PACIFIC ENTERPRISES INC - 10-K Annual Report

Back to GetFilings.com

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

(Mark One)
[X] Annual report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 For the fiscal year ended December 31, 1998
--------------------
OR
[ ] Transition report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934 For the transition period from
to
- ------ -------
PACIFIC ENTERPRISES
- -------------------------------------------------------------------
(Exact name of registrant as specified in its charter)

CALIFORNIA 1-40 94-0743670
- -------------------------------------------------------------------
(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: American and Pacific
$4.75 dividend
$4.50 dividend
$4.40 dividend
$4.36 dividend

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 67. Glossary on page 70.

Aggregate market value of the voting preferred stock held by non-
affiliates of the registrant as of March 26, 1999 was
$67.6 million.

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

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. . 12
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 . . . . . . . . . . . . . . . . . 29
Item 8. Financial Statements and Supplementary Data. . . . . . 30
Item 9. Changes In and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . 61

PART III
Item 10. Directors and Executive Officers of the Registrant . . 61
Item 11. Executive Compensation . . . . . . . . . . . . . . . . 61
Item 12. Security Ownership of Certain Beneficial Owners
and Management. . . . . . . . . . . . . . . . . . . 62
Item 13. Certain Relationships and Related Transactions . . . . 62

PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . . 62

Independent Auditors' Consent and Report on Schedule. . . . . . 63

Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . 66

Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . 67

Glossary. . . . . . . . . . . . . . . . . . . . . . . . . . . . 70

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
Pacific Enterprises (PE or the Company) is an energy services company
whose principal subsidiary is Southern California Gas Company
(SoCalGas), the nation's largest natural gas distribution utility.
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 which provides electric
and natural gas service to San Diego County and southern Orange
County, is the principal subsidiary of Enova. Further discussion of
PE 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

PE's principal subsidiary, SoCalGas, is regulated by local, state and
federal agencies, as described below. Regulation of PE's other
subsidiaries is insignificant.

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
- -------------------------------------------------------------------
Operating 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

Other Operating Revenues 45 97 141
--------- --------- ----------
$ 2,472 $ 2,738 $ 2,563
========= ========= ==========

Industry segment information is contained in "Management's Discussion
and Analysis of Financial Condition and Results of Operations" and in
Note 14 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.

SoCalGas offers two basic 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
SoCalGas buys natural gas under several short-term and long-term
contracts. Short-term purchases are based on monthly-spot-market
prices. SoCalGas has pipeline capacity contracts with pipeline
companies that expire at various dates through 2006.

Most of the natural gas purchased and delivered by SoCalGas is
produced outside of California. These supplies are delivered to
SoCalGas' intrastate transmission system by interstate pipeline
companies, primarily El Paso Natural Gas Company and Transwestern
Natural Gas Company. These interstate companies provide
transportation services for supplies purchased from other sources by
SoCalGas 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
Affiliate 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 SoCalGas 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, SoCalGas delivered 962 bcf of natural gas through its
system. Approximately 66 percent of these deliveries were customer-
owned natural gas for which SoCalGas provided transportation
services. The balance of natural gas deliveries was gas purchased
by SoCalGas and resold to customers. SoCalGas 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 SoCalGas.
Core aggregate transportation customers are permitted to aggregate
their natural gas requirement and, up to a CPUC-imposed limit of 10
percent of SoCalGas' core market, to purchase natural gas directly
from brokers or producers. SoCalGas 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
SoCalGas 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 SoCalGas or from other sources, such as brokers or producers,
for delivery through SoCalGas' 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, SoCalGas generally earns the same margin whether
SoCalGas buys the gas and sells it to the customer or transports
natural gas already owned by the customer.

SoCalGas also provides natural gas storage services for noncore and
off-system customers on a bid and negotiated contract basis. The
storage service program provides opportunities for customers to
store natural gas on an "as available" basis, usually during the
summer to reduce winter purchases when natural gas costs are
generally higher. As of December 31, 1998, SoCalGas 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. SoCalGas added approximately 46,000
new meters in 1998. This represents a growth rate of approximately
0.9 percent. SoCalGas expects its growth for 1999 will continue at
about the 1998 level.

During 1998, 97 percent of residential energy customers in
SoCalGas' 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 SoCalGas' 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 SoCalGas' 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 its 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 12 and 13 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 13 of the "Notes to Consolidated Financial
Statements" herein.

Balancing Accounts
In general, earnings fluctuations from changes in the costs of
natural gas and consumption levels for the majority of natural gas
are eliminated 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 13 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 13 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 13 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 13 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 13 of
the "Notes to Consolidated Financial Statements" herein.

ENVIRONMENTAL MATTERS

Discussions about environmental issues, 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 $1.1 million. In 1998, SoCalGas
completed work efforts of $225,000. 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 $.06 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. Subsequent to the business
combination, PE employees were shifted to Sempra Energy and
operating units, and PE now has no direct employees.

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.

Foreign Operations
A discussion of PE's foreign operations is included in
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" and in Note 3 of the "Notes to Consolidated
Financial Statements" herein.

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.

PE and its subsidiaries own or lease 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
- -------------------------------------------------------------------
Richard D. Farman 63 Chairman and Chief Executive
Officer

Stephen L. Baum 57 President and Chief Operating
Officer

John R. Light 57 Executive Vice President and
General Counsel

Neal E. Schmale 51 Executive Vice President and
Chief Financial Officer

Frank H. Ault 54 Vice President and Controller

Charles A. McMonagle 48 Vice President and Treasurer

Thomas C. Sanger 55 Corporate Secretary

* As of December 31, 1998.

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

PART II

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

As a result of the formation of Sempra Energy (see Note 1 of "Notes
to Consolidated Financial Statements" herein), all of the issued
and outstanding common stock of PE is owned by Sempra Energy. The
information required by Item 5 concerning dividends declared is
included in the "Statements of Consolidated Changes in
Shareholders' Equity" set forth in Item 8 of this Annual Report
herein.

Dividend Restrictions
At December 31, 1998, $103 million of PE's retained earnings was
available for future dividends, due to the CPUC's regulation of
SoCalGas' capital structure.

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:
Revenues and Other Income $2,472 $2,777 $2,588 $2,377 $2,702
Operating Income $ 341 $ 438 $ 451 $ 422 $ 439
Earnings Applicable to
Common Shares $ 143 $ 180 $ 196 $ 175 $ 160

Balance Sheet Data:
Total Assets $4,598 $4,977 $5,186 $5,259 $5,445
Long-Term Debt $ 985 $1,118 $1,225 $1,371 $1,550
Short-Term Debt (a) $ 249 $ 502 $ 411 $ 334 $ 406
Shareholders' Equity $1,547 $1,469 $1,440 $1,483 $1,428

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

Since Pacific Enterprises is a wholly owned subsidiary of Sempra Energy, 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
Pacific Enterprises (PE 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.
PE is a California-based utility holding company whose principal
subsidiary is Southern California Gas Company (SoCalGas), the
nation's largest natural gas distribution utility, serving 4.8
million meters throughout most of southern California and part of
central California. SoCalGas delivers natural gas and related
services to residential and small commercial and industrial customers
and stores and transports natural gas for utility electric generation
and wholesale customers. The company, jointly with Enova Corporation
(Enova), the parent corporation of San Diego Gas & Electric, owns and
operates Sempra Energy Solutions (Solutions) and Sempra Energy
Trading. Sempra Energy Solutions is engaged in the buying and selling
of natural gas for large users, integrated energy management services
targeted at large governmental and commercial facilities, and
consumer-market products and services. Sempra Energy Trading is
engaged in the wholesale trading and marketing of natural gas, power
and petroleum. Through other subsidiaries the Company owns and
operates interstate and offshore natural gas pipelines and
centralized heating and cooling for large building complexes, and is
involved in domestic and international energy-utility operations, and
other energy-related products and services.
In January 1998, the Company and Enova jointly acquired CES/Way
International, Inc., through the jointly owned Solutions. CES/Way
provides energy-efficiency services including energy audits,
engineering design, project management, construction, financing and
contract maintenance.

Business Combination
Sempra Energy was formed to serve as a holding company for the
Company and Enova 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, and $9 million,
aftertax, for the years ended December 31, 1998 and 1997,
respectively. 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 Company 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 and of SoCalGas remained outstanding.
The combination was approved by the shareholders of both companies on
March 11, 1997 and was a tax-free transaction.
In conjunction with the PE/Enova Business Combination, on
September 30, 1998 PE's ownership interests in certain non-utility
subsidiaries were dividended to Sempra Energy at book value.

