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
- ------    -------
                           SEMPRA ENERGY
- -------------------------------------------------------------------
      (Exact name of registrant as specified in its charter)

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


101 ASH STREET, SAN DIEGO, CALIFORNIA                        92101
- -------------------------------------------------------------------
(Address of principal executive offices)                 (Zip Code) 
 
Registrant's telephone number, including area code    (619)696-2000
                                                     -------------- 

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: 

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

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

Indicate by check mark whether the registrant (1) has filed all 
reports required to be filed by Section 13 or 15(d) of the 
Securities Exchange Act of 1934 during the preceding 12 months and 
(2) has been subject to such filing requirements for the past 90 
days.                                         Yes [ X ]   No  [   ]    
  
Indicate by check mark if disclosure of delinquent filers pursuant 
to Item 405 of Regulation S-K is not contained herein, and will not 
be contained, to the best of registrant's knowledge, in definitive 
proxy or information statements incorporated by reference in Part 
III of this Form 10-K or any amendment to this Form 10-K.  [  ]   
 
Exhibit Index on page 31.  Glossary on page 43.  
 
Aggregate market value of the voting stock held by non-affiliates 
of the registrant as of January 31, 1999 was $5.6 billion.

Registrant's common stock outstanding as of February 28, 1999 was 
240,111,553 shares.

DOCUMENTS INCORPORATED BY REFERENCE: 
 
Portions of the 1998 Annual Report to Shareholders are incorporated 
by reference into Parts I, II, and IV. 
 
Portions of the Proxy 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 . . . . . . . . . . . . . . . . . . . . . .21
Item 3.  Legal Proceedings. . . . . . . . . . . . . . . . . . .21
Item 4.  Submission of Matters to a Vote of Security Holders. .22
         Executive Officers of the Registrant . . . . . . . . .22

PART II
Item 5.  Market for Registrant's Common Equity and Related
            Stockholder Matters . . . . . . . . . . . . . . . .22
Item 6.  Selected Financial Data. . . . . . . . . . . . . . . .23
Item 7.  Management's Discussion and Analysis of Financial
            Condition and Results of Operations . . . . . . . .23
Item 7A. Quantitative and Qualitative Disclosures 
            About Market Risk . . . . . . . . . . . . . . . . .23
Item 8.  Financial Statements and Supplementary Data. . . . . .24
Item 9.  Changes In and Disagreements with Accountants on
            Accounting and Financial Disclosure . . . . . . . .24

PART III
Item 10. Directors and Executive Officers of the Registrant . .24
Item 11. Executive Compensation . . . . . . . . . . . . . . . .24
Item 12. Security Ownership of Certain Beneficial Owners
            and Management. . . . . . . . . . . . . . . . . . .24
Item 13. Certain Relationships and Related Transactions . . . .24

PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
            on Form 8-K . . . . . . . . . . . . . . . . . . . .25

Independent Auditors' Consent and Report on Schedule. . . . . .27

Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . .30

Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . .31

Glossary. . . . . . . . . . . . . . . . . . . . . . . . . . . .43




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
A description of Sempra Energy and its subsidiaries (the Company) 
is given in "Management's Discussion and Analysis of Financial 
Condition and Results of Operations" of the 1998 Annual Report to 
Shareholders, which is incorporated by reference. 

GOVERNMENT REGULATION

Local Regulation
Southern California Gas Company (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.

San Diego Gas and Electric (SDG&E) has separate electric and gas 
franchises with the two counties and the 25 cities in its service 
territory. These franchises allow SDG&E to locate facilities for 
the transmission and distribution of electricity and natural gas in 
the streets and other public places. The franchises do not have 
fixed terms, except for the electric and natural gas franchises 
with the cities of Chula Vista (2003), Encinitas (2012), San Diego 
(2021) and Coronado (2028); and the natural gas franchises with the 
city of Escondido (2036) and the county of San Diego (2030).

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

The California Energy Commission (CEC) has discretion over 
electric-demand forecasts for the state and for specific service 
territories. Based upon these forecasts, the CEC determines the 
need for additional energy sources and for conservation programs. 
The CEC sponsors alternative-energy research and development 
projects, promotes energy conservation programs, and maintains a 
state-wide plan of action in case of energy shortages. In addition, 
the CEC certifies power-plant sites and related facilities within 
California.

Federal Regulation
The Federal Energy Regulatory Commission (FERC) regulates 
transmission access, the uniform systems of accounts, rates of 
depreciation and electric rates involving sales for resale. The 
FERC also regulates the interstate sale and transportation of 
natural gas.

