 200,000 small commercial
and industrial). Noncore customers consist primarily of utility
electric generation (UEG), wholesale, and large commercial and
industrial customers, and total approximately 1,600.

Most core customers purchase natural gas directly from the Company.
Core aggregate transportation customers are permitted to aggregate
their natural gas requirement and, up to a CPUC-imposed limit of 10
percent of the Company's core market, to purchase natural gas
directly from brokers or producers. The Company continues to be
obligated to purchase reliable supplies of natural gas to serve the
requirements of its core customers. However, the only natural gas
supplies that the Company may offer for sale to noncore customers
are the same supplies that it purchases for its core customers.

Noncore customers have the option of purchasing natural gas
either from the Company or from other sources, such as brokers
or producers, for delivery through the Company's transmission
and distribution system. Most noncore customers procure their
own natural gas supply.

For 1998, approximately 87 percent of the CPUC-authorized
natural gas margin was allocated to the core customers, with 13
percent allocated to the noncore customers.

Although revenue from transportation throughput is less than for
natural gas sales, the Company generally earns the same margin
whether the Company buys the gas and sells it to the customer or
transports natural gas already owned by the customer.

The Company also provides natural gas storage services for noncore
and off-system customers on a bid and negotiated contract basis.
The storage service program provides opportunities for customers to
store natural gas on an "as available" basis, usually during the
summer to reduce winter purchases when natural gas costs are
generally higher. As of December 31, 1998, the Company stored
approximately 26 bcf of customer-owned gas.

Demand for Natural Gas
Natural gas is a principal energy source for residential,
commercial, industrial and UEG customers. Natural gas competes with
electricity for residential and commercial cooking, water heating,
space heating and clothes drying, and with other fuels for large
industrial, commercial and UEG uses. Growth in the natural gas
markets is largely dependent upon the health and expansion of the
southern California economy. The Company added approximately 46,000
new meters in 1998. This represents a growth rate of approximately
0.9 percent. The Company expects its growth for 1999 will continue
at about the 1998 level.

During 1998, 97 percent of residential energy customers in the
Company's service area used natural gas for water heating, 94
percent for space heating, 78 percent for cooking and 72 percent
for clothes drying.

Demand for natural gas by noncore customers is very sensitive to
the price of alternative competitive fuels. Although the number of
noncore customers in 1998 was only 1,600, it accounted for 13
percent of the authorized natural gas revenues and 62 percent of
total natural gas volumes. External factors such as weather,
electric deregulation, the increased use of hydro-electric power,
competing pipeline bypass and general economic conditions can
result in significant shifts in this market. Natural gas demand for
big UEG customers is also greatly affected by the price and
availability of electric power generated in other areas and
purchased by the Company's UEG customers. Natural gas demand in
1998 for UEG customer use decreased as a result of decreased demand
for electricity. UEG customer demand increased in 1997 as a result
of higher demand for electricity and less availability of hydro-
electricity.

As a result of electric industry restructuring, natural gas
demand for electric generation within southern California
competes with electric power generated throughout the western
United States. Effective March 31, 1998, California consumers
were given the option of selecting their electric energy
provider from a variety of local and out-of-state producers.
Although the electric industry restructuring has no direct
impact on the Company's natural gas operations, future volumes
of natural gas transported for UEG customers may be adversely
affected to the extent that regulatory changes divert
electricity from the Company's service area.

Other
Additional information concerning customer demand and other aspects
of natural gas operations is provided under "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" and in Notes 10 and 11 of the "Notes to Consolidated
Financial Statements" herein.

RATES AND REGULATION

SoCalGas is regulated by the CPUC, which consists of five
commissioners appointed by the Governor of California for staggered
six-year terms. Two of the five commissioner positions are
currently vacant. It is the responsibility of the CPUC to determine
that utilities operate within the best interests of their
customers. The regulatory structure is complex and has a
substantial impact on SoCalGas' profitability. The natural gas
industry is currently undergoing transitions to competition (see
below).

Natural Gas Industry Restructuring
The natural gas industry experienced an initial phase of
restructuring during the 1980s by deregulating natural gas sales to
noncore customers. In January 1998, the CPUC released a staff
report initiating a project to assess the current market and
regulatory framework for California's natural gas industry. The
general goals of the plan are to consider reforms to the current
regulatory framework emphasizing market-oriented policies
benefiting California natural gas customers. Additional information
on natural gas industry restructuring is discussed in "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" and in Note 11 of the "Notes to Consolidated Financial
Statements" herein.

Balancing Accounts
In general, earnings fluctuations from changes in the costs of
natural gas and consumption levels for the majority of natural gas
are eliminated by balancing accounts authorized by the CPUC.
Additional information on balancing accounts is discussed in
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" and in Note 2 of the "Notes to Consolidated
Financial Statements" herein.

Performance-Based Regulation (PBR)
To promote efficient operations and improved productivity and to
move away from reasonableness reviews and disallowances, the CPUC
has been directing utilities to use PBR. PBR has replaced the
general rate case and certain other regulatory proceedings for
SoCalGas. Under PBR, regulators require future income potential to
be tied to achieving or exceeding specific performance and
productivity measures, as well as cost reductions, rather than
relying solely on expanding utility rate base in a market where a
utility already has a highly developed infrastructure. Additional
information on PBR is discussed in "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and in
Note 11 of the "Notes to Consolidated Financial Statements" herein.

Biennial Cost Allocation Proceeding (BCAP)
Rates to recover the changes in natural gas fuel costs and changes
in the cost of natural gas transportation services are determined
in the BCAP. The BCAP adjusts rates to reflect variances in core
customer demand from estimates previously used in establishing core
customer rates. The mechanism substantially eliminates the effect
on core income of variances in core market demand and natural gas
costs subject to the limitations of the Gas Cost Incentive
Mechanism (GCIM) discussed below. The BCAP will continue under PBR.
Additional information on the BCAP is discussed in "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" and in Note 11 of the "Notes to Consolidated Financial
Statements" herein.

Gas Cost Incentive Mechanism (GCIM)
The GCIM is a process SoCalGas uses to evaluate its natural gas
purchases, substantially replacing the previous process of
reasonableness reviews. Additional information on the GCIM is
discussed in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and in Note 11 of the "Notes
to Consolidated Financial Statements" herein.

Affiliate Transactions
In December 1997, the CPUC adopted rules establishing uniform
standards of conduct governing the manner in which California
investor-owned utilities conduct business with their affiliates.
The objective of these rules is to ensure that the utilities'
energy affiliates do not gain an unfair advantage over other
competitors in the marketplace and that utility customers do not
subsidize affiliate activities. Additional information on affiliate
transactions is discussed in "Management's Discussion and Analysis
of Financial Condition and Results of Operations" and in Note 11 of
the "Notes to Consolidated Financial Statements" herein.

Cost of Capital
Under PBR, annual Cost of Capital proceedings have been replaced by
an automatic adjustment mechanism if changes in certain indices
exceed established tolerances. For 1999, SoCalGas is authorized to
earn a rate of return on rate base of 9.49 percent and a rate of
return on common equity of 11.6 percent, the same as in 1998,
unless interest-rate changes are large enough to trigger an
automatic adjustment. Additional information on the utilities' cost
of capital is discussed in "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and in Note 11 of
the "Notes to Consolidated Financial Statements" herein.

ENVIRONMENTAL MATTERS

Discussions about environmental issues affecting SoCalGas,
including hazardous substances, are included in "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" herein. The following should be read in conjunction
with those discussions.

Hazardous Substances
The utility lawfully disposed of wastes at 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, redevelopment agencies are authorized
to require landowners to cleanup property within their jurisdiction
or, where the landowner or operator of such a facility fails to
complete any corrective action required, applicable environmental
laws may impose an obligation to undertake corrective actions on
the utilities and others who disposed of hazardous wastes at the
facility.

SoCalGas has been named as a potential responsible party (PRP) for
two landfill sites and two industrial waste disposal sites, as
described below.

The Casmalia former waste disposal site operated as a Class I waste
disposal site which was composed of 6 landfills, 58 surface
impoundments, 11 disposal wells, 7 disposal trenches, 2 treatment
systems and one former pre-Resource Conservation and Recovery Act
drum burial area. The utility has estimated the costs of
remediation at Casmalia to be $0.7 million. In 1998, SoCalGas
completed work efforts of $82,000. Remedial actions and
negotiations with other PRPs and the United States Environmental
Protection Agency (EPA) have been continuing since March 1993.
SoCalGas is currently negotiating a final remedy with the EPA for
Operating Industries, Inc. (OII), a former landfill for both
household and industrial wastes. The total costs for remediation of
OII are estimated at $3 million, of which $0.6 million was
completed during 1998. Remedial actions and negotiations have been
in progress since June 1986.

In the early 1990s, SoCalGas was notified of hazards at two former
industrial waste treatment facilities, Industrial Waste Processing
(Industrial) and Cal Compact (Compact), where SoCalGas had disposed
of wastes. A feasibility study and remedial investigation have been
submitted and accepted by the EPA for Industrial. The total cost
estimate for remediation of Industrial is $300,000, of which $4,000
of remedial action was completed in 1998. The nature and extent for
remediation of the Compact site indicates an estimated cost of
$120,000. During 1998, the utility completed remedial efforts of
this site at a cost of $50,000 and is involved in ongoing
negotiations with the California Department of Toxic Substances
Control.

At December 31, 1998, the utility's estimated remaining
investigation and remediation liability related to hazardous waste
sites not detailed above was $68 million, of which 90 percent is
authorized to be recovered through the Hazardous Waste
Collaborative mechanism. SoCalGas believes that any costs not
ultimately recovered through rates, insurance or other means, upon
giving effect to previously established liabilities, will not have
a material adverse effect on the Company's consolidated results of
operations or financial position.

Estimated liabilities for environmental remediation are recorded
when amounts are probable and estimable. Amounts authorized to be
recovered in rates under the Hazardous Waste Collaborative
mechanism are recorded as a regulatory asset. Possible recoveries
of environmental remediation liabilities from third parties are not
deducted from the liability.

OTHER

Year 2000
A discussion of the Company's plans to prepare its computer systems
and applications for the year 2000 and beyond is included in
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" herein.

Research, Development and Demonstration (RD&D)
The SoCalGas RD&D portfolio is focused in five major areas:
Operations, Utilization Systems, Power Generation, Public Interest
and Transportation. Each of these activities provides benefits to
customers and society by providing more cost-effective, efficient
natural gas equipment with lower emissions, increased safety and
reduced environmental mitigation and other utility operating costs.
The CPUC has authorized SoCalGas to recover its operating cost
associated with RD&D. An annual average of $7.7 million has been
spent for the last three years.

Employees of Registrant
As of December 31, 1998 SoCalGas had 6,148 employees, compared to
6,615 at December 31, 1997. This decrease is related to synergies
resulting from the PE/Enova Business Combination and the shifting
of certain functions to Sempra Energy.

Field, technical and most clerical employees of SoCalGas are
represented by the Utility Workers' Union of America or the
International Chemical Workers' Council. The collective bargaining
agreement on wages, hours and working conditions remains in effect
through March 31, 2000.

ITEM 2. PROPERTIES

Natural Gas Properties
At December 31, 1998, SoCalGas owned 2,857 miles of transmission
and storage pipeline, 44,097 miles of distribution pipeline and
43,825 miles of service piping. It also owned 10 transmission
compressor stations and 6 underground storage reservoirs (with a
combined working storage capacity of approximately 116 Bcf).

Other Properties
Southern California Gas Tower, a wholly owned subsidiary of
SoCalGas, has a 15-percent limited partnership interest in a 52-
story office building in downtown Los Angeles. SoCalGas leases
approximately half of the building through the year 2011. The lease
has six separate five-year renewal options.