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. Nonutility cash requirements include investments in
Sempra Energy Solutions, Sempra Energy Trading, CES/Way
International, and other domestic and international ventures.
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 $ 598 $ 350 $ 608
----------------------------------
Investing activities:
Capital expenditures (150) (187) (204)
Acquisitions of companies (45) (138) (62)
Other 6 62 (20)
---------------------------------
Total investing activities (189) (263) (286)
----------------------------------
Financing activities:
Long-term debt - net (75) (125) (97)
Short-term debt - net (311) 92 29
Issuance of common stock 27 17 8
Repurchase of common stock -- (48) (24)
Redemption of preferred stock (75) -- (210)
Dividends on common and
preferred stock (101) (126) (123)
----------------------------------
Total financing activities (535) (190) (417)
----------------------------------
Decrease in cash
and cash equivalents $ (126) $ (103) $ (95)
- -------------------------------------------------------------------

Cash Flows from Operating Activities
The increase in cash flows from operating activities in 1998 was
primarily due to lower working capital requirements for natural gas
operations in 1998. This 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 capital
expenditures at SoCalGas and investments in new businesses.
Capital expenditures were $37 million lower in 1998 primarily due
to the shifting of certain functions to Sempra Energy following the
PE/Enova Business Combination.
Capital expenditures were $17 million lower in 1997 than in 1996
due to lower spending at SoCalGas 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 and a plant expansion at a non-utility
subsidiary.
Capital expenditures are estimated to be $180 million in 1999.
They will be financed primarily by internally generated funds and
will largely represent investment in utility operations.

Investments
In December 1997, the Company and Enova jointly acquired Sempra
Energy Trading for $225 million. In July 1998, Sempra Energy Trading
purchased Consolidated Natural Gas, a wholesale trading and
commercial marketing operation, for $36 million to expand its eastern
United States operations.
In May 1997, Sempra Energy Solutions together with Conectiv
Thermal Systems, Inc., formed two joint ventures to provide
integrated energy management services to commercial and industrial
customers. Specific projects of these joint ventures are described
in Note 3 of the notes to Consolidated Financial Statements.
As noted above, Sempra Energy Solutions acquired CES/Way
International, Inc. (CES/Way) in January 1998.
In March 1998, the Company increased its combined investment in
two Argentine natural gas utility holding companies from 12.5 percent
to 21.5 percent by purchasing an additional interest for $40 million.
Fluctuations in the Company's level of investments in the next
few years will depend primarily on the activities of its subsidiaries
other than SoCalGas.

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 13 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 at SoCalGas.

Stock Purchases and Redemption
The Company repurchased common stock of $48 million and $24 million
in 1997 and 1996, respectively. The Company did not repurchase common
stock in 1998. The repurchase program of the Company was suspended
as a result of the PE/Enova Business Combination.
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 amounted to $124
million, $126 million and $123 million in 1998, 1997 and 1996,
respectively. During 1998, prior to the PE/Enova Business
Combination, the Company declared and paid the first through third
quarter dividends. The increase in 1997 was primarily due to an
increase in the quarterly dividend rate in the second quarter of
1997, partially offset by a reduction in the number of shares
outstanding.
The payment of future dividends and the amount thereof is within
the discretion of the board of directors.

Capitalization
The debt-to-capitalization ratio was 44 percent at year-end 1998,
below the 51 percent ratio in 1997. The decrease was primarily due to
the repayment of debt. The debt-to-capitalization ratio was 51
percent at year-end 1997, slightly below the 52 percent ratio in
1996.

Cash and Cash Equivalents
Cash and cash equivalents were $27 million at December 31, 1998. This
cash is available for investment in energy-related domestic and
international projects, the retirement of debt and other corporate
purposes.
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 borrowing of up to $700
million, of which $43 million is outstanding at December 31, 1998.
For further discussion, see Note 4 of the notes to Consolidated
Financial Statements.

Results of Operations

1998 Compared to 1997
Net income for 1998 decreased to $147 million in 1998, compared to
net income of $184 million in 1997.
The decrease in net income is primarily due to costs associated
with the PE/Enova Business Combination and a lower base margin
established at SoCalGas in its Performance Based Regulation (PBR)
decision which became effective on August 1, 1997 (see Note 13 of the
notes to Consolidated Financial Statements). Expenses related to the
business combination were $35 million and $9 million, aftertax, for
1998 and 1997, respectively.
Also contributing to lower net income for 1998 were significant
start-up costs at Sempra Energy Solutions (see discussion under
"Other Operations" below.)

1997 Compared to 1996
Net income for 1997 decreased to $184 million compared to net income
of $203 million in 1996.
The decrease in net income is due primarily to costs associated
with the PE/Enova Business Combination, favorable litigation
settlements in 1996 and the absence of such in 1997, and start-up
costs and increased operating expenses related to energy products and
services offered by Sempra Energy Solutions. Partially offsetting
the lower consolidated net income in 1997 was an increase in
SoCalGas' net income in 1996 (see "SoCalGas Operations" for further
discussion).

Utility Operations
To understand the operations and financial results of PE, it is
important to understand the ratemaking procedures that SoCalGas
follows.
SoCalGas is regulated by the CPUC. It is the responsibility of
the CPUC to determine that utilities operate in the best interests of
their customers and have the opportunity to earn a reasonable return
on investment. In response to utility-industry restructuring, in 1997
SoCalGas received approval from the CPUC for performance-based
regulation (PBR).
PBR replaced the general rate case (GRC) procedure and certain
other regulatory proceedings through December 31, 2002. Under
ratemaking procedures in effect prior to PBR, SoCalGas 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 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 in Note 13 of the
notes to Consolidated Financial Statements.
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 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 natural gas industry restructuring
in Note 13 of the notes to Consolidated Financial Statements.

1998 Compared to 1997
SoCalGas' net income for 1998 decreased to $159 million, compared to
net income of $238 million in 1997. This decrease is primarily due to
costs associated with the PE/Enova Business Combination and a lower
base margin established at SoCalGas in its PBR decision, which became
effective on August 1, 1997 (see Note 13 of the notes to Consolidated
Financial Statements). The expense related to the PE/Enova Business
Combination was $35 million, aftertax, for 1998.
Utility natural gas revenues decreased 8 percent in 1998
primarily due to the lower 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
SoCalGas' net income for 1997 increased to $238 million, compared to
net income of $201 million in 1996. This increase in net income is
primarily due to increased throughput to utility electric generation
customers and lower operation and maintenance expenses than amounts
authorized in rates.
Utility 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 throughput to utility electric generation customers
due to increased demand for electricity.
Utility 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 expenses were relatively unchanged in 1997, because of
the Company's continued emphasis on reducing costs and reduced costs
in 1996 from favorable litigation settlements.

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 results of SoCalGas. Because of the ratemaking and regulatory
process, electric and natural gas industry restructurings, and the
changing energy marketplace, there are several factors that will
influence future financial performance. 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 15 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 13 of the notes to Consolidated
Financial Statements.

Regulatory Accounting Standards. SoCalGas has been accounting for
the economic effects of regulation on all of 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 13 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
SoCalGas and SDG&E from the affiliate-transaction rules in its
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 13 of the notes to Consolidated Financial Statements for
additional information.

Allowed Rate of Return. For 1998, SoCalGas 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 13 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. SoCalGas 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 achieve returns at
least at or in excess of authorized returns at levels experienced in
past years. See additional discussion of PBR in Note 13 of the notes
to Consolidated Financial Statements.

Electric Industry Restructuring. As a result of electric industry
restructuring, natural gas generated electricity within SoCalGas'
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
SoCalGas' 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 SoCalGas' service territory.

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. SoCalGas' throughput to enhanced oil recovery (EOR)
customers in the Kern County area has decreased significantly since
1992 because of the bypass of SoCalGas' system by competing
interstate pipelines. The decrease in revenues from EOR customers
did not have a material impact on SoCalGas' earnings.
Bypass of other markets also may occur, and SoCalGas 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. SoCalGas is continuing
to reduce its costs to maintain cost competitiveness in order to
retain transportation customers.

Noncore Pricing. To respond to bypass, SoCalGas 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 SoCalGas to better
compete with new interstate pipelines for noncore customers.

Noncore Throughput. SoCalGas' 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 SoCalGas' 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 13 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. SoCalGas 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 SoCalGas 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, SoCalGas' 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 12 of
the notes to Consolidated Financial Statements.

International Operations
Pacific Enterprises International (PEI) was established to
participate in the international natural gas infrastructure market
and began operations in March 1995.
Together with Enova International, PEI currently is involved in
natural gas transmission and distribution projects in Mexico,
Argentina and Uruguay. The Company will be pursuing projects in
other parts of Latin America.
In March 1998, PEI increased its existing investment in two
Argentine natural gas utility holding companies (Sodigas Pampeana
S.A. and Sodigas Sur S.A.) by purchasing an additional 9-percent
interest for $40 million. With this purchase, PEI's interest in the
holding companies was increased to 21.5 percent. The distribution
companies serve 1.2 million customers in central and southern
Argentina, respectively, and have a combined sendout of 650 million
cubic feet per day.
The net losses for international operations were $2 million, $8
million and $5 million for 1998, 1997 and 1996, respectively.