The Nuclear Regulatory Commission (NRC) oversees the licensing, 
construction and operation of nuclear facilities. NRC regulations 
require extensive review of the safety, radiological and 
environmental aspects of these facilities. Periodically, the NRC 
requires that newly developed data and techniques be used to re-
analyze the design of a nuclear power plant and, as a result, 
requires plant modifications as a condition of continued operation 
in some cases.

Licenses and Permits
SDG&E obtains a number of permits, authorizations and licenses in 
connection with the construction and operation of its generating 
plants. Discharge permits, San Diego Air Pollution Control District 
permits and NRC licenses are the most significant examples. The 
licenses and permits may be revoked or modified by the granting 
agency if facts develop or events occur that differ significantly 
from the facts and projections assumed in granting the approval. 
Furthermore, discharge permits and other approvals are granted for 
a term less than the expected life of the facility. They require 
periodic renewal, which results in continuing regulation by the 
granting agency.

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

Other regulatory matters are described throughout this report.



SOURCES OF REVENUE

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

   Gas:
     Regular sales-
       Residential                 $   2,234  $   1,957  $   1,809
       Commercial/Industrial             571        617        573
       Utility Generation                  9         14          9
                                   ---------  ---------  ---------
                                       2,814      2,588      2,391
     Transportation & Exchange-
       Residential                        11         10         10
       Commercial/Industrial             277        273        257
       Utility Generation                 66         76         70
       Wholesale                           7         12         10
                                   ---------  ---------  ----------
                                         361        371        347
       Balancing and Other              (403)         5        (28)
                                   ---------  ---------  ----------
         Total Gas Revenues            2,772      2,964      2,710
                                   ---------  ---------  ----------
   Electric:
     Residential                         637        684        647
     Commercial                          643        680        625
     Industrial                          233        268        261
     Balancing and Other                 352        137         58
                                   ---------  ---------  ---------
         Total Electric Revenues       1,865      1,769      1,591
                                   ---------  ---------  ---------
     Total Utility Revenues        $   4,637  $   4,733  $   4,301
                                   =========  =========  =========

Industry segment information is contained in "Management's 
Discussion and Analysis of Financial Condition and Results of 
Operations" and in Note 15 of the "Notes to Consolidated Financial 
Statements" of the 1998 Annual Report to Shareholders, which is 
incorporated by reference.

NATURAL GAS OPERATIONS

The Company purchases, sells, distributes, stores and transports 
natural gas. SDG&E purchases natural gas for resale to its 
customers in San Diego and southern Orange counties, and as fuel 
for its generating plants. SoCalGas owns and operates a natural gas 
distribution, transmission and storage system that supplies natural 
gas in 535 cities and communities throughout a 23,000-square-mile 
service territory comprising most of southern and part of central 
California.

Supplies of Natural Gas 
The Company buys natural gas under several short-term and long-term 
contracts. Short-term purchases are based on monthly-spot-market 
prices. The Company has firm pipeline capacity contracts with 
pipeline companies that expire at various dates through 2023.

Most of the natural gas purchased and delivered by the Company is 
produced outside of California. These supplies are delivered to the 
Company's intrastate transmission system by interstate pipeline 
companies, primarily El Paso Natural Gas Company and Transwestern 
Natural Gas Company. These interstate companies provide 
transportation services for supplies purchased from the Company's 
transportation customers or other sources. 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" of the 1998 Annual Report to 
Shareholders, which is incorporated by reference.

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





                                          

                                                                Year Ended December 31
                                          -------------------------------------------------------------------
                                            1998           1997          1996           1995           1994
- -------------------------------------------------------------------------------------------------------------
                                                                                      
Natural Gas Purchases (billions of cubic feet):
 Market                                      388            330           323            296            342
 Long-Term Contracts                         104            100           108            128            137
                                          -------        -------       -------        -------        -------
    Total Gas Purchases                      492            430           431            424            479

Customer-Owned and
  Exchange Receipts                          521            514           422            531            565

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

Company Use and
  Unaccounted For                            (23)           (11)          (11)            (5)           (15)
                                          -------        -------       -------        -------        -------
    Net Deliveries                           962            930           884            937          1,020 
                                          =======        =======       =======        =======        =======

Natural Gas Purchases: (millions of dollars)
 Commodity Costs                          $1,092         $1,160        $  879         $  666         $  890

 Fixed Charges*                              174            250           276            264            368
                                          -------        -------       -------        -------        -------
    Total Gas Purchases                   $1,266         $1,410        $1,155         $  930         $1,258
                                          =======        =======       =======        =======        =======

Average Commodity Cost of Gas Purchased
  (Dollars per Thousand Cubic Feet)       $ 2.22         $ 2.69        $ 2.04         $ 1.57         $ 1.86
                                          =======        =======       =======        =======        =======

 *  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.