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

ITEM 3. LEGAL PROCEEDINGS

Except for the matters referred to in the financial statements in
Item 8 or referred to elsewhere in this Annual Report, neither the
Company nor any of its affiliates is a party to, nor is its
property the subject of, any material pending legal proceedings
other than routine litigation incidental to its businesses.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
ITEM 4. EXECUTIVE OFFICERS OF THE REGISTRANT

Name Age* Positions
- -------------------------------------------------------------------
Warren I. Mitchell 61 Chairman and President

Lee M. Stewart 53 Senior Vice President and
Corporate Secretary;
President-Energy Transportation
Services

Debra L. Reed 42 Senior Vice President and
Chief Financial Officer;
President-Energy Distribution
Services

Richard M. Morrow 49 Vice President

Roy M. Rawlings 54 Vice President

Anne S. Smith 45 Vice President

George E. Strang 59 Vice President

* As of December 31, 1998

Each Executive Officer has been an officer of SoCalGas for more
than five years.

PART II

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

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

Dividend Restrictions
The CPUC regulates SoCalGas' capital structure, limiting the
dividends it may pay. At December 31, 1998, $233 million of
SoCalGas' retained earnings was available for future dividends.

ITEM 6. SELECTED FINANCIAL DATA

(Dollars in millions)

At December 31, or for the years then ended
------------------------------------------------
1998 1997 1996 1995 1994
-------- ------- ------- ------- -------

Income Statement Data:
Operating Revenues $2,427 $2,641 $2,422 $2,279 $2,587
Operating Income $ 238 $ 318 $ 286 $ 300 $ 279
Dividends on Preferred Stock $ 1 $ 7 $ 8 $ 12 $ 10
Earnings Applicable to
Common Shares $ 158 $ 231 $ 193 $ 203 $ 180

Balance Sheet Data:
Total Assets $3,834 $4,205 $4,354 $4,462 $4,776
Long-Term Debt $ 967 $ 968 $1,090 $1,220 $1,397
Short-Term Debt (a) $ 75 $ 498 $ 409 $ 329 $ 364
Shareholders' Equity $1,382 $1,467 $1,487 $1,645 $1,674

(a) Includes bank and other notes payable, commercial paper borrowings
and long-term debt due within one year.

Since SoCalGas is a wholly owned subsidiary of Pacific Enterprises, per share data
has been omitted.

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

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

Introduction
This section includes management's analysis of operating results
from 1996 through 1998, and is intended to provide additional
information about the capital resources, liquidity and financial
performance of Southern California Gas Company (SoCalGas or the
Company). This section also focuses on the major factors expected
to influence future operating results and discusses investment and
financing plans. It should be read in conjunction with the
Consolidated Financial Statements.
SoCalGas is the nation's largest natural gas distribution
utility, and owns and operates a natural gas distribution,
transmission and storage system supplying natural gas in 535 cities
and communities throughout a 23,000 square-mile service territory
comprising most of southern and part of central California. The
Company is the principal subsidiary of Pacific Enterprises (PE or
the Parent), which is wholly owned by Sempra Energy. The Company
provides natural gas service to residential, commercial,
industrial, utility electric generation and wholesale customers
through 4.8 million meters in a service area with a population of
17.6 million.

Business Combination
Sempra Energy was formed to serve as a holding company for the
Parent and Enova Corporation (the parent company of San Diego Gas &
Electric) in connection with a business combination that became
effective on June 26, 1998 (the PE/Enova Business Combination).
Expenses incurred by the Company in connection with the business
combination are $35 million, aftertax, for the year ended December
31, 1998. These costs consist primarily of employee-related costs,
and investment banking, legal, regulatory and consulting fees.
In connection with the PE/Enova Business Combination, the
holders of common stock of the Parent and Enova each became holders
of Sempra Energy common stock. PE's common shareholders received
1.5038 shares of Sempra Energy's common stock for each share of PE
common stock, and Enova's common shareholders received one share of
Sempra Energy's common stock for each share of Enova common stock.
The preferred stock of the Company remained outstanding. The
combination was approved by the shareholders of both companies on
March 11, 1997 and was a tax-free transaction.

Capital Resources and Liquidity
The Company's working capital requirements are met through cash
from operations and the issuance of short-term and long-term debt.
Cash requirements primarily include capital investments in the
utility operations.
Additional information on sources and uses of cash during the
last three years is summarized in the following condensed statement
of cash flows:

Sources and (Uses) of Cash
Year Ended December 31,
Dollars in millions) 1998 1997 1996
- -------------------------------------------------------------------
Operating activities $ 782 $ 396 $ 638
----------------------------------
Investing activities:
Capital expenditures (128) (159) (197)
Other - net 22 40 (31)
----------------------------------
Total investing activities (106) (119) (228)
----------------------------------
Financing activities:
Long-term debt - net (73) (122) (78)
Short-term debt - net (351) 89 28
Redemption of preferred stock (75) -- (100)
Dividends (166) (258) (259)
----------------------------------
Total financing activities (665) (291) (409)
----------------------------------
Increase (decrease) in cash
and cash equivalents $ 11 $ (14) $ 1
- -------------------------------------------------------------------

Cash Flows from Operating Activities
The increase in cash flows from operating activities in 1998
primarily was caused by higher throughput compared to 1997 combined
with natural gas costs that were lower than amounts being collected
in rates, resulting in overcollected regulatory balancing accounts
at year-end 1998. This increase was partially offset by expenses
incurred in connection with the PE/Enova Business Combination.
The decrease in cash flows from operating activities in 1997
was primarily due to greater working capital requirements for
natural gas operations in 1997. This was caused by natural gas
costs' being higher than amounts collected in rates, resulting in
undercollected regulatory balancing accounts at year end 1997.

Cash Flows from Investing Activities
Cash flows from investing activities primarily represent rate base
investment at the Company.
Capital expenditures were $31 million lower in 1998 primarily
due to the shifting of certain functions to Sempra Energy following
the PE/Enova Business Combination.
Capital expenditures were $38 million lower in 1997 than in
1996 due to lower spending primarily related to the customer
information system's being completed in 1996, and other
nonrecurring computer system expenditures in 1996. The decrease
was partially offset by higher capital expenditures related to the
purchase of a data processing facility.
Capital expenditures are estimated to be $170 million in 1999.
They will be financed primarily by internally generated funds.

Cash Flows from Financing Activities
Long-Term Debt
In 1998, cash was used for the repayment of $100 million of first-
mortgage bonds and $47 million of Swiss Franc bonds partially
offset by the issuance of $75 million of Medium-Term Notes. Short-
term debt repayments included repayment of $94 million of debt
issued to finance the Comprehensive Settlement (see Note 11 of the
notes to Consolidated Financial Statements).
In 1997 cash was used for the repayment of $96 million of debt
issued to finance the Comprehensive Settlement and repayment of
$125 million of first-mortgage bonds. This was partially offset by
the issuance of $120 million in Medium-Term Notes and short-term
borrowings used to finance working capital requirements.

Stock Redemption
On February 2, 1998, SoCalGas redeemed all outstanding shares of
its 7 3/4% Series Preferred Stock at a cost of $25.09 per share, or
$75.3 million including accrued dividends.

Dividends
Dividends paid on common and preferred stock in 1998 amounted to
$169 million, compared to approximately $260 million in 1997 and
1996. The payment of future dividends and the amount thereof are
within the discretion of the board of directors.

Capitalization
The debt-to-capitalization ratio was 43 percent at year-end 1998,
below the 50 percent ratio in 1997. The decrease was primarily due
to the repayment of short-term debt. The debt-to-capitalization
ratio was 50 percent in 1997, the same as in 1996.

Cash and Cash Equivalents
Cash and cash equivalents were $11 million at December 31, 1998.
The Company anticipates that cash required in 1999 for capital
expenditures, dividends and debt payments will be provided by cash
generated from operating activities and existing cash balances.
In addition to cash from ongoing operations, the Company has
multi-year credit agreements that permit term borrowings of up to
$400 million. At December 31, 1998 all bank lines of credit were
unused. For further discussion, see Note 3 of the notes to
Consolidated Financial statements.

Ratemaking Procedures

To understand the operations and financial results of the Company
it is important to understand the ratemaking procedures that the
Company follows.
The Company is regulated by the CPUC. It is the responsibility
of the CPUC to determine that utilities operate in the best
interest of their customers and have the opportunity to earn a
reasonable return on investment. In response to utility-industry
restructuring, in 1997 the Company received approval from the CPUC
for performance-based regulation (PBR).
PBR replaced the general rate case (GRC) procedure and certain
other regulatory proceedings. Under ratemaking procedures in
effect prior to PBR, the Company typically filed a GRC with the
CPUC every three years. In a GRC, the CPUC establishes a base
margin, which is the amount of revenue to be collected from
customers to recover authorized operating expenses (other than the
cost of natural gas), depreciation, taxes and return on rate base.
Under PBR, regulators allow income potential to be tied to
achieving or exceeding specific performance and productivity
measures, rather than relying solely on expanding utility rate base
in a market where a utility already has a highly developed
infrastructure. See additional discussion of PBR and gas-industry
restructuring in Note 11 of the notes to Consolidated Financial
Statements.
The gas industry experienced an initial phase of restructuring
during the 1980s by deregulating gas sales to noncore customers. In
January 1998, the CPUC initiated a project to assess the current
market and regulatory framework for California's natural gas
industry. The general goals of the plan are to consider reforms to
the current regulatory framework emphasizing market-oriented
policies.
See additional discussion of gas-industry restructuring in Note
11 of the notes to Consolidated Financial Statements.

Results of Operations

1998 Compared to 1997
Net income for 1998 decreased to $159 million, compared to net
income of $238 million in 1997.
The decrease in net income is primarily due to costs associated
with the PE/Enova Business Combinations and a lower base margin
established at SoCalGas in its PBR decision which became effective
on August 1, 1997 (see Note 11 of the notes to Consolidated
Financial Statements). The expense related to the PE/Enova
Business Combination was $35 million, aftertax, for 1998.
Utility gas revenues decreased 8 percent in 1998 primarily due
to the lower natural gas margin established in SoCalGas' PBR
proceeding, a decrease in the average cost of natural gas, and a
decrease in sales to utility electric generation customers due to
decreased demand for electricity. This decrease was partially
offset by increased sales to residential customers due to colder
weather in 1998.
The Company's cost of natural gas distributed decreased 16
percent in 1998 largely due to a decrease in the average cost of
natural gas purchased, partially offset by an increase in sales
volume.
Operating expenses increased 12 percent in 1998 primarily due
to costs associated with the PE/Enova Business Combination.

1997 Compared to 1996
Net income for 1997 increased to $238 million compared to net
income of $201 million in 1996. The increase in net income is
primarily due to increased throughput to Utility Electric
Generation (UEG) customers, lower operation and maintenance
expenses than amounts authorized in rates, and a nonrecurring non-
cash charge of $26.6 million, aftertax, in 1996 partially offset by
a lower margin in 1997 established in the PBR decision. The non-
cash charge of $26.6 million in 1996 was the result of continuing
developments in the CPUC's restructuring of the electric utility
industry. The charge arose because the Company anticipated that
throughput to noncore UEG customers would be below the levels
projected in 1993 at the time of the Comprehensive Settlement (See
Note 11 of notes to Consolidated Financial Statements).
Consequently, the Company believed it would not realize the
remaining revenue enhancements that were applied to offset the
costs of the Comprehensive Settlement. In connection with the 1992
quasi-reorganization, the Parent established a liability for this
issue and therefore this charge had no effect on the Parent's
consolidated net income.
Natural gas revenues increased 9 percent in 1997 primarily due
to an increase in the average unit cost of natural gas, which is
recoverable in rates. To a lesser extent, the increase was due to
increased demand for electricity.
Cost of natural gas distributed increased 18 percent in 1997,
largely due to an increase in the average cost of natural gas
purchased and increases in sales volume.
Operating expense was relatively unchanged in 1997, primarily
due to the Company's continued emphasis on reducing costs and
reduced costs in 1996 from favorable litigation settlements.

Operating Results

The table below summarizes the components of SoCalGas' volume and
revenues by customer class for the years ended December 31, 1998,
1997 and 1996.