Other Operations
Sempra Energy Trading Corp. (SET), a leading natural gas and power
marketing firm headquartered in Stamford, Connecticut, was jointly
acquired by PE and Enova on December 31, 1997. The Company's
portion of the net losses was $6 million for the year ended December
31, 1998. The losses were primarily due to the amortization of costs
associated with the acquisition. Additional information concerning
SET is provided in Note 3 of the notes to Consolidated Financial
Statements.
Sempra Energy Solutions (Solutions), formed in 1997 and owned
equally by the Company and Enova, incorporates several existing
unregulated businesses from each of PE and Enova. It is pursuing a
variety of opportunities, including buying and selling natural gas
for large users, integrated energy-management services targeted at
large governmental and commercial facilities, and consumer-market
products and services such as earthquake shutoff valves. CES/Way
International, Inc. (CES/Way) acquired by Solutions in January 1998,
provides energy-efficiency services including energy audits,
engineering design, project management, construction, financing and
contract maintenance.
The Company's portion of Solutions' net losses was $21 million
and $7 million, aftertax, for 1998 and 1997, respectively. The
losses are primarily due to start-up costs.

Other Income, Interest Expense and Income Taxes
Other Income
Other income primarily consists of interest income from short-term
investments and regulatory balancing accounts. Other income was $20
million in 1998 compared to $46 million in 1997. The decrease was
primarily the result of lower interest income from short-term
investments. Other income increased in 1997 to $46 million from $25
million in 1996 primarily due to higher interest from short-term
investments during much of 1997.
Equity in losses of unconsolidated joint ventures and
partnerships represents the Company's portion of net income or
losses from Solutions, SET and PEI.

Interest Expense
Interest expense for 1998 decreased to $67 million from $103 million
in 1997. The decrease was primarily due to the repayment of short-
term debt in 1998. Interest expense for 1997 increased to $103
million from $97 million in 1996, as a result of a higher long-term
debt balance.

Income Taxes
Income tax expense was $127 million, $151 million and $151 million
in 1998, 1997 and 1996, respectively. This represents an effective
tax rate of 46 percent, 45 percent and 43 percent for the same
periods. The increase in the effective tax rate for 1997 was
primarily due to fewer deductions from capitalized information-
systems costs at SoCalGas.

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. The Company also uses and trades
derivative financial instruments in its energy trading and marketing
activities. 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.
Sempra Energy Trading derives a substantial portion of its
revenue from risk management and trading activities in natural gas,
petroleum and electricity. Profits are earned as SET acts as a
dealer in structuring and executing transactions that assist its
customers in managing their energy-price risk. In addition, SET may,
on a limited basis, take positions in energy markets based on the
expectation of future market conditions. These positions include
options, forwards, futures and swaps. See Note 9 of the notes to
Consolidated Financial Statements and the following "Market Risk
Management Activities" section for additional information regarding
SET's use of derivative financial instruments.
The Company's regulated 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's
regulated operations is subject to certain limitations imposed by
established Company policy and regulatory requirements. See Note 9
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 regulated
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
and trading activities. An Energy Risk Management Oversight
Committee, consisting of senior corporate officers, oversees energy-
price risk-management and trading activities to ensure compliance
with Sempra Energy's stated energy risk-management and trading
policies. In addition, all affiliates have groups that monitor and
control energy-price risk-management and trading activities
independently from the groups responsible for creating or actively
managing these risks.
Along with other tools, the Company uses Value at Risk (VaR) to
measure its exposure to market risk. VaR is an estimate of the
potential loss on a position or portfolio of positions over a
specified holding period, based on normal market conditions and
within a given statistical confidence 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 utility 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 is 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's
regulated and unregulated affiliates are 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 of each
affiliate.
SoCalGas is exposed to market risk on its natural gas purchase,
sale and storage activities whenever natural gas prices fall outside
the GCIM tolerance band. SoCalGas manages this risk within the
parameters of the Company's market risk management and trading
framework. As of December 31, 1998, the total VaR of SoCalGas'
natural gas positions was not material.

Sempra Energy Trading
Sempra Energy Trading derives a substantial portion of its revenue
from risk management and trading activities in natural gas,
petroleum and electricity. As such, SET is exposed to price
volatility in the domestic and international natural gas markets,
petroleum and electricity markets. SET conducts these activities
within a structured and disciplined risk management and control
framework that is based on clearly communicated policies and
procedures, position limits, active and ongoing management
monitoring and oversight, clearly defined roles and
responsibilities, and daily risk measurement and reporting.
Market risk of SET's portfolio is measured using a variety of
methods, including VaR. SET computes the VaR of its portfolio based
on a three-day holding period. As of December 31, 1998, the
diversified VaR of SET's portfolio was $5.3 million.

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 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 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 April 1998, the American Institute of Certified Public
Accountants issued Statement of Position 98-5 "Reporting on the
Costs of Start-up Activities". This statement is effective for 1999,
but is not expected to have a significant effect on the Company's
Consolidated Financial Statements.
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 Pacific
Enterprises:

We have audited the accompanying consolidated balance sheets
of Pacific Enterprises 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 Pacific
Enterprises 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 15 as to which the
date is February 22, 1999

PACIFIC ENTERPRISES AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
In millions of dollars

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

Revenues
Operating revenues $2,472 $2,738 $2,563
Loss of unconsolidated
joint ventures and partnerships (20) (7) --
Other Income 20 46 25
----- ----- -----
Total 2,472 2,777 2,588
----- ----- -----
Expenses
Cost of natural gas distributed 840 1,059 866
Operating expenses 930 918 910
Depreciation and amortization 259 256 255
Franchise fees and other taxes 100 99 98
Preferred dividends of subsidiaries 2 7 8
----- ----- -----
Total 2,131 2,339 2,137
----- ----- -----
Income Before Interest
and Income Taxes 341 438 451
Interest 67 103 97
----- ----- -----
Income Before Income Taxes 274 335 354
Income Taxes 127 151 151
----- ----- -----
Net Income 147 184 203
Preferred Dividend Requirements 4 4 5
Preferred Stock Original Issue Discount -- -- 2
----- ----- -----
Earnings Applicable to Common Shares $ 143 $ 180 $ 196
===== ===== =====

See notes to Consolidated Financial Statements.

PACIFIC ENTERPRISES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
In millions of dollars

Balance at December 31 1998 1997
----------- -----------

ASSETS
Current assets
Cash and cash equivalents $ 27 $ 153
Accounts and notes receivable - trade
(less allowance for doubtful receivables
of $18 in 1998 and $19 in 1997) 444 480
Accounts and notes receivable - other 137 50
Income taxes receivable 22 3
Regulatory balancing accounts undercollected - net -- 355
Deferred income taxes 130 --
Natural Gas in storage 49 25
Materials and supplies 16 16
Prepaid expenses 19 21
----- -----
Total current assets 844 1,103
----- -----

Property, plant and equipment 6,152 6,097
Less accumulated depreciation and
amortization 3,149 2,943
------ ------
Total property, plant and
equipment - net 3,003 3,154
------ ------
Investments and other assets:
Regulatory assets 351 394
Other receivables 130 62
Investments 209 191
Other assets 61 73
------ ------
Total investments and
other assets 751 720
------ ------
Total $4,598 $4,977
====== ======

See notes to Consolidated Financial Statements.

PACIFIC ENTERPRISES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
In millions of dollars

Balance at December 31 1998 1997
----------- -----------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term debt $ 43 $ 354
Current portion of long-term debt 206 148
Accounts payable - trade 163 133
Accounts payable - other 245 304
Regulatory balancing accounts overcollected - net 129 --
Interest accrued 47 52
Deferred income taxes -- 7
Other taxes payable 32 30
Other 149 87
----- -----
Total current liabilities 1,014 1,115
----- -----

Long-term debt 985 988
Debt of Employee Stock Ownership Plan -- 130
----- -----
Total long-term debt 985 1,118
----- -----
Deferred credits and other liabilities:
Customer advances for construction 31 34
Post-retirement benefits other than pensions 210 217
Deferred income taxes - net 220 272
Deferred investment tax credits 58 61
Other deferred credits 346 413
Other long-term liabilities 167 183
----- -----
Total deferred credits and
other liabilities 1,032 1,180
----- -----
Preferred stock of subsidiary 20 95
----- -----
Commitments and contingent liabilities (Note 12)

Shareholders' equity:
Capital stock:
Preferred 80 80
Common 1,117 1,064
----- -----
Total capital stock 1,197 1,144
Retained earnings 395 372
Deferred compensation relating to
Employee Stock Ownership Plan (45) (47)
----- -----
Total shareholders' equity 1,547 1,469
------ ------
Total $4,598 $4,977
====== ======
See notes to Consolidated Financial Statements.