Gas Sales, Transportation & Exchange
(Dollars in millions, volumes in billion cubic feet)

Gas Sales Transportation & Exchange Total
---------------------------------------------------------------
Throughput Revenue Throughput Revenue Throughput Revenue
---------------------------------------------------------------

1998:
Residential 269 $1,976 3 $ 11 272 $1,987
Commercial and Industrial 81 466 315 261 396 727
Utility Electric Generation 139 66 139 66
Wholesale 155 66 155 66
---------------------------------------------------------------
350 $2,442 612 $404 962 2,846
Balancing accounts and other (419)
--------
Total Operating Revenues $2,427
- ------------------------------------------------------------------------------------------

1997:
Residential 237 $1,726 3 $ 10 240 $1,736
Commercial and Industrial 80 502 314 255 394 757
Utility Electric Generation 158 76 158 76
Wholesale 138 67 138 67
---------------------------------------------------------------
317 $2,228 613 $408 930 2,636
Balancing accounts and other 5
---------
Total Operating Revenues $2,641
- ------------------------------------------------------------------------------------------

1996:
Residential 233 $1,603 3 $ 10 236 $1,613
Commercial and Industrial 82 473 297 236 379 709
Utility Electric Generation 139 70 139 70
Wholesale 130 70 130 70
---------------------------------------------------------------
315 $2,076 569 $386 884 2,462
Balancing accounts and other (40)
---------
Total Operating Revenues $2,422

Although the revenues from transportation throughput are less than
for natural gas sales, the Company generally earns the same margin
whether it buys the natural gas and sells it to the customer or
transports natural gas already owned by the customer. Throughput,
the total natural gas sales and transportation volumes moved
through the Company's system, increased in 1998 compared to 1997,
primarily because of higher residential sales due to colder weather
in 1998. The increase in throughput in 1997 compared to 1996 is
primarily due to higher demand for electricity from gas-fired
electric generation and less availability of hydro-electricity.

Factors Influencing Future Performance
Performance of the Company in the near future will depend primarily
on the ratemaking and regulatory process, electric and natural gas
industry restructurings, and the changing energy marketplace.
These factors are summarized below.

KN Energy Acquisition. On February 22, 1999, Sempra Energy
announced a definitive agreement to acquire KN Energy, Inc.,
subject to approval by the shareholders of both companies and by
various regulatory agencies. See Note 13 of the notes to
Consolidated Financial Statements for additional information.

Performance-Based Regulation. Under PBR, regulators allow future
income potential to be tied to achieving or exceeding specific
performance and productivity measures, as well as cost reductions,
rather than relying solely on expanding utility rate base. See
additional discussion in Note 11 of the notes to Consolidated
Financial Statements.

Regulatory Accounting Standards. SoCalGas has been accounting for
the economic effects of regulation on its utility operations in
accordance with Statement of Financial Accounting Standards (SFAS)
No. 71, "Accounting for the Effects of Certain Types of
Regulation." Under SFAS No. 71, a regulated entity records a
regulatory asset if it is probable that, through the ratemaking
process, the utility will recover the asset from customers.
Regulatory liabilities represent future reductions in revenues for
amounts due to customers. See Notes 2 and 11 of the notes to
Consolidated Financial Statements for additional information.

Affiliate Transactions. On December 16, 1997, the CPUC adopted
rules establishing uniform standards of conduct governing the
manner in which California investor owned utilities (IOUs) conduct
business with their affiliates. The objective of these rules,
effective January 1, 1998, is to ensure that the utilities' energy
affiliates do not gain an unfair advantage over other competitors
in the marketplace and that utility customers do not subsidize
affiliate activities.
The CPUC excluded utility-to-utility transactions between
SDG&E and SoCalGas from the affiliate-transaction rules in its
March 1998 decision approving the PE/Enova Business Combination. As
a result, the affiliate transaction rules will not substantially
impact the Company's ability to achieve anticipated synergy
savings. See Notes 1 and 11 of the notes to Consolidated Financial
Statements for additional information.

Allowed Rate of Return. For 1998, the Company was authorized to
earn a rate of return on rate base of 9.49 percent and a rate of
return on common equity of 11.6 percent, which is unchanged from
1997. See additional discussion in Note 11 of the notes to
Consolidated Financial Statements.

Management Control of Expenses and Investment. In the past,
management has been able to control operating expenses and
investments within the amounts authorized to be collected in rates.
It is the intent of management to control operating expenses and
investments within the amounts authorized to be collected in rates
in the PBR decision. The Company intends to make the efficiency
improvements, changes in operations and cost reductions necessary
to achieve this objective and earn its authorized rate of return.
However, in view of the earnings-sharing mechanism and other
elements of the PBR, it is more difficult to exceed authorized
returns to the degree experienced in past years. See additional
discussion of PBR in Note 11 of the notes to Consolidated Financial
Statements.

Electric Industry Restructuring. As a result of electric industry
restructuring, natural gas generated electricity within the
Company's service area competes with electric power generated
throughout the western United States.
The State of California in September 1996 enacted a law
restructuring California's electric-utility industry (AB 1890).
Consumers have the opportunity to choose to continue to purchase
their electricity from the local utility under regulated tariffs,
to enter into contracts with other energy-service providers (direct
access) or to buy their power from the independent Power Exchange
(PX) that serves as a wholesale power pool allowing all energy
producers to participate competitively. The implementation of
electric industry restructuring has no direct impact on the
Company's operations. However, future volumes of natural gas
transported for current utility electric generation customers may
be adversely affected to the extent these regulatory changes divert
electricity generated from the Company's service territory.

Natural Gas Industry Restructuring. The natural gas industry
experienced an initial phase of restructuring during the 1980s by
deregulating natural gas sales to noncore customers. On January 21,
1998, the CPUC released a staff report initiating a project to
assess the current market and regulatory framework for California's
natural gas industry. The general goals of the plan are to consider
reforms to the current regulatory framework emphasizing market-
oriented policies benefiting California natural gas consumers. On
August 25, 1998 California enacted a law prohibiting the CPUC from
enacting any natural gas industry-restructuring decision for core
customers prior to January 1, 2000. The CPUC continues to study
the issue.

Noncore Bypass. The Company's throughput to enhanced oil recovery
(EOR) customers in the Kern County area has decreased significantly
since 1992 because of the bypass of the Company's system by
competing interstate pipelines. The decrease in revenues from EOR
customers did not have a material impact on the Company's earnings.
Bypass of other markets also may occur, and the Company is
fully at risk for a reduction in non-EOR, noncore volumes due to
bypass. However, significant additional bypass would require
construction of additional facilities by competing pipelines. The
Company is continuing to reduce its costs to maintain cost
competitiveness in order to retain transportation customers.

Noncore Pricing. To respond to bypass, the Company has received
authorization from the CPUC for expedited review of long-term
natural gas transportation service contracts with some noncore
customers at lower than tariff rates. In addition, the CPUC
approved changes in the methodology that eliminates subsidization
of core customer rates by noncore customers. This allocation
flexibility, together with negotiating authority, has enabled the
Company to better compete with new interstate pipelines for noncore
customers.

Noncore Throughput. The Company's earnings may be adversely
impacted if natural gas throughput to its noncore customers varies
from estimates adopted by the CPUC in establishing rates. There is
a continuing risk that an unfavorable variance in noncore volumes
may result from external factors such as weather, electric
deregulation, the increased use of hydro-electric power, competing
pipeline bypass of the Company's system and a downturn in general
economic conditions. In addition, many noncore customers are
especially sensitive to the price relationship between natural gas
and alternate fuels, as they are capable of readily switching from
one fuel to another, subject to air-quality regulations. SoCalGas is
at risk for the lost revenue.
Through July 31, 1999, any favorable earnings effect of higher
revenues resulting from higher throughput to noncore customers has
been limited as a result of the Comprehensive Settlement discussed
in Note 11 of the notes to Consolidated Financial Statements.

Excess Interstate Pipeline Capacity. Existing interstate pipeline
capacity into California exceeds current demand by over one billion
cubic feet (Bcf) per day. This situation has reduced the market
value of the capacity well below the Federal Energy Regulatory
Commission's (FERC) tariffs. The Company has exercised its step-
down option on both the El Paso and Transwestern systems, thereby
reducing its firm interstate capacity obligation from 2.25 Bcf per
day to 1.45 Bcf per day.
FERC-approved settlements have resulted in a reduction in the
costs that the Company may have been required to pay for the
capacity released back to El Paso and Transwestern that cannot be
remarketed. Of the 1.45 Bcf per day of capacity, the Company's core
customers use 1.05 Bcf per day at the full FERC tariff rate. The
remaining 0.4 Bcf per day of capacity is marketed at significant
discounts. Under existing California regulation, unsubscribed
capacity costs associated with the remaining 0.4 Bcf per day are
recoverable in customer rates. While including the unsubscribed
pipeline cost in rates may impact the Company's ability to compete
in highly contested markets, the Company does not believe its
inclusion will have a significant impact on volumes transported or
sold.

Environmental Matters
The Company's operations are conducted in accordance with
applicable federal, state and local environmental laws and
regulations governing such things as hazardous wastes, air and
water quality, and the protection of wildlife.
These costs of compliance are normally recovered in customer
rates. It is anticipated that the environmental costs associated
with the natural gas operations will continue to be recoverable in
rates.
Capital expenditures to comply with environmental laws and
regulations were $1 million in 1998 and 1997 and $3 million in
1996.
In 1994, the CPUC approved the Hazardous Waste Collaborative
Mechanism, which allows utilities to recover cleanup costs of
hazardous waste contamination at sites where the utility may have
responsibility or liability under the law to conduct or participate
in any required cleanup. In general, utilities are allowed to
recover 90 percent of their cleanup costs and any related costs of
litigation with responsible parties.
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.
Possible recoveries of environmental remediation liabilities from
third parties are not deducted from the liability.
For further discussion of environmental matters, see Note 10 of
the notes to Consolidated Financial Statements.

Other Income, Interest Expense and Income Taxes
Other Income
Other income, which primarily consists of interest income from
short-term investments and regulatory balancing accounts, decreased
in 1998 to $1 million from $7 million in 1997. The decrease was
primarily the result of lower regulatory interest in 1998. Other
income increased in 1997 to $7 million from $1 million in 1996. The
increase was primarily due to higher regulatory interest in 1997.

Interest Expense
Interest expense for 1998 decreased to $80 million from $87 million
in 1997. The decrease is primarily due to repayment of short-term
debt in 1998. Interest expense for 1997 slightly increased to $87
million from $86 million in 1996.

Income Taxes
Income tax expense was $128 million, $178 million and $148 million
in 1998, 1997 and 1996, respectively. This represents an effective
tax rate of 45 percent for 1998, 43 percent for 1997 and 42 percent
for 1996. See Note 5 of the notes to Consolidated Financial
Statements for additional information.

Derivative Financial Instruments
The Company's policy is to use derivative financial instruments to
manage exposure to fluctuations in interest rates, foreign currency
exchange rates and energy prices. Transactions involving these
financial instruments are with reputable firms and major exchanges.
The use of these instruments may expose the Company to market and
credit risks. At times, credit risk may be concentrated with
certain counterparties, although counterparty nonperformance is not
anticipated.
The Company's operations use energy derivatives to manage
natural gas price risk associated with servicing their load
requirements. These instruments include forward contracts, futures,
swaps, options and other contracts, with maturities ranging from 30
days to 12 months. In the case of price-risk management activities,
the use of derivative financial instruments by the Company is
subject to certain limitations imposed by established Company
policy and regulatory requirements. See Note 8 of the notes to
Consolidated Financial Statements and the "Market Risk Management
Activities" section below for further information regarding the use
of energy derivatives by the Company's operations.

Market Risk Management Activities
Market risk is the risk of erosion of the Company's cash flows, net
income and asset values due to adverse changes in interest and
foreign-currency rates, and in prices for energy. Sempra Energy has
adopted corporate-wide policies governing its market-risk
management activities. An Energy Risk Management Oversight
Committee, consisting of senior corporate officers, oversees
energy-price risk-management activities to ensure compliance with
Sempra Energy's stated energy risk-management policies. In
addition, all affiliates have groups that monitor and control
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 level. The Company has
adopted the variance/covariance methodology in its calculation of
VaR, and uses a 95 percent confidence level. Holding periods are
specific to the types of positions being measured, and are
determined based on the size of the position or portfolios, market
liquidity, tenor and other factors. Historical volatilities and
correlations between instruments and positions are used in the
calculation.
The following is a discussion of the Company's primary market-
risk exposures as of December 31, 1998, including a discussion of
how these exposures are managed.

Interest-Rate Risk
The Company is exposed to fluctuations in interest rates primarily
as a result of its fixed-rate long-term debt. The Company has
historically funded its operations through long-term bond issues
with fixed interest rates. With the restructuring of the regulatory
process, greater flexibility has been permitted within the debt-
management process. As a result, recent debt offerings have been
selected with short-term maturities to take advantage of yield
curves or used a combination of fixed- and floating-rate debt.
Interest rate swaps, subject to regulatory constraints, may be used
to adjust interest-rate exposures when appropriate, based upon
market conditions. However, no such swaps are in place at December
31, 1998.
A portion of the Company's borrowings are denominated in
foreign currencies, which expose the Company to market risk
associated with exchange-rate movements. The Company's policy
generally is to hedge major foreign-currency cash exposures through
swap transactions. These contracts are entered into with major
international banks, thereby minimizing the risk of credit loss.
The VaR on the Company's fixed-rate long-term debt is estimated
at approximately $168 million as of December 31, 1998, assuming a
one-year holding period. The VaR attributable to currency exchange
rates nets to zero as a result of a currency swap that is directly
matched to the Company's Swiss Franc debt obligation, its only non-
dollar-denominated debt.

Energy-Price Risk
Market risk related to physical commodities is based upon potential
fluctuations in natural gas exchange prices and basis. The
Company's market risk is impacted by changes in volatility and
liquidity in the markets in which these instruments are traded. The
Company is exposed, in varying degrees, to price risk in the
natural gas markets. The Company's policy is to manage this risk
within a framework that considers the unique markets, and operating
and regulatory environment.
The Company is exposed to market risk on its natural gas
purchase, sale and storage activities whenever natural gas prices
fall outside the GCIM tolerance band. The Company manages this risk
within the parameters of the Company's market risk management
framework. As of December 31, 1998, the total VaR of the Company's
natural gas positions was not material.

Credit Risk
Credit risk relates to the risk of loss that would be incurred as a
result of nonperformance by counterparties pursuant to the terms of
their contractual obligations. The Company avoids concentration of
counterparties and maintains credit policies with regard to
counterparties that management believes significantly minimize
overall credit risk. These policies include an evaluation of
potential counterparties' financial condition (including credit
rating), collateral requirements under certain circumstances, and
the use of standardized agreements that allow for the netting of
positive and negative exposures associated with a single
counterparty.
The Company monitors credit risk through a credit-approval
process and the assignment and monitoring of credit limits. These
credit limits are established based on risk and return
considerations under terms customarily available in the industry.

Year 2000 Issues
Most companies are affected by the inability of many automated
systems and applications to process the year 2000 and beyond. The
Year 2000 issues are the result of computer programs and other
automated processes using two digits to identify a year, rather
than four digits. Any of the Company's computer programs that
include date-sensitive software may recognize a date using "00" as
representing the year 1900, instead of the year 2000, or "01" as
1901, etc., which could lead to system malfunctions. The Year 2000
issues impact both Information Technology (IT) systems and also
non-IT systems, including systems incorporating "embedded
processors." To address this problem, in 1996, both Pacific
Enterprises and Enova Corporation established company-wide Year
2000 programs. These programs have now been consolidated into
Sempra Energy's overall Year 2000 readiness effort. Sempra Energy
has established a central Year 2000 Program Office which reports to
the its Chief Information Technology Officer and reports
periodically to the audit committee of the Board of Directors.

The Company's State of Readiness
Sempra Energy is identifying all IT and non-IT systems that might
not be Year 2000 ready and categorizing them in the following
areas: IT applications, computer hardware and software
infrastructure, telecommunications, embedded systems and third
parties. Sempra Energy is currently evaluating its exposure in all
of these areas. These systems and applications are being tracked
and measured through four key phases: inventory, assessment,
remediation/testing, and Year 2000 readiness. Those applications
and systems which, if not appropriately remediated, may have a
significant impact on energy delivery, revenue collection or the
safety of personnel, customers or facilities are being assessed and
modified/replaced first. The testing effort includes functional
testing of Year 2000 dates and validating that changes have not
altered existing functionality. Sempra Energy uses an independent,
internal-review process to verify that the appropriate testing has
occurred.
Inventory and assessment for all company systems were completed
by January 1999 and ongoing inventory and assessment will be
performed, as necessary, on any new applications. The project is on
schedule and the Company estimates that by June 30, 1999, all
critical systems will be suitable for continued use into the year
2000 with no significant operational problems.
Sempra Energy's current schedule for Year 2000 testing,
readiness and development of contingency plans is subject to change
depending upon the remediation and testing phases of its compliance
effort and upon developments that may arise as the Company
continues to assess its computer-based systems and operations. In
addition, this schedule is dependent upon the efforts of third
parties, such as suppliers (including energy producers) and
customers. Accordingly, delays by third parties may cause Sempra
Energy's schedule to change.

Costs to Address Sempra Energy's Year 2000 Issues
Sempra Energy's budget for the Year 2000 program is $48 million, of
which $38 million has been spent. As Sempra Energy continues to
assess its systems and as the remediation and testing efforts
progress, cost estimates may change. Sempra Energy's Year 2000
readiness effort is being funded entirely by operating cash flows.

The Risks of Sempra Energy's Year 2000 Issues
Based upon its current assessment and testing of the Year 2000
issue, Sempra Energy believes the reasonably likely worst case Year
2000 scenarios would have the following impacts upon its
operations. With respect to Sempra Energy's ability to provide
energy to its domestic utility customers, it believes that the
reasonably likely worst case scenario is for small, localized
interruptions of natural gas or electrical service which are
restored in a timeframe that is within normal service levels. With
respect to services that are essential to Sempra Energy's
operations, such as customer service, business operations, supplies
and emergency response capabilities, the scenario is for minor
disruptions of essential services with rapid recovery and all
essential information and processes ultimately recovered.
To assist in preparing for and mitigating these possible
scenarios, Sempra Energy is a member of several industry-wide
efforts established to deal with Year 2000 problems affecting
embedded systems and equipment used by the nation's natural gas and
electric power companies. Under these efforts, participating
utilities are working together to assess specific vendors' system
problems and to test plans. These assessments will be shared by the
industry as a whole to facilitate Year 2000 problem solving.
A portion of this risk is due to the various Year 2000
schedules of critical third-party suppliers and customers. Sempra
Energy is in the process of contacting its critical suppliers and
customers to survey their Year 2000 remediation programs. While
risks related to the lack of Year 2000 readiness by third parties
could materially and adversely affect the Company's business,
results of operations and financial condition, the Company expects
its Year 2000 readiness efforts to reduce significantly the
Company's level of uncertainty about the impact of third party Year
2000 issues on both its IT systems and non-IT systems.

Company's Contingency Plans
Sempra Energy's contingency plans for interruptions related to year
2000 issues are being incorporated in its existing overall
emergency preparedness plans. To the extent appropriate, such plans
will include emergency backup and recovery procedures, remediation
of existing systems parallel with installation of new systems,
replacing electronic applications with manual processes,
identification of alternate suppliers and increasing inventory
levels. Sempra Energy expects these contingency plans to be
completed by June 30, 1999. Due to the speculative and uncertain
nature of contingency planning, there can be no assurances that
such plans actually will be sufficient to reduce the risk of
material impacts on Sempra Energy's operations due to Year 2000
issues.

New Accounting Standards
In June 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards (SFAS) No. 133
"Accounting for Derivative Instruments and Hedging Activities."
This statement, which is effective January 1, 2000, requires that
an entity recognize all derivatives as either assets or liabilities
in the statement of financial position, measure those instruments
at fair value and recognize changes in the fair value of
derivatives in earnings in the period of change unless the
derivative qualifies as an effective hedge that offsets certain
exposures. The effect of this standard on the Company's
Consolidated Financial Statements has not yet been determined.

Information Regarding Forward-Looking Statements
This report includes forward-looking statements within the
definition of Section 27A of the Securities Act of 1933 and Section
21E of the Securities Exchange Act of 1934. The words "estimates,"
"believes," "expects," "anticipates," "plans" and "intends,"
variations of such words, and similar expressions are intended to
identify forward-looking statements that involve risks and
uncertainties which could cause actual results to differ materially
from those anticipated. These statements are necessarily based upon
various assumptions involving judgments with respect to the future
including, among others, local, regional, national, and
international economic, competitive, political and regulatory
conditions and developments, technological developments, capital
market conditions, inflation rates, interest rates, energy markets,
weather conditions, business and regulatory or legal decisions, the
pace of deregulation of retail natural gas and electricity
industries, the timing and success of business development efforts,
and other uncertainties, all of which are difficult to predict and
many of which are beyond the control of the Company. Accordingly,
while the Company believes that the assumptions are reasonable,
there can be no assurance that they will approximate actual
experience, or that the expectations will be realized. Readers are
urged to carefully review and consider the risks, uncertainties and
other factors which affect the Company's business described in this
annual report and other reports filed by the Company from time to
time with the Securities and Exchange Commission.

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 Management Activities."

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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 as of December
31, 1998 and 1997, and the related statements of consolidated
income, changes in shareholders' equity, and cash flows for each of
the three years in the period ended December 31, 1998. 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 generally accepted
auditing standards. 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,
1998 and 1997, and the results of their operations and their cash
flows for each of the three years in the period ended December 31,
1998 in conformity with generally accepted accounting principles.

/s/ DELOITTE & TOUCHE LLP

San Diego, California
January 27, 1999, except for Note 13 as to which the date is
February 22, 1999

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
In millions of dollars

For the years ended December 31 1998 1997 1996
------ ------- -------

Operating Revenues $2,427 $2,641 $2,422
------ ------ ------
Expenses
Cost of natural gas distributed 913 1,088 923
Operation 728 640 643
Maintenance 70 72 82
Depreciation 254 251 248
Income taxes 126 174 145
Local franchise payments 41 36 34
Ad valorem taxes 33 35 35
Payroll and other taxes 24 27 26
------ ------ ------
Total 2,189 2,323 2,136
------ ------ ------
Operating Income 238 318 286
------ ------ ------

Other Income and (Deductions)
Interest income 4 1 1
Regulatory interest -- 15 4
Allowance for equity funds used during construction 3 2 4
Taxes on nonoperating income (2) (4) (3)
Other - net (4) (7) (5)
------ ------ ------
Total 1 7 1
------ ------ ------
Income Before Interest Charges 239 325 287
------ ------ ------
Interest Charges
Long-term debt 75 82 80
Other interest 6 6 8
Allowance for borrowed funds used during construction (1) (1) (2)
------ ------ ------
Total 80 87 86
------ ------ ------
Net income 159 238 201
Preferred Dividend Requirements 1 7 8
------ ------ ------
Earnings Applicable to Common Shares $ 158 $ 231 $ 193
====== ====== ======

See notes to Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
In millions of dollars

December 31,
1998 1997
----------- -----------

ASSETS
Utility plant - at original cost $6,063 $5,978
Accumulated depreciation (3,111) (2,904)
------ ------
Utility plant - net 2,952 3,074
------ ------

Current assets
Cash and cash equivalents 11 --
Accounts receivable - trade (less allowance for doubtful
receivables of $17 in 1998 and $17 in 1997) 453 499
Regulatory balancing accounts undercollected - net -- 355
Deferred income taxes 157 11
Natural gas in storage 49 25
Materials and supplies 14 13
Prepaid expenses 14 14
------ ------
Total current assets 698 917
------ ------
Regulatory assets 184 214
------ ------
Total $3,834 $4,205
====== ======

See notes to Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
In millions of dollars