PACIFIC ENTERPRISES 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 $ 147 $ 184 $ 203
Adjustments to reconcile net income
to net cash provided by operating
activities:
Depreciation and amortization 259 256 255
Deferred income taxes (55) (35) 33
Loss of unconsolidated
joint ventures and partnerships 20 7 --
Other - net (79) (22) 13
Changes in working capital components 306 (40) 104
------ ------ ------
Net cash provided by operating activities 598 350 608
------ ------ ------
Cash Flows from Investing Activities:
Expenditures for property, plant and
equipment (150) (187) (204)
Acquisition of Sempra Energy Trading -- (112) --
Increase in investments (45) (26) (62)
Proceeds from disposition of properties -- 20 --
(Increase) decrease in other receivables,
regulatory assets and other assets 6 42 (20)
------ ------ ------
Net cash used in investing activities (189) (263) (286)
------ ------ ------
Cash Flows from Financing Activities:
Common dividends paid (97) (122) (119)
Preferred dividends paid (4) (4) (4)
Payment on long-term debt (150) (245) (172)
Increase (decrease)in short-term debt (311) 92 29
Issuance of long-term debt 75 120 75
Sale of common stock 27 17 8
Repurchase of common stock -- (48) (24)
Redemption of preferred stock of a subsidiary (75) -- (100)
Redemption of preferred stock -- -- (110)
------ ------ ------
Net cash used in financing activities (535) (190) (417)
------ ------ ------
Net decrease (126) (103) (95)
Cash and Cash Equivalents, January 1 153 256 351
------ ------ ------
Cash and Cash Equivalents, December 31 $ 27 $ 153 $ 256
====== ====== ======
See notes to Consolidated Financial Statements.

PACIFIC ENTERPRISES AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
In millions of dollars

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

Changes in Working Capital Components
(Excluding cash and cash equivalents,
short-term debt and long-term debt
due within one year)
Current Assets:
Receivables $ (51) $ (34) $ (58)
Income taxes receivable (19) 55 12
Deferred income taxes (130) -- 11
Inventories (24) 5 27
Regulatory balancing accounts -- 25 46
Other 2 2 16
------ ------ ------
Total (222) 53 54
------ ------ ------
Current Liabilities:
Accounts payable (29) (139) 53
Deferred income taxes (7) 26 --
Other taxes payable 2 2 (18)
Regulatory balancing accounts 484 -- --
Other 78 18 15
------ ------ ------
Total 528 (93) 50
------ ------ ------
Net change in other working
capital components $ 306 $ (40) $ 104
====== ====== ======

Supplemental Disclosure of Cash Flow Information:
Income tax payments, net of refunds $ 263 $ 112 $ 92
====== ====== ======
Interest payments, net of amount capitalized $ 72 $ 92 $ 100
====== ====== ======
Supplemental Schedule of Noncash Activities:
Dividend of property to Sempra Energy $ 23 $ -- $ --
====== ====== ======
Capital contribution from Sempra Energy $ 26 $ -- $ --
====== ====== ======

Sale of assets of small generation plants:
Fair value of the assets sold $ 77
Cash received (20)
Loss on sale (6)
------
Note receivable $ 51
======

See notes to Consolidated Financial Statements.

PACIFIC ENTERPRISES
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
For the years ended December 31, 1998, 1997, 1996
(Dollars in millions)

Deferred
Compensation Total
Common Preferred Retained Relating Shareholders'
Stock Stock Earnings to ESOP Equity
- --------------------------------------------------------------------------------------------

Balance at December 31, 1995 $ 1,111 $ 188 $ 236 $ (52) $ 1,483
Net income 203 203
Preferred stock dividends declared (5) (5)
Common stock dividends declared (118) (118)
Sale of common stock 8 8
Repurchase of common stock (24) (24)
Redemption of preferred stock (108) (2) (110)
Common stock released
from ESOP 3 3
- --------------------------------------------------------------------------------------------
Balance at December 31, 1996 1,095 80 314 (49) 1,440
Net income 184 184
Preferred stock dividends declared (4) (4)
Common stock dividends declared (122) (122)
Sale of common stock 17 17
Repurchase of common stock (48) (48)
Common stock released
from ESOP 2 2
- --------------------------------------------------------------------------------------------
Balance at December 31, 1997 1,064 80 372 (47) 1,469
Net income 147 147
Preferred stock dividends declared (4) (4)
Common stock dividends declared (120) (120)
Capital contribution 26 26
Sale of common stock 27 27
Common stock released
from ESOP 2 2
- --------------------------------------------------------------------------------------------
Balance at December 31, 1998 $ 1,117 $ 80 $ 395 $ (45) $ 1,547
============================================================================================

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 or the Company) 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 PE's principal subsidiary, Southern California Gas
Company (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

Property, Plant and Equipment

This primarily represents the buildings, equipment and other
facilities used by SoCalGas 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.

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.

Trading Instruments

Sempra Energy Trading (SET), a leading natural gas and power
marketing firm headquartered in Stamford, Connecticut, was jointly
acquired by PE and Enova on December 31, 1997. SET's trading assets
and trading liabilities are recorded on a trade-date basis at fair
value and include option premiums paid and received, and unrealized
gains and losses from exchange-traded futures and options, over the
counter (OTC) swaps, forwards, and options. Unrealized gains and
losses on OTC transactions reflect amounts which would be received
from or paid to a third party upon settlement of the contracts.
Unrealized gains and losses on OTC transactions are reported
separately as assets and liabilities unless a legal right of setoff
exists under a master netting arrangement enforceable by law.
Revenues are recognized on a trade-date basis and include realized
gains and losses, and the net change in unrealized gains and
losses.
Futures and exchange-traded option transactions are recorded
as contractual commitments on a trade-date basis and are carried at
fair value based on closing exchange quotations. Commodity swaps
and forward transactions are accounted for as contractual
commitments on a trade-date basis and are carried at fair value
derived from dealer quotations and underlying commodity-exchange
quotations. OTC options are carried at fair value based on the use
of valuation models that utilize, among other things, current
interest, commodity and volatility rates, as applicable. For long-
dated forward transactions, where there are no dealer or exchange
quotations, fair values are derived using internally developed
valuation methodologies based on available market information.
Where market rates are not quoted, current interest, commodity and
volatility rates are estimated by reference to current market
levels. Given the nature, size and timing of transactions,
estimated values may differ from realized values. Changes in the
fair value are recorded currently in income.

Effects of Regulation

SoCalGas accounting policies conform with generally accepted
accounting principles for regulated enterprises and reflect the
policies of the CPUC and the FERC. The Company's interstate natural
gas transmission subsidiary follows accounting policies authorized
by the FERC.
SoCalGas prepares 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 below in "Revenues and Regulatory Balancing Accounts" and
in Note 13.

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 utility expects to recover in future rates. See Note 13 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.

Quasi-Reorganization

In 1993, PE completed a strategic plan to refocus on its natural
gas utility and related businesses. The strategy included the
divestiture of its merchandising operations and all of its oil and
natural gas exploration and production business. In connection with
the divestitures, PE effected a quasi-reorganization for financial
reporting purposes, effective December 31, 1992. Certain of the
liabilities established in connection with discontinued operations
and the quasi-reorganization will be resolved in future years.
Management believes the provisions previously established for these
matters are adequate at December 31, 1998.

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 April 1998, the American Institute of Certified Public
Accountants issued Statement of Position 98-5 "Reporting on the
Costs of Start-up Activities". This statement is effective for
1999, but is not expected to have a significant effect on the
Company's Consolidated Financial Statements.
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: ACQUISITIONS AND JOINT VENTURES

Sempra Energy Trading, Sempra Energy Resources, Sempra Energy
Utility Ventures and Sempra Energy Solutions are nonregulated
subsidiaries of Sempra Energy, each equally owned by PE and Enova.

Sempra Energy Trading
In December 1997, PE and Enova jointly acquired Sempra Energy
Trading (SET) for $225 million. SET is a wholesale-energy trading
company based in Stamford, Connecticut. It participates in
marketing and trading physical and financial energy products,
including natural gas, power, crude oil and associated commodities.
In July 1998, SET purchased CNG Energy Services Corporation, a
subsidiary of Pittsburgh-based Consolidated Natural Gas Company,
for $36 million. The acquisition expands SET's business volume by
adding large commodity-trading contracts with local distribution
companies, municipalities and major industrial corporations in the
eastern United States. See Note 9 for additional information on
Sempra Energy Trading.