December 31,
1998 1997
----------- -----------

CAPITALIZATION AND LIABILITIES
Capitalization
Common stock $ 835 $ 835
Retained earnings 525 535
------ ------
Total common equity 1,360 1,370
Preferred stock 22 97
Long-term debt 967 968
------ ------
Total capitalization 2,349 2,435
------ ------

Current liabilities
Short-term debt -- 351
Accounts payable - trade 153 119
Accounts payable - affiliates 111 30
Accounts payable - other 221 268
Regulatory balancing accounts overcollected - net 129 --
Other taxes payable 31 30
Accrued income taxes 30 39
Interest accrued 46 52
Current portion of long-term debt 75 147
Other 75 78
------ ------
Total current liabilities 871 1,114
------ ------

Customer advances for construction 31 34
Deferred income taxes - net 323 373
Deferred investment tax credits 58 61
Deferred credits and other liabilities 202 188
------ ------
Total deferred credits 614 656
------ ------
Contingencies and commitments (Note 10)
Total $3,834 $4,205
====== ======

See notes to Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
In millions of dollars

For the years ended December 31 1998 1997 1996
------ ------ ------

Cash Flows From Operating Activities
Net income $ 159 $ 238 $ 201
Adjustments to reconcile net income to net
cash provided by operating activities
Depreciation 254 251 248
Deferred income taxes (50) (15) 15
Deferred investment tax credits (3) (3) (3)
Allowance for funds used during construction (4) (4) (6)
Other 1 (21) 24
Changes in working capital components
Accounts receivable 46 (86) (14)
Regulatory balancing accounts 484 36 50
Gas in storage (24) 3 27
Other current assets (1) (1) 20
Accounts payable 68 (101) 90
Other taxes payable 1 51 (18)
Deferred income taxes (146) 21 (6)
Other current liabilities (3) 27 10
------ ------ ------
Net cash provided by operating activities 782 396 638
------ ------ ------
Cash Flows from Investing Activities
Capital expenditures (128) (159) (197)
Other - net 22 40 (31)
------ ------ ------
Net cash used in investing activities (106) (119) (228)
------ ------ ------
Cash Flows from Financing Activities
Dividends (166) (258) (259)
Issuance of long-term debt 75 120 75
Payment of long-term debt (148) (242) (153)
Redemption of preferred stock (75) -- (100)
Increase (decrease) in short-term debt (351) 89 28
------ ------ ------
Net cash used in financing activities (665) (291) (409)
------ ------ ------

Net increase (decrease) 11 (14) 1
Cash and Cash Equivalents, January 1 -- 14 13
------ ------ ------
Cash and Cash Equivalents, December 31 $ 11 $ -- $ 14
====== ====== ======
Supplemental Disclosure of Cash Flow Information:
Income tax payments, net of refunds $ 302 $ 132 $ 127
====== ====== ======
Interest payments, net of amount capitalized $ 86 $ 75 $ 85
====== ====== ======
See notes to Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
For the years ended December 31, 1998, 1997, 1996
(Dollars in millions)

Total
Preferred Common Retained Shareholders'
Stock Stock Earnings Equity
- ------------------------------------------------------------------------------

Balance at December 31, 1995 $ 197 $ 835 $ 613 $1,645
Net income 201 201
Preferred stock dividends declared (8) (8)
Common stock dividends declared (251) (251)
Redemption of preferred stock (100) (100)
- ------------------------------------------------------------------------------
Balance at December 31, 1996 97 835 555 1,487
Net income 238 238
Preferred stock dividends declared (7) (7)
Common stock dividends declared (251) (251)
- ------------------------------------------------------------------------------
Balance at December 31, 1997 97 835 535 1,467
Net income 159 159
Preferred stock dividends declared (1) (1)
Common stock dividends declared (168) (168)
Redemption of preferred stock (75) (75)
- ------------------------------------------------------------------------------
Balance at December 31, 1998 $ 22 $ 835 $ 525 $1,382
==============================================================================

See notes to Consolidated Financial Statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1: BUSINESS COMBINATION

On June 26, 1998, Enova Corporation (Enova), and Pacific Enterprises
(PE), parent company of Southern California Gas Company (SoCalGas),
combined into a new company named Sempra Energy. As a result of the
combination, (i) each outstanding share of common stock of Enova was
converted into one share of common stock of Sempra Energy, (ii) each
outstanding share of common stock of PE was converted into 1.5038
shares of common stock of Sempra Energy and (iii) the preferred
stock and preference stock of Enova's principal subsidiary, San
Diego Gas & Electric Company (SDG&E); PE; and SoCalGas remained
outstanding. The combination was approved by the shareholders of
both companies on March 11, 1997 and was a tax-free transaction. The
Consolidated Financial Statements of Sempra Energy and its
subsidiaries give effect to the business combination using the
pooling-of-interests method.

As required by the March 1998 decision of the California Public
Utilities Commission (CPUC) approving the business combination,
SDG&E has entered into agreements to sell its fossil-fueled
generation units. The sales are subject to regulatory approvals and
are expected to close during its first half of 1999. In addition,
SoCalGas has sold its options to purchase the California portions of
the Kern River and Mojave Pipeline natural gas transmission
facilities. The Federal Energy Regulatory Commission's (FERC)
approval of the combination includes conditions that the combined
company will not unfairly use any potential market power regarding
natural gas transportation to fossil-fueled generation plants. The
FERC also specifically noted that the divestiture of SDG&E's fossil-
fueled generation plants would eliminate any concerns about vertical
market power arising from transactions between SDG&E and SoCalGas.

NOTE 2: SIGNIFICANT ACCOUNTING POLICIES

Utility Plant and Depreciation

Utility plant represents the buildings, equipment and other
facilities used by the Company to provide natural gas service. The
cost of utility plant includes labor, materials, contract services
and related items, and an allowance for funds used during
construction. The cost of retired depreciable utility plant, plus
removal costs minus salvage value, is charged to accumulated
depreciation. Depreciation expense is based on the straight-line
method over the useful lives of the assets or a shorter period
prescribed by the CPUC. The provisions for depreciation as a
percentage of average depreciable utility plant in 1998, 1997 and
1996, respectively are: 4.36, 4.35 and 4.39.

Allowance for Funds Used During Construction (AFUDC)

The allowance represents the cost of funds used to finance the
construction of utility plant and is added to the cost of utility
plant. AFUDC also increases income, although it is not a current
source of cash.

Inventories

Materials and supplies are generally valued at the lower of average
cost or market; natural gas in storage is valued by the last-in
first-out method.

Effects of Regulation

SoCalGas accounting policies conform with generally accepted
accounting principles for regulated enterprises and reflect the
policies of the CPUC.
SoCalGas has been preparing its financial statements in
accordance with the provisions of Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain
Types of Regulation," under which a regulated utility may record a
regulatory asset if it is probable that, through the ratemaking
process, the utility will recover that asset from customers.
Regulatory liabilities represent future reductions in rates for
amounts due to customers. In addition, SFAS No. 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets
to Be Disposed Of," affects utility plant and regulatory assets
such that a loss must be recognized whenever a regulator excludes
all or part of an asset's cost from rate base. Additional
information concerning regulatory assets and liabilities is
described in Note 11.

Revenues and Regulatory Balancing Accounts

Revenues from utility customers consist of deliveries to customers
and the changes in regulatory balancing accounts. Earnings
fluctuations from changes in the costs of natural gas and
consumption levels for the majority of natural gas are eliminated
by balancing accounts authorized by the CPUC.

Regulatory Assets

Regulatory assets include unrecovered premium on early retirement
of debt, post-retirement benefit costs, deferred income taxes
recoverable in rates and other regulatory-related expenditures that
the Company expects to recover in future rates. See Note 11 for
additional information.

Comprehensive Income

In 1998, the Company adopted SFAS No. 130, "Reporting Comprehensive
Income." This statement requires reporting of comprehensive income
and its components (revenues, expenses, gains and losses) in any
complete presentation of general-purpose financial statements.
Comprehensive income describes all changes, except those resulting
from investments by owners and distributions to owners, in the
equity of a business enterprise from transactions and other events
including, as applicable, foreign-currency items, minimum pension
liability adjustments and unrealized gains and losses on certain
investments in debt and equity securities. Comprehensive income
was equal to net income for the years ended December 31, 1998,
1997, and 1996.

Use of Estimates in the Preparation of the Financial Statements

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

Statements of Consolidated Cash Flows

Cash equivalents are highly liquid investments with original
maturities of three months or less, or investments that are readily
convertible to cash.

New Accounting Standard

In June 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards (SFAS) No. 133
"Accounting for Derivative Instruments and Hedging Activities."
This statement, which is effective January 1, 2000, requires that
an entity recognize all derivatives as either assets or liabilities
in the statement of financial position, measure those instruments
at fair value and recognize changes in the fair value of
derivatives in earnings in the period of change unless the
derivative qualifies as an effective hedge that offsets certain
exposures. The effect of this standard on the Company's
consolidated financial statements has not yet been determined.

NOTE 3: SHORT-TERM BORROWINGS

SoCalGas has a $400 million multi-year credit agreement. This
agreement expires in 2001 and bears interest at various rates based
on market rates and the Company's credit ratings. SoCalGas' lines
of credit are available to support commercial paper. At December
31, 1998 and 1997, SoCalGas' bank line of credit was unused.
At December 31, 1998, there were no commercial-paper
obligations outstanding. At December 31, 1997, SoCalGas had $351
million of commercial-paper obligations outstanding, of which
approximately $94 million related to the restructuring costs
associated with certain long-term natural gas supply contracts
under the Comprehensive Settlement. See Note 11 for additional
information.

NOTE 4: LONG-TERM DEBT

- -------------------------------------------------------------------
December 31,
(In millions of dollars) 1998 1997
- -------------------------------------------------------------------
First-Mortgage Bonds
5.250% March 1, 1998 $ -- $ 100
6.875% August 15, 2002 100 100
5.750% November 15, 2003 100 100
8.750% October 1, 2021 150 150
7.375% March 1, 2023 100 100
7.500% June 15, 2023 125 125
6.875% November 1, 2025 175 175
----------------------------
750 850
Other Long-Term Debt
6.210% Notes, November 7, 1999 75 75
6.375% Notes, October 29, 2001 120 120
8.750% Notes, July 6, 2000 30 30
5.670% Notes, January 15, 2003 75 --
SFr. 100,000,000 5.125% Bonds,
February 6, 1998 (foreign currency
exposure hedged through currency swap
at an interest rate of 9.725%) -- 47
SFr. 15,695,000 6.375% Foreign Interest
Payment Securities, May 14, 2006 8 8
----------------------------
Total 1,058 1,130
Less:
Long term debt due within one year 75 147
Unamortized debt discount on
long-term debt 16 15
----------------------------
91 162
----------------------------
Total $ 967 $ 968
- -------------------------------------------------------------------

Maturities of long-term debt are $75 million in 1999, $30 million
in 2000, $120 million in 2001, $100 million in 2002 and $175
million in 2003.

First-Mortgage Bonds

First-mortgage bonds are secured by a lien on substantially all
utility plant. SoCalGas may issue additional first-mortgage bonds
upon compliance with the provisions of its bond indenture, which
provides for, among other things, the issuance of an additional
$750 million of first-mortgage bonds as of December 31, 1998.

Other Long-Term Debt

During 1998, SoCalGas issued $75 million of unsecured debt in
medium-term notes used to finance working capital requirements.

Currency Rate Swaps

In May 1996, SoCalGas issued SFr. 15,695,000 of 6.375% Foreign
Interest Payment Securities maturing on May 14, 2006. SoCalGas
hedged the currency exposure by entering into a swap transaction
with a major international bank. As a result, the bond issue,
interest payments and other ongoing costs were swapped for fixed
annual payments. The Foreign Interest Payment Securities are
renewable at ten-year intervals at reset interest rates. The next
put date for the $8 million Foreign Interest Payment Securities is
in the year 2006.