Sempra Energy Resources
In December 1997, Sempra Energy Resources (SER), in partnership
with Reliant Energy Power Generation, formed El Dorado Energy. In
April 1998, El Dorado Energy began construction on a 480-megawatt
power plant near Boulder City, Nevada. SER invested $2.3 million in
1997 and $19.7 million in 1998 on this $263-million project. In
October 1998, El Dorado Energy obtained a $158-million senior
secured credit facility, which entails both construction and 15-
year term financing for the project. This financing represents 60
percent of the estimated total project costs.

Sempra Energy Utility Ventures
In September 1997, Sempra Energy Utility Ventures (SEUV) formed a
joint venture with Bangor Hydro to build, own and operate a $40-
million natural gas distribution system in Bangor, Maine.
Construction began in June 1998. The new Bangor Gas Company expects
to begin deliveries in the fourth quarter of 1999.
In December 1997, SEUV formed Frontier Energy with Frontier
Utilities of North Carolina to build and operate a $55-million
natural gas distribution system in North Carolina. Gas delivery
began in December 1998. Subsequent to December 31, 1998, SEUV
purchased Frontier Utilities' interest and acquired 100 percent
ownership of the system.

Sempra Energy Solutions
In January 1998, Sempra Energy Solutions completed the acquisition
of CES/Way International, a national leader in energy-service
performance contracting headquartered in Houston, Texas. CES/Way
provides energy-efficiency services including energy audits,
engineering design, project management, construction, financing and
contract maintenance.
In May 1997, Sempra Energy Solutions entered into an operating
joint venture agreement with Conectiv Thermal Systems, Inc.
(formerly Atlantic Thermal System, Inc.) to form Atlantic-Pacific
Las Vegas, with each receiving a 50 percent interest. Atlantic-
Pacific Las Vegas will provide integrated energy-management
services to commercial and industrial customers including the
construction of facilities. In May 1997, Atlantic-Pacific Las Vegas
entered into an energy-services agreement with three other parties
to finance, own, operate and maintain an integrated thermal-energy
production facility at the site of the future Venetian Casino
Resort in Las Vegas. The construction cost incurred to date is $48
million.
A second joint venture agreement was entered into with Conectiv
Thermal Systems to form Atlantic-Pacific Glendale in August 1997,
with each receiving a 50-percent interest. Atlantic-Pacific
Glendale entered into an integrated energy-management services
agreement with Dreamworks Animation, LLC, to develop, manage and
finance the construction and operation of a central chiller plant,
emergency power generators and chilled-water distribution and
circulation system at Dreamworks' Glendale facilities. The cost of
the project, completed in May 1998, was $7 million.

International Gas Distribution Projects
Pacific Enterprises International (PEI), Sempra Energy
International (SEI), and Proxima Gas S.A. de C.V., partners in the
Mexican companies Distribuidora de Gas Natural (DGN) de Mexicali
and Distribuidora de Gas Natural (DGN) de Chihuahua, are the
licensees to build and operate natural gas distribution systems in
Mexicali and Chihuahua. DGN - Mexicali will invest up to $25
million during the first five years of the 30-year license period.
DGN - Chihuahua will invest up to $50 million over the first five
years of operation. DGN - Mexicali and DGN - Chihauhua assumed
ownership of natural gas distribution during the third quarter of
1997. PEI owns interests of 30 and 47.5 percent in the Mexicali and
Chihuahua projects, respectively. In March 1998, PEI increased its
existing investment in two Argentine natural gas utility holding
companies (Sodigas Pampeana S.A. and Sodigas Sur S.A.) from 12.5
percent to 21.5 percent by purchasing an additional 9 percent
interest for $40 million.

Dividending of Subsidiaries to Sempra Energy
As a result of the PE/Enova Business Combination which was
completed in June 1998, certain subsidiaries of PE were dividended
to Sempra Energy in September 1998 in order to effectuate the
change in the corporate structure.

NOTE 4: SHORT-TERM BORROWINGS

PE has a $300 million multi-year credit agreement. SoCalGas has an
additional $400 million multi-year credit agreement. These
agreements expire in 2001 and bear interest at various rates based
on market rates and the companies' credit ratings. SoCalGas' lines
of credit are available to support commercial paper. At December
31, 1998, PE had $43 million of bank loans under the credit
agreement outstanding, due and paid in January 1999. SoCalGas' bank
line of credit was unused. At December 31, 1997, both bank lines of
credit were unused.
At December 31, 1998, there were no commercial-paper
obligations outstanding. At December 31, 1997, SoCalGas had $354
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 13 for additional
information.

NOTE 5: LONG-TERM DEBT
- --------------------------------------------------------------
December 31,
(Dollars in millions) 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
Employee Stock Ownership Plan,
November 30, 1999 130 130
Other, 8% - 9.5%, 1999-2002 19 21
-----------------------
Total 1,207 1,281
-----------------------
Less:
Long term debt due within one year 206 148
Unamortized discount on
long-term debt 16 15
-----------------------
222 163
-----------------------
Total $ 985 $1,118
- --------------------------------------------------------------

Maturities of long-term debt, including PE's Employees Stock
Ownership Plan, are $206 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 at 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.

Debt of Employee Stock Ownership Plan (ESOP) and Trust

The Trust covers substantially all of the Company's former PE
employees and is used to partially fund their retirement savings
program. It has an ESOP feature and holds approximately 3.1 million
shares of Sempra Energy's common stock. The variable-rate ESOP debt
held by the Trust bears interest at a rate necessary to place or
remarket the notes at par. The balance of this debt was $130
million at December 31, 1998, and is included in the table above.
Principal is due on November 30, 1999 and interest is payable
monthly. PE is obligated to make contributions to the Trust
sufficient to satisfy debt service requirements. As PE makes
contributions to the Trust, these contributions, plus any dividends
paid on the unallocated shares of PE's common stock held by the
Trust, will be used to repay the debt. As dividends are increased
or decreased, required contributions are reduced or increased,
respectively. Interest on ESOP debt amounted to $6 million in each
of the years 1998, 1997 and 1996. Dividends used for debt service
amounted to $3 million in each of the years 1998, 1997 and 1996,
and are deductible only for federal income tax purposes.

NOTE 6: 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 9.9 6.9 6.5
State income taxes - net of
federal income tax benefit 4.7 6.9 5.7
Tax credits (1.0) (0.9) (0.8)
Capitalized expenses not deferred 0.4 (0.9) (3.1)
Other - net (2.6) (1.9) (0.6)
-----------------------------
Effective income tax rate 46.4% 45.1% 42.7%
- -----------------------------------------------------------------------

The components of income tax expense are as follows:
- -----------------------------------------------------------------------
(Dollars in millions) 1998 1997 1996
- -----------------------------------------------------------------------
Current:
Federal $242 $143 $ 68
State 65 25 25
-----------------------------
Total current taxes 307 168 93
-----------------------------
Deferred:
Federal (139) (19) 54
State (38) 5 7
-----------------------------
Total deferred taxes (177) (14) 61
-----------------------------
Deferred investment tax credits-net (3) (3) (3)
-----------------------------
Total income tax expense $127 $151 $151
- -----------------------------------------------------------------------

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 $ 495
Regulatory balancing accounts - 161
Regulatory assets 76 90
Other 51 61
--------------------
Total deferred tax liabilities 576 807
--------------------
Deferred Tax Assets:
Unamortized investment tax credits 25 27
Regulatory balancing accounts 51 -
Comprehensive settlement (see Note 13) 95 117
Postretirement benefits 76 81
Other deferred liabilities 153 157
Restructuring costs 51 54
Other 35 92
--------------------
Total deferred tax assets 486 528
--------------------
Net deferred income tax liability 90 279
Current portion - net asset (liability) 130 (7)
--------------------
Non-current portion - net liability $220 $272
- --------------------------------------------------------------

NOTE 7: EMPLOYEE BENEFIT PLANS

The information presented below describes the plans of the Company
and its principal subsidiaries. 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 $1,512 $1,435 $ 488 $ 401
Service cost 36 35 12 14
Interest cost 104 104 33 32
Plan participants' contributions - - 1 1
Plan amendments 21 - - -
Actuarial (gain) loss (32) 35 (5) 56
Transfer of liability (3) (293) - (43) -
Special termination benefits 54 13 3 2
Gross benefits paid (221) (110) (17) (18)
-----------------------------------------------
Net benefit obligation at
December 31 1,181 1,512 472 488
-----------------------------------------------

Change in Plan Assets:
Fair value of plan assets
at January 1 1,954 1,774 349 274
Actual return on plan assets 300 288 62 59
Employer contributions 13 2 31 33
Plan participants' contributions - - 1 1
Transfer of assets (3) (447) - (40) -
Gross benefits paid (221) (110) (17) (18)
-----------------------------------------------
Fair value of plan assets
at December 31 1,599 1,954 386 349
-----------------------------------------------
Funded status at December 31 418 442 (86) (139)
Unrecognized net actuarial gain (525) (533) (110) (63)
Unrecognized prior service cost 50 32 (14) (15)
Unrecognized net transition
obligation 3 4 - -
-----------------------------------------------
Net liability at December 31 (4) $ (54) $ (55) $(210) $(217)
- ---------------------------------------------------------------------------------
(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.