NOTE 5: INCOME TAXES

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

- ------------------------------------------------------------------
1998 1997 1996
- ------------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Depreciation 9.4 5.5 6.6
State income taxes - net of
federal income tax benefit 4.7 6.3 5.4
Tax credits (0.9) (0.7) (0.9)
Capitalized expenses not deferred (0.9) (0.7) (3.2)
Other - net (2.7) (2.6) (.5)
------------------------------
Effective income tax rate 44.6% 42.8% 42.4%
- ------------------------------------------------------------------

The components of income tax expense are as follows:

- ------------------------------------------------------------------
(Dollars in millions) 1998 1997 1996
- ------------------------------------------------------------------
Current:
Federal $233 $138 $100
State 64 38 30
------------------------------
Total current taxes 297 176 130
------------------------------
Deferred:
Federal (128) 6 21
State (38) (1) -
------------------------------
Total deferred taxes (166) 5 21
------------------------------
Deferred investment tax credits-net (3) (3) (3)
------------------------------
Total income tax expense $128 $178 $148
- ------------------------------------------------------------------

Deferred income taxes at December 31 result from the following:

- ------------------------------------------------------------------
(Dollars in millions) 1998 1997
- ------------------------------------------------------------------
Deferred Tax Liabilities:
Differences in financial and
tax bases of utility plant $449 $455
Regulatory balancing accounts - 161
Regulatory assets 1 11
Other 50 48
------------------------------
Total deferred tax liabilities 500 675
------------------------------
Deferred Tax Assets:
Unamortized investment tax credits 25 27
Regulatory balancing accounts 51 -
Comprehensive settlement (see Note 11) 95 114
Other deferred liabilities 153 158
Other 10 14
------------------------------
Total deferred tax assets 334 313
------------------------------
Net deferred income tax liability 166 362
Current portion (net asset) 157 11
------------------------------
Non-current portion (net liability) $323 $373
- ------------------------------------------------------------------

NOTE 6: EMPLOYEE BENEFIT PLANS

The information presented below describes the plans of the Company.
In connection with the PE/Enova Business Combination described in
Note 1, certain of these plans have been or will be replaced or
modified, and numerous participants have been or will be
transferred from the Company's plans to those of Sempra Energy.

Pension and Other Postretirement Benefits

The Company sponsors qualified and nonqualified pension plans and
other postretirement benefit plans for its employees. The following
tables provide a reconciliation of the changes in the plans'
benefit obligations and fair value of assets over the two years,
and a statement of the funded status as of each year end:

- ---------------------------------------------------------------------------------
Other
Pension Benefits Postretirement Benefits
-----------------------------------------------
(Dollars in millions) 1998 1997 1998 1997
- ---------------------------------------------------------------------------------

Weighted-Average Assumptions
as of December 31:
Discount rate 6.75% 7.00% 6.75% 7.00%
Expected return on plan assets 8.50% 8.00% 8.50% 8.00%
Rate of compensation increase 5.00% 5.00% 5.00% 5.00%
Cost trend of covered
health-care charges - - 8.00%(1) 7.00%(2)

Change in Benefit Obligation:
Net benefit obligation at
January 1 $1,378 $1,316 $ 463 $ 372
Service cost 33 32 12 13
Interest cost 95 95 31 30
Plan participants' contributions - - 1 1
Plan amendments 16 - - -
Actuarial (gain) loss (10) 26 (5) 62
Transfer of liability (3) (204) - (43) -
Special termination benefits 48 13 3 2
Gross benefits paid (200) (104) (16) (17)
-----------------------------------------------
Net benefit obligation at
December 31 1,156 1,378 446 463
-----------------------------------------------

Change in Plan Assets:
Fair value of plan assets
at January 1 1,834 1,672 343 267
Actual return on plan assets 286 266 61 59
Employer contributions 1 - 30 33
Plan participants' contributions - - 1 1
Transfer of assets (3) (326) - (40) -
Gross benefits paid (200) (104) (16) (17)
-----------------------------------------------
Fair value of plan assets
at December 31 1,595 1,834 379 343
-----------------------------------------------
Funded status at December 31 439 456 (67) (120)
Unrecognized net actuarial gain (518) (520) (53) (7)
Unrecognized prior service cost 50 37 (1) (1)
Unrecognized net transition
obligation 3 4 119 128
-----------------------------------------------
Net liability at December 31 (4) $ (26) $ (23) $ (2) $ -
- ---------------------------------------------------------------------------------
(1) Decreasing to ultimate trend of 6.50% in 2004.
(2) Decreasing to ultimate trend of 6.50% in 1998.
(3) To reflect transfer of plan assets and liability to Sempra Energy
plan for Company employees transferred to Sempra Energy.
(4) Approximates amounts recognized in the Consolidated Balance Sheets
at December 31. Prior year amounts include non-qualified plans to be
consistent with the current year presentation.

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

- ---------------------------------------------------------------------------------
Other
Pension Benefits Postretirement Benefits
-----------------------------------------------
(Dollars in millions) 1998 1997 1996 1998 1997 1996
- ---------------------------------------------------------------------------------

Service cost $ 33 $ 32 $ 34 $ 12 $ 13 $ 15
Interest cost 95 95 93 31 30 30
Expected return on assets (128) (120) (108) (24) (20) (18)
Amortization of:
Transition obligation 1 1 1 9 9 13
Prior service cost 3 3 3 - - (1)
Actuarial gain (12) (10) - - - -
Special termination benefit 48 13 - 3 2 -
Settlement credit (30) - - - - -
Regulatory adjustment - - 3 9 - (1)
-----------------------------------------------
Total net periodic benefit cost $ 10 $ 14 $ 26 $ 40 $ 34 $ 38
- ---------------------------------------------------------------------------------

Assumed health care cost trend rates have a significant effect
on the amounts reported for the health care plans. A 1% 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 $10 $ (9)
Effect on the health care component of the
accumulated postretirement benefit obligation $67 $(61)
- ------------------------------------------------------------------------

The projected benefit obligation and accumulated benefit obligation
for the pension plan were $15 million and $12 million,
respectively, as of December 31, 1998, and $12 million and $10
million, respectively, as of December 31, 1997.
Other postretirement benefits include medical benefits for
retirees and their spouses, and retiree life insurance.

Savings Plans

SoCalGas offers a savings plan, administered by plan trustees, to
all eligible employees. Eligibility to participate in the various
employer plans begins after one month of completed service.
Employees may contribute, subject to plan provisions, from 1
percent to 15 percent of their regular earnings. Employer
contributions, after one year of completed service, are made in
shares of Sempra Energy common stock. Employer contributions are
equal to 50 percent of the first 6 percent of eligible base salary
contributed by employees. The employee's contributions, at the
direction of the employees, are primarily invested in Sempra Energy
stock, mutual funds or guaranteed investment contracts. Employer
contributions for the SoCalGas plan are partially funded by the
Pacific Enterprises Employee Stock Ownership Plan and Trust. Annual
expense for the savings plans was $7 million in 1998, 1997 and
1996.

NOTE 7: STOCK-BASED COMPENSATION

Sempra Energy has stock-based compensation plans that align
employee and shareholder objectives related to Sempra Energy's
long-term growth. The long-term incentive stock compensation plan
provides for aggregate awards of Sempra Energy non-qualified stock
options, incentive stock options, restricted stock, stock
appreciation rights, performance awards, stock payments or dividend
equivalents to eligible employees of Sempra Energy and its
subsidiaries.
In 1995, Statement of Financial Accounting Standards (SFAS)
No. 123, "Accounting for Stock-Based compensation," was issued. It
encourages a fair-value-based method of accounting for stock-based
compensation. As permitted by SFAS No. 123, Sempra Energy and its
subsidiaries adopted its disclosure-only requirements and continue
to account for stock-based compensation in accordance with the
provisions of accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees."
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, the subsidiaries record an expense for
the plans. SoCalGas recorded expenses of $4 million in each of 1998
and 1997, and $1 million in 1996.

NOTE 8: FINANCIAL INSTRUMENTS

Fair Value

The fair values of the Company's financial instruments are not
materially different from the carrying amounts, except for long-
term debt and preferred stock. The carrying amounts and fair values
of long-term debt are $1.0 billion and $1.1 billion, respectively,
at December 31, 1998, and $1.1 billion and $1.2 billion,
respectively, at December 31, 1997. The carrying amounts and fair
values of preferred stock are $22 million and $8 million,
respectively, at December 31, 1998, and $97 million and $95
million, respectively, at December 31, 1997. The fair values of
the first-mortgage bonds and preferred stock are estimated based on
quoted market prices for them or for similar issues. The fair
values of long-term notes payable are based on the present value of
the future cash flows, discounted at rates available for similar
notes with comparable maturities.

Off-Balance-Sheet Financial Instruments

The Company's policy is to use derivative financial instruments to
manage its exposure to fluctuations in interest rates, foreign-
currency exchange rates and energy prices. Transactions involving
these financial instruments expose the Company to market and credit
risks which may at times be concentrated with certain
counterparties, although counterparty nonperformance is not
anticipated.

Energy Derivatives

As a result of the GCIM (see Note 11), the Company enters into a
certain amount of natural gas futures contracts in the open market
with the intent of reducing natural gas costs within the GCIM
tolerance band. The Company's policy is to use natural gas futures
contracts to mitigate risk and better manage natural gas costs. The
CPUC has approved the use of natural gas futures for managing risk
associated with the GCIM. For the years ended December 31, 1998,
1997 and 1996, gains and losses from natural gas futures contracts
are not material to SoCalGas' financial statements.

NOTE 9: SHAREHOLDERS' EQUITY

- -----------------------------------------------------------------
At December 31,
(Dollars in millions) 1998 1997
- -----------------------------------------------------------------
COMMON EQUITY:
Common stock, without par value,
authorized 100,000,000 shares,
91,300,000 shares outstanding $ 835 $ 835
Retained earnings 525 535
--------------------------
Total common equity $ 1,360 $ 1,370
- -----------------------------------------------------------------

All shares of SoCalGas common stock are wholly owned by Pacific
Enterprises.

- -----------------------------------------------------------------
December 31,
(Dollars in millions) 1998 1997
- -----------------------------------------------------------------
PREFERRED STOCK:
Not subject to mandatory redemption:
$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
7.75% Series - 75
--------------
$22 $97
- -----------------------------------------------------------------

None of SoCalGas' series of preferred stock are callable. All
series have one vote per share and cumulative preferences as to
dividends. On February 2, 1998, SoCalGas redeemed all outstanding
shares of 7.75% Series Preferred Stock at a price per share of $25
plus $0.09 of dividends accruing to the date of redemption. The
total cost to SoCalGas was approximately $75.3 million.

Dividend Restrictions
The CPUC regulates SoCalGas' capital structure, limiting the
dividends it may pay. At December 31, 1998, $233 million of
SoCalGas' retained earnings was available for future dividends.

NOTE 10: CONTINGENCIES AND COMMITMENTS

Natural Gas Contracts

SoCalGas buys natural gas under several short-term and long-term
contracts. Short-term purchases are based on monthly spot market
prices. SoCalGas has commitments for firm pipeline capacity under
contracts with pipeline companies that expire at various dates
through the year 2006. These agreements provide for payments of an
annual reservation charge. SoCalGas recovers such fixed charges in
rates.

At December 31, 1998, the future minimum payments under natural
gas contracts were:
- ---------------------------------------------------------------------
Storage and
(Dollars in millions) Transportation Natural Gas
- ---------------------------------------------------------------------
1999 $ 184 $ 270
2000 186 150
2001 188 153
2002 188 157
2003 184 158
Thereafter 460 -
-------------------------------
Total minimum payments $1,390 $ 888
- ---------------------------------------------------------------------

Total payments under the short-term and long-term contracts were $0.9
billion in 1998, $1.1 billion in 1997, and $0.9 billion in 1996.

Leases

SoCalGas has operating leases on real and personal property expiring
at various dates from 1999 to 2030. The rentals payable under these
leases are determined on both fixed and percentage bases, and most
leases contain options to extend, which are exercisable by SoCalGas.

The minimum rental commitments payable in future years under all
noncancellable leases are:
Operating
(Dollars in millions) Leases
- -----------------------------------------------------------------
1999 $ 30
2000 30
2001 29
2002 29
2003 30
Thereafter 248
- -----------------------------------------------------------------
Total future rental commitment $ 396
- -----------------------------------------------------------------

Rent expense totaled $43 million in 1998, $44 million in 1997
and $45 million in 1996.