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 $ 36 $ 35 $ 39 $ 12 $ 14 $ 17
Interest cost 104 104 103 33 32 33
Expected return on assets (135) (128) (117) (24) (21) (19)
Amortization of:
Transition obligation 1 1 1 - - -
Prior service cost 3 3 3 (1) (1) (1)
Actuarial (gain) loss (12) (10) - 1 1 1
Special termination benefit 54 13 - 3 2 -
Settlement credit (30) - - - - -
Regulatory adjustment - - 3 9 13 13
-----------------------------------------------
Total net periodic benefit cost $ 21 $ 18 $ 32 $ 33 $ 40 $ 44
- ---------------------------------------------------------------------------------

Assumed health care cost trend rates have a significant effect on
the amounts reported for the health care plans. A 1-percent change
in assumed health care cost trend rates would have the following
effects:
- ------------------------------------------------------------------------
(Dollars in millions) 1% Increase 1% Decrease
- ------------------------------------------------------------------------
Effect on total of service and interest cost
components of net periodic postretirement
health care benefit cost $11 $ (9)
Effect on the health care component of the
accumulated postretirement benefit obligation $70 $(63)
- ------------------------------------------------------------------------

The projected benefit obligation and accumulated benefit
obligation for the pension plan were $40 million and $32 million,
respectively, as of December 31, 1998, and $37 million and $34
million, respectively, as of December 31, 1997.
Other postretirement benefits include medical benefits for
retirees and their spouses, and retiree life insurance.

Savings Plans

Pacific Enterprises and SoCalGas offer savings plans, administered
by plan trustees, to all eligible employees. Eligibility to
participate in the various employer plans ranges from one month to
one year of completed service. Employees may contribute, subject
to plan provisions, from 1 percent to 15 percent of their regular
earnings. 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,
after one year of completed service, are made in shares of Sempra
Energy common stock. Employer contribution methods vary by plan,
but generally the contribution is equal to 50 percent of the first
6 percent of eligible base salary contributed by employees.
Employer contributions for the PE and SoCalGas plans are partially
funded by the Pacific Enterprises Employee Stock Ownership Plan
and Trust. Annual expense for the savings plans was $8 million in
1998, 1997 and 1996.

Employee Stock Ownership Plan

The Pacific Enterprises Employee Stock Ownership Plan and Trust
(Trust) covers substantially all employees of PE and SoCalGas and
is used to partially fund their retirement savings plan programs.
All contributions to the Trust are made by the Company, and there
are no contributions made by the participants. As the Company
makes contributions to the Trust, the Trust debt service is paid
and shares are released in proportion to the total expected debt
service.

Compensation expense is charged and equity is credited for the
market value of the shares released. Income-tax deductions are
allowed based on the cost of the shares. Dividends on unallocated
shares are used to pay debt service and are charged against
liabilities. The Trust held 3.1 and 3.3 million shares of Sempra
Energy common stock, with fair values of $77.9 million and $80.3
million at December 31, 1998, and 1997, respectively.

NOTE 8: 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. PE recorded expenses of $8 million in 1998, $17 million
in 1997 and $6 million in 1996.

NOTE 9: 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 $1.2 billion each at December 31, 1998, and
$1.3 billion each at December 31, 1997. The carrying amounts and
fair values of the combined preferred stock and preferred stock of
subsidiaries are $100 million and $77 million, respectively, at
December 31, 1998, and $175 million and $157 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

Information on derivative financial instruments of SET is provided
below. The Company's regulated operations use energy derivatives
for price risk management purposes within certain limitations
imposed by Company policies and regulatory requirements.
As a result of the GCIM (see Note 13), SoCalGas 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.

Sempra Energy Trading

SET derives a substantial portion of its revenue from market making
and trading activities, as a principal, in natural gas, petroleum
and electricity. It quotes bid and offer prices to end users and
other market makers. It also earns trading profits as a dealer by
structuring and executing transactions that permit its
counterparties to manage their risk profiles. In addition, it takes
positions in energy markets based on the expectation of future
market conditions. These positions may be offset with similar
positions or may be offset in the exchange-traded markets. These
positions include options, forwards, futures and swaps. These
financial instruments represent contracts with counterparties
whereby payments are linked to or derived from energy-market
indices or on terms predetermined by the contract, which may or may
not be physically or financially settled by SET. For the year ended
December 31, 1998, substantially all of SET's derivative
transactions were held for trading and marketing purposes.
Market risk arises from the potential for changes in the value
of financial instruments resulting from fluctuations in natural
gas, petroleum and electricity commodity-exchange prices and basis.
Market risk is also affected by changes in volatility and liquidity
in markets in which these instruments are traded.
SET adjusts the book value of these derivatives to market each
month with gains and losses recognized in earnings. Certain
instruments such as swaps are entered into and closed out within
the same month and, therefore, do not have any balance-sheet
impact.
SET also carries an inventory of financial instruments. As
trading strategies depend on both market making and proprietary
positions, given the relationships between instruments and markets,
those activities are managed in concert in order to maximize
trading profits.
SET's credit risk from financial instruments as of December
31, 1998, is represented by the positive fair value of financial
instruments after consideration of master netting agreements and
collateral. Credit risk disclosures, however, relate to the net
accounting losses that would be recognized if all counterparties
completely failed to perform their obligations. Options written do
not expose SET to credit risk. Exchange-traded futures and options
are not deemed to have significant credit exposure as the exchanges
guarantee that every contract will be properly settled on a daily
basis.
The following table approximates the counterparty credit
quality and exposure of SET expressed in terms of net replacement
value (in millions of dollars):

- -------------------------------------------------------------------
Futures,
forward and
swap Purchased
Counterparty credit quality: contracts options Total
- -------------------------------------------------------------------
AAA $ 32 $ 1 $ 33
AA 41 14 55
A 129 19 148
BBB 290 26 316
Below investment grade 69 2 71
Exchanges 30 8 38
- -------------------------------------------------------------------
$591 $ 70 $661
- -------------------------------------------------------------------

Financial instruments with maturities or repricing
characteristics of 180 days or less, including cash and cash
equivalents, are considered to be short-term and, therefore, the
carrying values of these financial instruments approximate their
fair values. SET's commodities owned, trading assets and trading
liabilities are carried at fair value. The average fair values
during the year, based on quarterly observation, for trading assets
and trading liabilities which are considered financial instruments
with off-balance-sheet risk approximate $952 million and $890
million, respectively. The fair values are net of the amounts
offset pursuant to rights of setoff based on qualifying master
netting arrangements with counterparties, and do not include the
effects of collateral held or pledged.
As of December 31, 1998, and 1997, SET's trading assets and
trading liabilities approximate the following:

- -------------------------------------------------------------------
December 31,
(Dollars in millions) 1998 1997
- -------------------------------------------------------------------
Trading Assets
Unrealized gains on swaps and forwards $ 756 $ 497
Due from commodity clearing organization
and clearing brokers 75 41
OTC commodity options purchased 45 33
Due from trading counterparties 30 16
------------------
Total $ 906 $ 587
- -------------------------------------------------------------------

Trading Liabilities
Unrealized losses on swaps and forwards $ 740 $ 487
Due to trading counterparties 35 41
OTC commodity options written 30 29
------------------
Total $ 805 $ 557
- -------------------------------------------------------------------

Notional amounts do not necessarily represent the amounts
exchanged by parties to the financial instruments and do not
measure SET's exposure to credit or market risks. The notional or
contractual amounts are used to summarize the volume of financial
instruments, but do not reflect the extent to which positions may
offset one another. Accordingly, SET is exposed to much smaller
amounts potentially subject to risk. The notional amounts of SET's
financial instruments are:

- -------------------------------------------------------------------
(Dollars in millions) Total
- -------------------------------------------------------------------
Forwards and commodity swaps $ 5,916
Futures and exchange options 2,915
Options purchased 1,320
Options written 1,298
-------------
Total $11,449
- -------------------------------------------------------------------

NOTE 10: PREFERRED STOCK OF SUBSIDIARIES

- -----------------------------------------------------------------
SoCalGas December 31,
(Dollars in millions) 1998 1997
- -----------------------------------------------------------------
Not subject to mandatory redemption:
$25 par value, authorized 1,000,000 shares
6% Series, 28,664 shares outstanding $ 1 $ 1
6% Series A, 783,032 shares outstanding 19 19
Without par value, authorized 10,000,000 shares
7.75% Series - 75
--------------
$20 $95
- -----------------------------------------------------------------

None of SoCalGas' series of preferred stock is 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.