Other Commitments and Contingencies

At December 31, 1998 commitments for capital expenditures were
approximately $8 million.

Environmental Issues

SoCalGas believes that its operations are conducted in accordance
with federal, state and local environmental laws and regulations
governing hazardous wastes, air and water quality, land use, and
solid waste disposal. SoCalGas incurs significant costs to operate
its facilities in compliance with these laws and regulations. The
costs of compliance with environmental laws and regulations generally
have been recovered in customer rates.
In 1994, the CPUC approved the Hazardous Waste Collaborative
Memorandum account allowing utilities to recover their hazardous
waste costs, including those related to Superfund sites or similar
sites requiring cleanup. Recovery of 90 percent of 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.
Environmental liabilities that may arise are recorded when remedial
efforts are probable and the costs can be estimated.
SoCalGas' capital expenditures to comply with environmental laws
and regulations were $1 million in 1998, $1 million in 1997, and $3
million in 1996, and are not expected to be significant over the next
five years.
The Company has identified and reported to California
environmental authorities 42 former manufactured-gas plant sites
for which it (together with other utilities as to 21 of these
sites) may have remedial obligations under environmental laws. As
of December 31, 1998, 12 of these sites have been remediated, of
which 10 have received certification from the California
Environmental Protection Agency. Preliminary investigations, at a
minimum, have been completed on 39 of the gas plant sites. At
December 31, 1998, the Company's estimated remaining investigation
and remediation liability for these sites was $68 million, of which
90 percent is authorized to be recovered through the Hazardous
Waste Collaborative Mechanism. In addition, the Company has been
named as a potentially responsible party for two landfill sites and
two industrial waste disposal sites. The total cost estimate for
remediation of these four sites is $4 million. The Company believes
that any costs not ultimately recovered through rates, insurance or
other means, upon giving effect to previously established
liabilities, will not have a material adverse effect on the
Company's consolidated results of operations or financial position.
SoCalGas has been associated with various other sites which may
require remediation under federal, state or local environmental laws.
SoCalGas is unable to determine the extent of its responsibility for
remediation of these sites until assessments are completed.
Furthermore, the number of others that also may be responsible, and
their ability to share in the cost of the cleanup, is not known. The
Company does not anticipate that such costs, net of the portion
recoverable in rates, will be significant.

Litigation

SoCalGas is involved in various legal matters arising out of the
ordinary course of business. Management believes that these matters
will not have a material adverse effect on the Company's results of
operations, financial condition or liquidity.

Concentration of Credit Risk

SoCalGas grants credit to its utility customers, substantially all of
whom are located in its service territory, which covers most of
Southern California and a portion of central California.

NOTE 11: REGULATORY MATTERS

Natural Gas Industry Restructuring

The natural gas industry experienced an initial phase of
restructuring during the 1980s by deregulating natural gas sales to
noncore customers. On January 21, 1998, the CPUC released a staff
report initiating a project to assess the current market and
regulatory framework for California's natural gas industry. The
general goals of the plan are to consider reforms to the current
regulatory framework emphasizing market-oriented policies
benefiting California natural gas consumers.
On August 25, 1998, California adopted a law prohibiting the
CPUC from enacting any natural gas industry restructuring decision
for customers prior to January 1, 2000. During the moratorium, the
CPUC will hold hearings throughout the state and intends to give
the California Legislature a report for its review detailing
specific recommendations for changing the natural gas market within
California. SoCalGas will actively participate in this effort.

Performance-Based Regulation (PBR)

To promote efficient operations and improved productivity and to
move away from reasonableness reviews and disallowances, the CPUC
has been directing utilities to use PBR. PBR has replaced the
general rate case and certain other regulatory proceedings for
SoCalGas. Under PBR, regulators require future income potential to
be tied to achieving or exceeding specific performance and
productivity measures, as well as cost reductions, rather than
relying solely on expanding utility rate base in a market where a
utility already has a highly developed infrastructure.
SoCalGas' PBR is in effect through December 31, 2002; however,
the CPUC decision allows for the possibility that changes to the
PBR mechanism could be adopted in a decision to be issued in
SoCalGas' 1999 Biennial Cost Allocation Proceeding, which is
anticipated to become effective before year end 1999. Key elements
of the SoCalGas PBR include an initial reduction in base rates, an
indexing mechanism that limits future rate increases to the
inflation rate less a productivity factor, a sharing mechanism with
customers if earnings exceed the authorized rate of return on rate
base, and rate refunds to customers if service quality
deteriorates. Specifically, the key elements of SoCalGas' PBR
include the following:

- --Earnings up to 25 basis points in excess of the authorized rate
of return on rate base are retained 100 percent by shareholders.
Earnings that exceed the authorized rate of return on rate base by
greater than 25 basis points are shared between customers and
shareholders on a sliding scale that begins with 75 percent of the
additional earnings being given back to customers and declining to
0 percent as earned returns approach 300 basis points above
authorized amounts. There is no sharing if actual earnings fall
below the authorized rate of return. In 1999, SoCalGas is
authorized to earn a 9.49 percent return on rate base, the same as
in 1998.

- --Revenue or base margin per customer is indexed based on inflation
less an estimated productivity factor of 2.1 percent in the first
year (1998), increasing 0.1 percent per year up to 2.5 percent in
the fifth year (2002). This factor includes 1 percent to
approximate the projected impact of a declining rate base.

- --The CPUC decision allows for pricing flexibility for residential
and small commercial customers, with any shortfalls in revenue
being borne by shareholders and with any increase in revenue shared
between shareholders and customers.

Under SoCalGas' PBR, annual cost of capital proceedings are
replaced by an automatic adjustment mechanism if changes in certain
indices exceed established tolerances. The mechanism is triggered
if the 12-month trailing average of actual market interest rates
increases or decreases by more than 150 basis points and is
forecasted to continue to vary by at least 150 basis points for the
next year. If this occurs, there would be an automatic adjustment
of rates for the change in the cost of capital according to a
preestablished formula, which applies a percentage of the change to
various capital components.

Comprehensive Settlement Of Natural Gas Regulatory Issues

In July 1994, the CPUC approved a comprehensive settlement for
SoCalGas (Comprehensive Settlement) of a number of regulatory
issues, including rate recovery of a significant portion of the
restructuring costs associated with certain long-term contracts
with suppliers of California-offshore and Canadian natural gas. In
the past, the cost of these supplies had been substantially in
excess of SoCalGas' average delivered cost for all natural gas
supplies. The restructured contracts substantially reduced the
ongoing delivered costs of these supplies. The Comprehensive
Settlement permits SoCalGas to recover in utility rates
approximately 80 percent of the contract-restructuring costs of
$391 million and accelerated amortization of related pipeline
assets of approximately $140 million, together with interest,
incurred prior to January 1, 1999. In addition to the supply
issues, the Comprehensive Settlement addressed the following other
regulatory issues:

- --Noncore Customer Rates. The Comprehensive Settlement changed the
procedures for determining noncore rates to be charged by SoCalGas
for the five-year period commencing August 1, 1994. These rates are
based upon SoCalGas' recorded throughput to these customers for
1991. SoCalGas will bear the full risk of any declines in noncore
deliveries from 1991 levels. Any revenue enhancement from
deliveries in excess of 1991 levels will be limited by a crediting
account mechanism that will require a credit to customers of 87.5
percent of revenues in excess of certain limits. These annual
limits above which the credit is applicable increase from $11
million to $19 million over the five-year period from August 1,
1994, through July 31, 1999. SoCalGas' ability to report as
earnings the results from revenues in excess of SoCalGas'
authorized return from noncore customers due to volume increases
has been limited for the five years beginning August 1, 1994, as a
result of the Comprehensive Settlement. The 1999 Biennial Cost
Allocation Proceeding is intended to adopt measures to replace this
aspect of the Comprehensive Settlement when it expires during 1999.

- --Gas Cost Incentive Mechanism (GCIM). On April 1, 1994, SoCalGas
implemented a new process for evaluating its natural gas purchases,
substantially replacing the previous process of reasonableness
reviews. Initially a three-year pilot program, in December 1998 the
CPUC extended the GCIM program indefinitely. Automatic annual
extensions to the program will continue unless the CPUC issues an
order stating otherwise.
GCIM compares SoCalGas' cost of natural gas with a benchmark
level, which is the average price of 30-day firm spot supplies in
the basins in which SoCalGas purchases the natural gas. 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 equally between customers and
shareholders.
The CPUC approved the use of natural gas futures for managing
risk associated with the GCIM. SoCalGas enters into natural gas
futures contracts in the open market on a limited basis to mitigate
risk and better manage natural gas costs.
In June 1997, SoCalGas requested a shareholder award of $11
million, which was approved by the CPUC in June 1998 and is
included in pretax income in 1998. In June 1998, SoCalGas filed its
annual GCIM application with the CPUC, requesting an award of $2
million for the annual period ended March 31, 1998. This request
was approved by the CPUC in December 1998 and is included in pretax
income in 1998.

- --Attrition Allowances. The Comprehensive Settlement authorized
SoCalGas an annual allowance for increases in operating and
maintenance expenses. However, no attrition allowance was
authorized for 1997 and beyond, based on an agreement reached as
part of the PBR application.
SoCalGas recorded the impact of the Comprehensive Settlement
in 1993. Upon giving effect to liabilities previously recognized,
the costs of the Comprehensive Settlement, including the
restructuring of natural gas supply contracts, did not result in
any future charge to earnings.

Biennial Cost Allocation Proceeding (BCAP)

In the second quarter of 1997, the CPUC issued a decision on
SoCalGas' 1996 BCAP filing.
In this decision, the CPUC considered SoCalGas'
relinquishments of interstate pipeline capacity on both the El Paso
and Transwestern pipelines. This resulted in a reduction in the
pipeline demand charges allocated to SoCalGas' customers and
surcharges allocated to firm capacity holders through pipeline
rate-case settlements adopted at the FERC. However, the CPUC and
FERC are reviewing the decision.
In October 1998, SoCalGas filed 1999 BCAP applications
requesting that new rates become effective August 1, 1999 and
remain in effect through December 31, 2002. The proposed beginning
date follows the conclusion of the Comprehensive Settlement
(discussed above), and the proposed end date aligns with the
expiration of SoCalGas' PBR. The application seeks overall
decreases in natural gas revenues of $204 million.

Cost of Capital

Under PBR, annual Cost of Capital proceedings were replaced by an
automatic adjustment mechanism if changes in certain indices exceed
established tolerances. For 1999, SoCalGas is authorized to earn a
rate of return on common equity of 11.6 percent and a 9.49 percent
return on rate base, the same as in 1998, unless interest-rate
changes are large enough to trigger an automatic adjustment as
discussed above under "Performance-Based Regulation."

Transactions with Affiliates

On December 16, 1997, the CPUC adopted rules, effective January 1,
1998, establishing uniform standards of conduct governing the
manner in which IOUs conduct business with their energy-related
affiliates. The objective of the affiliate-transaction rules is to
ensure that these affiliates do not gain an unfair advantage over
other competitors in the marketplace and that utility customers do
not subsidize affiliate activities. The rules establish standards
relating to non-discrimination, disclosure and information
exchange, and separation of activities.
The CPUC excluded utility-to-utility transactions between
SDG&E and SoCalGas from the affiliate-transaction rules in its
March 1998 decision approving the business combination of Enova and
PE (see Note 1).
Other subsidiaries of PE sell and transport natural gas to the
Company under tariffs approved by the FERC. Billings for the
purchases totaled $252 million in each of the years 1998 and 1997
and $186 million in 1996. The Company has long-term natural gas
purchase and transportation agreements with the affiliates
extending through the year 2003 requiring certain minimum payments
which allow the affiliates to recover the construction cost of
their facilities. The Company is obligated to make minimum annual
payments to cover the affiliates' operation and maintenance
expenses, demand charges paid to their suppliers, current taxes
other than income taxes, and debt service costs, including interest
expense and scheduled retirement of debt. These long-term
agreements were restructured in conjunction with the Comprehensive
Settlement described above.
During 1998, 1997 and 1996, the Company sold natural gas
transportation and storage services to SDG&E in the amount of $55
million to $60 million per year. These sales were at rates
established by the CPUC.