NOTE 11: SHAREHOLDERS' EQUITY

- ----------------------------------------------------------------------
December 31,
(Dollars in millions) 1998 1997
- ----------------------------------------------------------------------
COMMON EQUITY:
Common $ 1,117 $ 1,064
Retained earnings 395 372
Deferred compensation relating to
Employee Stock Ownership Plan (45) (47)
-----------------------------
Total common equity $ 1,467 $ 1,389
- ----------------------------------------------------------------------

The Company is authorized to issue 600,000,000 shares of common
stock, 10,000,000 shares of Preferred Stock and 5,000,000 shares of
Class A Preferred Stock. All shares of PE common stock are owned by
Sempra Energy. No shares of Unclassified or Class A preferred stock
are outstanding.

- ----------------------------------------------------------------------
Call December 31,
(Dollars in millions except call price) Price 1998 1997
- ----------------------------------------------------------------------
PREFERRED STOCK:
Cumulative preferred
without par value:
$4.75 Dividend, 200,000 shares
authorized and outstanding $100.00 $ 20 $ 20
$4.50 Dividend, 300,000 shares
authorized and outstanding $100.00 30 30
$4.40 Dividend, 100,000 shares
authorized and outstanding $101.50 10 10
$4.36 Dividend, 200,000 shares
authorized and outstanding $101.00 20 20
$4.75 Dividend, 253 shares
authorized and outstanding $101.00 -- --

----------------------
Total $ 80 $ 80
- ----------------------------------------------------------------------

All or any part of every series of presently outstanding PE
preferred stock is subject to redemption at PE's option at any time
upon not less than 30 days notice, at the applicable redemption
prices for each series, together with the accrued and accumulated
dividends to the date of redemption. All series have one vote per
share and cumulative preferences as to dividends.

Dividend Restrictions
At December 31, 1998, $103 million of PE's retained earnings was
available for future dividends, due to the CPUC's regulation of
SoCalGas' capital structure.

NOTE 12: 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

PE and its subsidiaries have 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 PE or its subsidiaries.
The minimum rental commitments payable in future years under
all noncancellable leases are(in millions of dollars):
- -------------------------------------------------------------------
1999 $ 49
2000 49
2001 47
2002 48
2003 45
Thereafter 350
----------------
Total future rental commitment $ 588
- -------------------------------------------------------------------

Rent expense totaled $55 million in 1998, $56 million in 1997,
and $58 million in 1996.
In connection with its quasi-reorganization described in Note
2 and loss on disposal of discontinued operations, PE established
reserves of $102 million to fair value operating leases related to
its headquarters and other leases at December 31, 1992. The
remaining amount of these reserves was $76 million at December 31,
1998. These leases are reflected in the above table.

Other Commitments and Contingencies

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

Environmental Issues

PE 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.
PE 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.
SoCalGas 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 the above sites was $68 million, of
which 90 percent is authorized to be recovered through the
Hazardous Waste Collaborative Mechanism. In addition, PE and its
subsidiaries have been named as potentially responsible parties for
two landfill sites and two industrial waste disposal sites. The
total cost estimate for remediation of these four sites is $5
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.
PE and its subsidiaries have been associated with various
other sites, which may require remediation under federal, state or
local environmental laws. PE is unable to determine fully 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

PE 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 Pacific Enterprise's results
of operations, financial condition or liquidity.

Concentration of Credit Risk

PE maintains credit policies and systems to minimize overall credit
risk. These policies include, when applicable, the use of an
evaluation of potential counterparties' financial condition and an
assignment of credit limits. These credit limits are established
based on risk and return considerations under terms customarily
available in the industry.
SoCalGas grants credit to its utility customers, substantially
all of whom are located in its service territories, which covers
most of Southern California and a portion of Central California.

NOTE 13: 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.
PE and SoCalGas recorded the impact of the Comprehensive
Settlement in 1993. Upon giving effect to liabilities previously
recognized by the companies, the costs of the Comprehensive
Settlement, including the restructuring of natural gas supply
contracts, did not result in any future charge to PE's 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).
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 14: SEGMENT INFORMATION

The Company has two separately managed reportable segments:
SoCalGas and Sempra Energy Trading (SET). SoCalGas is a natural
gas distribution utility, serving customers throughout most of
Southern California and part of Central California. SET is based
in Stamford, Connecticut, and is engaged in the nationwide
wholesale trading and marketing of natural gas, power and
petroleum. The Company has a 50 percent ownership interest in SET,
and accounts for this investment on the equity method of
accounting. However, for segment reporting, items of income and
assets for SET are reported at 100 percent. A corresponding
adjustment is made to reconcile the amounts to those that were
reported by the Company under the equity method. 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 net income. Intersegment transactions are generally
recorded the same as sales or transactions with third parties.
Utility transactions are primarily based on rates set by the CPUC.

- ---------------------------------------------------------------------
For the years ended December 31,
(Dollars in millions) 1998 1997 1996
- ---------------------------------------------------------------------
Revenues and Other Income:
Southern California Gas $ 2,427 $ 2,641 $ 2,422
Sempra Energy Trading 110 -- --
Sempra Energy Trading adjustment (110) -- --
All other 45 136 166
---------------------------------
Total $ 2,472 $ 2,777 $ 2,588
---------------------------------

Interest Revenue:
Southern California Gas $ 4 $ 16 $ 5
Sempra Energy Trading 3 -- --
Sempra Energy Trading adjustment (3) -- --
All other 15 15 14
---------------------------------
Total Interest 19 31 19
Sundry income 1 15 6
---------------------------------
Total Other Income $ 20 $ 46 $ 25
---------------------------------

Depreciation and amortization:
Southern California Gas $ 254 $ 251 $ 248
Sempra Energy Trading 13 -- --
Sempra Energy Trading adjustment (13) -- --
All other 5 5 7
---------------------------------
Total $ 259 $ 256 $ 255
---------------------------------
Interest Expense:
Southern California Gas $ 80 $ 87 $ 86
Sempra Energy Trading 5 -- --
Sempra Energy Trading adjustment (5) -- --
All other (13) 16 11
---------------------------------
Total $ 67 $ 103 $ 97
---------------------------------
Income Tax Expense (Benefit):
Southern California Gas $ 128 $ 178 $ 148
Sempra Energy Trading (9) -- --
Sempra Energy Trading adjustment 9 -- --
All other (1) (27) 3
---------------------------------
Total $ 127 $ 151 $ 151
---------------------------------
Net Income:
Southern California Gas $ 158 $ 231 $ 193
Sempra Energy Trading (13) -- --
Sempra Energy Trading adjustment 7 -- --
All other (5) (47) 10
---------------------------------
Total $ 147 $ 184 $ 203
---------------------------------

- ---------------------------------------------------------------------
At December 31, or for
the year then ended
(Dollars in millions) 1998 1997 1996
- ---------------------------------------------------------------------
Assets:
Southern California Gas $ 3,834 $ 4,205 $ 4,354
Sempra Energy Trading 1,225 846 --
Sempra Energy Trading adjustment (1,225) (846) --
All other 764 772 832
---------------------------------
Total $ 4,598 $ 4,977 $ 5,186
---------------------------------
Capital Expenditures:
Southern California Gas $ 128 $ 159 $ 197
Sempra Energy Trading -- -- --
All other 22 28 7
---------------------------------
Total $ 150 $ 187 $ 204
---------------------------------
Geographic Information:
Long-lived assets
United States $ 3,096 $ 3,287 $ 3,301
Latin America 106 58 51
---------------------------------
Total $ 3,202 $ 3,345 $ 3,352
---------------------------------
Revenues and Other Income:
United States $ 2,471 $ 2,776 $ 2,587
Latin America 1 1 1
---------------------------------
Total $ 2,472 $ 2,777 $ 2,588
- ---------------------------------------------------------------------

NOTE 15: 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 16: QUARTERLY FINANCIAL DATA (UNAUDITED)

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

1998
Operating Revenues $ 678 $ 585 $ 521 $ 688
Operating expenses 581 541 421 588
-----------------------------------------------------
Operating income $ 97 $ 44 $ 100 $ 100
-----------------------------------------------------
Net income $ 40 $ 12 $ 45 $ 50
Dividends on preferred stock 1 1 1 1
-----------------------------------------------------
Net income applicable
to common shares $ 39 $ 11 $ 44 $ 49
=====================================================

1997
Operating Revenues $ 803 $ 598 $ 624 $ 752
Operating expenses 687 470 525 657
-----------------------------------------------------
Operating income $ 116 $ 128 $ 99 $ 95
-----------------------------------------------------
Net income $ 50 $ 57 $ 37 $ 40
Dividends on preferred stock 1 1 1 1
-----------------------------------------------------
Net income applicable
to common shares $ 49 $ 56 $ 36 $ 39
=====================================================

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 . . . . . . . . . . . . . . 30

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

Consolidated Balance Sheets at December 31,
1998 and 1997. . . . . . . . . . . . . . . . . . . . . 32

Statements of Consolidated Cash Flows for the
years ended December 31, 1998, 1997 and 1996 . . . . . 34

Statements of Consolidated Changes in
Shareholders' Equity for the years ended
December 31, 1998, 1997 and 1996 . . . . . . . . . . . 36

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

Quarterly Financial Data (Unaudited) . . . . . . . . . . 61

2. Financial statement schedules

The following documents may be found in this report
at the indicated page numbers:

Independent Auditors' Consent and
Report on Schedule. . . . . . . . . . . . . . . . . . 63
Schedule I--Condensed Financial Information of Parent. . 64

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

3. Exhibits
See Exhibit Index on page 67 of this report.

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

INDEPENDENT AUDITORS' CONSENT AND REPORT ON SCHEDULE

To the Board of Directors and Shareholders of Pacific Enterprises:

We consent to the incorporation by reference in Registration
Statement Nos. 2-96782, 33-26357, 2-66833, 2-96781, 33-21908 and
33-54055 of Pacific Enterprises on Forms S-8 and Registration
Statement Nos. 33-24830 and 33-44338 of Pacific Enterprises on
Forms S-3 of our report dated January 27, 1999, except for Note 15
as to which the date is February 22, 1999, appearing in this Annual
Report on Form 10-K of Pacific Enterprises for the year ended
December 31, 1998.

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

/s/ DELOITTE & TOUCHE LLP

San Diego, California
March 31, 1999

Schedule I -- CONDENSED FINANCIAL INFORMATION OF PARENT

PACIFIC ENTERPRISES
Schedule 1
Condensed Financial Information of Parent

Condensed Statements of Income
(Dollars in millions)

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

Revenues and other income $ 11 $ 20 $ 65
Expenses, interest and income taxes 20 59 64
-------- -------- --------
Loss before subsidiary earnings (9) (39) 1
Subsidiary earnings 152 219 195
-------- -------- --------
Earnings applicable to common shares $ 143 $ 180 $ 196
======== ======== ========

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

Condensed Balance Sheets
(Dollars in millions)

Balance at December 31 1998 1997
---------- ----------

Assets:
Cash and temporary investments $ 3 $ 151
Other current assets 130 13
---------- ----------
Total current assets 133 164
Investments in subsidiaries 1,763 1,659
Deferred charges and other assets 162 232
---------- ----------
Total Assets $ 2,058 $ 2,055
========== ==========
Liabilities and Shareholders' Equity:
Dividends payable $ 1 $ 2
Due to affiliates 171 180
Other current liabilities 203 51
---------- ----------
Total current liabilities 375 233
Other long-term liabilities 136 353
Preferred stock 80 80
Common equity 1,467 1,389
---------- ----------
Total Liabilities and Shareholders' Equity $ 2,058 $ 2,055
========== ==========

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

Condensed Statements of Cash Flows
(Dollars in millions)

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

Cash flows from operating activities $ (220) $ (19) $ (110)
-------- ------- -------
Expenditures for property, plant and equipment (12) (10) --
Dividends received from subsidiaries 164 251 255
Increase in investments and other (53) (152) (1)
-------- ------- -------
Cash flows from investing activities 99 89 254
-------- ------- -------
Sale of common stock 27 17 8
Repurchase of common stock -- (48) (24)
Increase in short-term debt 43 --
Redemption of preferred stock -- -- (110)
Common dividends (97) (122) (119)
-------- ------- -------
Cash flows from financing activities (27) (153) (245)
-------- ------- -------
Net cash flow (148) (83) (101)
Cash and temporary investments,
beginning of year 151 234 335
-------- ------- -------
Cash and temporary investments, end of year $ 3 $ 151 $ 234
======== ======= =======

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

PACIFIC ENTERPRISES

By:
/s/ Richard D. Farman .
Richard D. Farman
Chairman and Chief Executive Officer

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

Name/Title Signature Date

Principal Executive Officers:
Richard D. Farman
Chairman, Chief Executive Officer /s/ Richard D. Farman March 2, 1999

Stephen L. Baum
President,
Chief Operating Officer /s/ Stephen L. Baum March 2, 1999

Principal Financial Officer:
Neal E. Schmale
Executive Vice President,
Chief Financial Officer /s/ Neal E. Schmale March 2, 1999

Principal Accounting Officer:
Frank H. Ault
Vice President, Controller /s/ Frank H. Ault March 2, 1999

Directors:
Richard D. Farman
Chairman /s/ Richard D. Farman 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 Articles of Incorporation of Pacific Enterprises (Pacific Enterprises
1996 Form 10-K; Exhibit 3.01).

3.02 Restated bylaws of Pacific Enterprises dated March 2, 1999.

Exhibit 4 -- Instruments Defining The Rights Of Security Holders

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

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

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

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

4.04 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).

4.05 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).

4.06 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).

4.07 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).

4.08 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).

4.09 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).

4.10 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 (Pacific Lighting Corporation 1984 Form
10-K; Exhibit 4.29).

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

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

4.13 Rights Agreement dated as of March 7, 1990 between Pacific Enterprises
and Security Pacific National Bank, as Rights Agent (Pacific Enterprises
September 25, 1992 Form 8-K; Exhibit 4).

Exhibit 10 -- Material Contracts

10.01 Form of Indemnification Agreement between Pacific Enterprises and each
of its directors and officers (Pacific Enterprises 1992 Form 10-K;
Exhibit 10.07).

10.03 Operating Agreement of Mineral JV, LLC, dated as of January 13, 1997
(Registration Statement No. 333-21229 filed by Mineral Energy Company
on February 5, 1997; Exhibit 10.5).

Executive Compensation Plans and Arrangements

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

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

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

10.12 Pacific Enterprises Deferred Compensation Plan for Key Management
Employees (Pacific Lighting Corporation 1985 Form 10-K; Exhibit 10.41).

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

10.16 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).

10.17 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).

10.18 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).

10.04 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).

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

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

10.07 Pacific Enterprises Supplemental Retirement and Survivor Plan (Pacific
Lighting Corporation 1984 Form 10-K; Exhibit 10.36).

10.08 Pacific Lighting Corporation Stock Payment Plan (Pacific Lighting
Corporation 1984 Form 10-K; Exhibit 10.37).

10.09 Pacific Lighting Corporation Pension Restoration Plan (Pacific Lighting
Corporation 1980 Form 10-K; Exhibit 10.28).

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

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

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

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

10.15 Pacific Enterprises Retirement Plan for Directors (Pacific Enterprises
1992 Form 10-K; Exhibit 10.20).

10.16 Pacific Enterprises Director's Deferred Compensation Plan (Pacific
Enterprises 1992 Form 10-K; Exhibit 10.21).

10.17 Amended and Restated Pacific Enterprises Employee Stock Option Plan (as
of March 4, 1997) (Pacific Enterprises 1996 Form 10-K; Exhibit 10.17).

10.18 Form of Severance Agreement (Pacific Enterprises 1996 Form 10-K;
Exhibit 10.18).

10.19 Form of Incentive Bonus Agreement (Pacific Enterprises 1996 Form 10-K;
Exhibit 10.19).

Exhibit 21 -- Subsidiaries

See Notes 1 and 3 of 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 - Independent Auditors' Consent, page 63.

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

DGN Distribuidora de Gas Natural

Enova Enova Corporation

EOR Enhanced Oil Recovery

ESOP Employee Stock Ownership Plan

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

PEI Pacific Enterprises International

PRP Potential Responsible Party

ROE Return on Equity

ROR Rate of Return

SDG&E San Diego Gas & Electric Company

SEC Securities and Exchange Commission

SEI Sempra Energy International

SER Sempra Energy Resources

Solutions Sempra Energy Solutions

SET Sempra Energy Trading

SEUV Sempra Energy Utility Ventures

SFAS Statement of Financial Accounting Standards

SoCalGas Southern California Gas Company

UEG Utility electric generation

VaR Value at Risk

70

3