NOTE 12: SEGMENT INFORMATION

The Company has two separately managed reportable segments:
natural gas distribution, and natural gas transmission/storage.
The accounting policies of the segments are the same as those
described in Note 2, and segment performance is evaluated by
management based on reported operating income. Intersegment
transactions are generally recorded the same as sales or
transactions with third parties. Interest expense and income tax
expense are not allocated to the reportable segments. Interest
revenue ($4 million, $16 million and $5 million for the years
ended December 31, 1998, 1997 and 1996, respectively) is included
in other income on the Statements of Consolidated Income herein.
It is not allocated to the reportable segments and, therefore, is
not presented in the tables below.

- --------------------------------------------------------------------
For the year ended December 31,
(Dollars in millions) 1998 1997 1996
- --------------------------------------------------------------------
Revenues:
Distribution $ 2,159 $ 2,283 $ 2,096
Transmission & storage 266 337 343
All other 2 21 (17)
------------------------------------
Total $ 2,427 $ 2,641 $ 2,422
------------------------------------
Depreciation and amortization:
Distribution $ 200 $ 197 $ 193
Transmission & storage 54 54 55
------------------------------------
Total $ 254 $ 251 $ 248
------------------------------------
Segment Income:
Distribution $ 300 $ 383 $ 379
Transmission & storage 64 87 68
All other -- 22 (16)
------------------------------------
Total segment income 364 492 431
------------------------------------
Interest expense (80) (87) (86)
Income tax expense (128) (178) (148)
Nonoperating income 3 11 4
------------------------------------
Net income $ 159 $ 238 $ 201
------------------------------------
- --------------------------------------------------------------------
At December 31, or for
the year then ended
1998 1997 1996
- --------------------------------------------------------------------
Assets:
Distribution $ 2,373 $ 2,946 $ 2,881
Transmission & storage 1,184 1,207 1,211
All other 277 52 262
------------------------------------
Total $ 3,834 $ 4,205 $ 4,354
------------------------------------
Capital Expenditures:
Distribution $ 92 $ 110 $ 124
Transmission & storage 15 24 29
All other 21 25 44
------------------------------------
Total $ 128 $ 159 $ 197
------------------------------------
Geographic Information:
Long-lived assets
United States $ 2,955 $ 3,077 $ 3,169
- --------------------------------------------------------------------

NOTE 13: SUBSEQUENT EVENT

On February 22, 1999, Sempra Energy and KN Energy, Inc. (KN Energy)
announced that their respective boards of directors approved Sempra
Energy's acquisition of KN Energy, subject to approval by the
shareholders of both companies and by various federal and state
regulatory agencies. If the transaction is approved, holders of KN
Energy common stock will receive 1.115 shares of Sempra Energy
common stock or $25 in cash, or some combination thereof, for each
share of KN Energy common stock. In the aggregate, the cash portion
of the transaction will constitute not more than 30 percent of the
total consideration of $1.7 billion. The companies anticipate that
the closing will occur in six to eight months. The transaction will
be treated as a purchase for accounting purposes.

NOTE 14: QUARTERLY FINANCIAL DATA (UNAUDITED)

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

1998
Operating revenues $ 664 $ 578 $ 520 $ 665
Operating expenses 594 537 449 609
-----------------------------------------------------
Operating income $ 70 $ 41 $ 71 $ 56
-----------------------------------------------------
Net income $ 48 $ 19 $ 54 $ 38
Dividends on preferred stock 1 - - -
-----------------------------------------------------
Net income applicable
to common shares $ 47 $ 19 $ 54 $ 38
=====================================================
1997
Operating revenues $ 738 $ 575 $ 607 $ 721
Operating expenses 656 484 535 648
-----------------------------------------------------
Operating income $ 82 $ 91 $ 72 $ 73
-----------------------------------------------------
Net income $ 60 $ 72 $ 55 $ 51
Dividends on preferred stock 2 2 1 2
-----------------------------------------------------
Net income applicable
to common shares $ 58 $ 70 $ 54 $ 49
=====================================================

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

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information required on Identification of Directors is
incorporated by reference from "Election of Directors" in the
Information Statement prepared for the May 1999 annual meeting of
shareholders. The information required on the Company's executive
officers is set forth in Item 4 herein.

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 1999 annual meeting of
shareholders.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT

The information required by Item 12 is incorporated by reference
from "Election of Directors" in the Information Statement prepared
for the May 1999 annual meeting of shareholders.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

None.

PART IV

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

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

1. Financial statements
Page in
This Report

Independent Auditors' Report . . . . . . . . . . . . . . 27

Statements of Consolidated Income for the years
ended December 31, 1998, 1997 and 1996 . . . . . . . . 28

Consolidated Balance Sheets at December 31,
1998 and 1997. . . . . . . . . . . . . . . . . . . . . 29

Statements of Consolidated Cash Flows for the
years ended December 31, 1998, 1997 and 1996 . . . . . 31

Statements of Consolidated Changes in
Shareholders' Equity for the years ended
December 31, 1998, 1997 and 1996 . . . . . . . . . . . 32

Notes to Consolidated Financial Statements . . . . . . . 33

Quarterly Financial Data (Unaudited) . . . . . . . . . . 50

2. Financial statement schedules
None.

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 notes to the
Consolidated Financial Statements herein.

3. Exhibits

See Exhibit Index on page 53 of this report.

(b) Reports on Form 8-K

There were no reports on Form 8-K filed after September 30, 1998.

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/ Warren I. Mitchell .
Warren I. Mitchell
Chairman and President

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

Name/Title Signature Date

Principal Executive Officers:
Warren I. Mitchell
Chairman, President /s/ Warren I. Mitchell March 2, 1999

Principal Financial Officer:
Debra L. Reed
Senior Vice President,
Chief Financial Officer /s/ Debra L. Reed March 2, 1999

Principal Accounting Officer:
Debra L. Reed
Senior Vice President,
Chief Financial Officer /s/ Debra L. Reed March 2, 1999

Directors:
Warren I. Mitchell
Chairman /s/ Warren I. Mitchell March 2, 1999

Hyla H. Bertea
Director /s/ Hyla H. Bertea March 2, 1999

Ann Burr
Director /s/ Ann Burr March 2, 1999

Herbert L. Carter
Director /s/ Herbert L. Carter March 2, 1999

Richard A. Collato
Director /s/ Richard A. Collato March 2, 1999

Daniel W. Derbes
Director /s/ Daniel W. Derbes March 2, 1999

Wilford D. Godbold, Jr.
Director /s/ Wilford D. Godbold, Jr. March 2, 1999

Robert H. Goldsmith
Director /s/ Robert H. Goldsmith March 2, 1999

William D. Jones
Director /s/ William D. Jones March 2, 1999

Ignacio E. Lozano, Jr.
Director /s/ Ignacio E. Lozano, Jr. March 2, 1999

Ralph R. Ocampo
Director /s/ Ralph R. Ocampo March 2, 1999

William G. Ouchi
Director /s/ William G. Ouchi March 2, 1999

Richard J. Stegemeier
Director /s/ Richard J. Stegemeier March 2, 1999

Thomas C. Stickel
Director /s/ Thomas C. Stickel March 2, 1999

Diana L. Walker
Director /s/ Diana L. Walker March 2, 1999

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

3.02 Bylaws of Southern California Gas Company dated September 1, 1998.

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

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

4.03 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).

4.04 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).

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

4.06 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).

4.07 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).

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

4.09 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).

4.10 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 Lighting
Corporation 1987 Form 10-K; Exhibit 4.11).

4.11 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).

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

Exhibit 10 -- Material Contracts

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

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

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

10.04 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)).

10.05 Enova Corporation 1986 Long-Term Incentive Plan amended and restated as
the Sempra Energy 1986 Long-Term Incentive Plan (Incorporated by
reference from the Registration Statement on Form S-8 Sempra Energy
Registration No. 333-56161(Exhibit 4.3)).

10.06 Pacific Lighting Corporation Stock Incentive Plan amended and restated
as the Sempra Energy Stock Incentive Plan (Incorporated by reference
from the Registration Statement on Form S-8 Sempra Energy Registration
No. 333-56161 (Exhibit 4.4)).

10.07 Pacific Enterprises Employee Stock Option Plan amended and restated as
the Sempra Energy Employee Stock Option Plan (Incorporated by reference
from the Registration Statement on Form S-8 Sempra Energy Registration
No. 333-56161 (Exhibit 4.5)).

10.08 Restatement and Amendment of Pacific Enterprises 1979 Stock Option Plan
(Registration Statement No. 2-66833 filed by Pacific Lighting
Corporation on March 5, 1980; Exhibit 1.1).

10.09 Pacific Enterprises Supplemental Medical Reimbursement Plan for Senior
Officers (Pacific Lighting Corporation 1980 Form 10-K; Exhibit 10.24).

10.10 Pacific Enterprises Financial Services Program for Senior Officers
(Pacific Lighting Corporation 1980 Form 10-K; Exhibit 10.25).

10.11 Southern California Gas Company Retirement Savings Plan, as amended and
restated as of August 30, 1988 (Registration Statement No. 33-6357 filed
by Pacific Enterprises on December 30, 1988; Exhibit 28.02).

10.12 Southern California Gas Company Statement of Life Insurance, Disability
Benefit and Pension Plans, as amended and restated as of January 1,
1985 (Southern California Gas Company 1984 Form 10-K; Exhibit 10.27).

10.13 Southern California Gas Company Pension Restoration Plan For Certain
Management Employees (Pacific Lighting Corporation 1980 Form 10-K;
Exhibit 10.29).

10.14 Pacific Enterprises Executive Incentive Plan (Pacific Lighting
Corporation 1987 Form 10-K; Exhibit 10.13).

10.15 Pacific Enterprises Deferred Compensation Plan for Key Management
Employees (Registration Statement No. 33-6357 filed by Pacific
Enterprises on December 30, 1988; Exhibit 10.41).

10.16 Pacific Enterprises Stock Incentive Plan (Registration Statement No.
33-21908 filed by Pacific Enterprises on May 17, 1988; Exhibit 4.01).

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

10.18 Master Affiliate Service Agreement dated as of September 1, 1996
between Southern California Gas Company and Pacific Enterprises Energy
Services, as amended (Southern California Gas Company 1996 Form 10-K;
Exhibit 10.11).

Exhibit 21 -- Subsidiaries

21.01 See Note 1 of the Notes to Consolidated Financial Statements and
Management's Discussion and Analysis of Financial Condition and Results
of Operations contained in Part II, Items 7 and 8 herein.

Exhibit 23 -- Consents Of Experts And Counsel

23.01 Independent Auditors' Consent

Exhibit 27 -- Financial Data Schedule

27.01 Financial Data Schedule for the year ended December 31, 1998.

GLOSSARY

BCAP Biennial Cost Allocation Proceeding

Bcf Billion Cubic Feet (of natural gas)

CPUC California Public Utilities Commission

Enova Enova Corporation

EOR Enhanced Oil Recovery

FASB Financial Accounting Standards Board

FERC Federal Energy Regulatory Commission

GCIM Gas Cost Incentive Mechanism

GRC General Rate Case

IDBs Industrial Development Bonds

IOUs Investor-Owned Utilities

IT Information Technology

Mcf Thousand Cubic Feet (of natural gas)

Mmcfd Million Cubic Feet (of natural gas) per day

ORA Office of Ratepayer Advocates

PBR Performance-Based Ratemaking

PE Pacific Enterprises, the Company's parent

PRP Potential Responsible Party

ROE Return on Equity

ROR Rate of Return

SDG&E San Diego Gas & Electric Company

SEC Securities and Exchange Commission

SFAS Statement of Financial Accounting Standards

SoCalGas Southern California Gas Company

UEG Utility electric generation

VaR Value at Risk
55

18