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 79 percent 
of total natural gas volumes purchased by the Company during 1998, 
as compared with 77 percent and 75 percent during 1997 and 1996, 
respectively. These supplies were generally purchased at prices 
significantly below those of long-term sources of supply.

During 1998, the Company delivered 962 bcf of natural gas through 
its system. Approximately 54 percent of these deliveries were 
customer-owned natural gas for which the Company provided 
transportation services. The balance of natural gas deliveries was 
gas purchased by the Company and resold to customers. The Company 
estimates that sufficient natural gas supplies will be available to 
meet the requirements of its customers for the next several years. 

Customers
For regulatory purposes, customers are separated into core and 
noncore customers. Core customers are primarily residential and 
small commercial and industrial customers, without alternative fuel 
capability. There are 5.6 million core customers (5.4 million 
residential and 230,000 small commercial and industrial). Noncore 
customers consist primarily of utility electric generation (UEG), 
wholesale, and large commercial and industrial customers, and total 
1,700.

Most core customers purchase natural gas directly from the Company. 
Core customers are permitted to aggregate their natural gas 
requirement and, up to a limit of 10 percent of the Company's core 
market, to purchase natural gas directly from brokers or producers. 
The Company continues to be obligated to purchase reliable supplies 
of natural gas to serve the requirements of its core customers.

Noncore customers have the option of purchasing natural gas either 
from the Company or from other sources, such as brokers or 
producers, for delivery through the Company's transmission and 
distribution system. The only natural gas supplies that the Company 
may offer for sale to noncore customers are the same supplies that 
it purchases for its core customers. Most noncore customers procure 
their own natural gas supply.

In 1998 for SoCalGas, 87 percent of the CPUC-authorized natural gas 
margin was allocated to the core customers, with 13 percent 
allocated to the noncore customers. In 1998 for SDG&E, 90 percent 
of the CPUC-authorized natural gas margin was allocated to the core 
customers, with 10 percent allocated to the noncore customers.

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

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


Demand for Natural Gas
Natural gas is a principal energy source for residential, 
commercial, industrial and UEG customers. Natural gas competes with 
electricity for residential and commercial cooking, water heating, 
space heating and clothes drying, and with other fuels for large 
industrial, commercial and UEG uses. Growth in the natural-gas 
markets is largely dependent upon the health and expansion of the 
southern California economy. The Company added approximately 58,000 
new customers in 1998. This represents a growth rate of 1.0 
percent. The Company expects its growth for 1999 will continue at 
about the 1998 level.

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

Demand for natural gas by noncore customers is very sensitive to 
the price of alternative competitive fuels. Although the number of 
noncore customers in 1998 was only 1,700, it accounted for 
approximately 12 percent of the authorized natural gas revenues and 
57 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 large UEG customers is also greatly affected by the price and 
availability of electric power generated in other areas and 
purchased by the Company's UEG customers. Natural gas demand in 
1998 for UEG customer use decreased as a result of decreased demand 
for electricity. UEG customer demand increased in 1997 as a result 
of higher demand for electricity and less availability of hydro-
electricity.

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

Other
Additional information concerning customer demand and other aspects 
of natural-gas operations is provided under "Management's 
Discussion and Analysis of Financial Condition and Results of 
Operations" and in Note 13 of the "Notes to Consolidated Financial 
Statements" of the 1998 Annual Report to Shareholders, which is 
incorporated by reference.

ELECTRIC OPERATIONS

Resource Planning
In September 1996, California enacted a law restructuring 
California's electric-utility industry. The legislation adopts the 
December 1995 CPUC policy decision restructuring the industry to 
stimulate competition and reduce rates. Beginning on March 31, 
1998, customers were given the opportunity to choose to continue to 
purchase their electricity from the local utility under regulated 
tariffs, to enter into contracts with other energy-service 
providers (direct access) or to buy their power from the 
independent Power Exchange (PX) that serves as a wholesale power 
pool allowing all energy producers to participate competitively.

Additional information concerning electric-industry restructuring 
is provided in "Management's Discussion and Analysis of Financial 
Condition and Results of Operations" and in Notes 13 and 14 of the 
"Notes to Consolidated Financial Statements" of the 1998 Annual 
Report to Shareholders, which is incorporated by reference.

Electric Resources
In connection with electric-industry restructuring, beginning March 
31, 1998, the California investor-owned utilities (IOUs) are 
obligated to bid their power supply, including owned generation and 
purchased-power contracts, into the PX. The IOUs are also obligated 
to purchase from the PX the power that they sell. Based on 
generating plants in service and purchased-power contracts 
currently in place, at February 28, 1999 the net megawatts (mw) of 
electric power available to SDG&E to bid into the PX are as 
follows:

    Source                                      Net mw
    --------------------------------------------------
    Gas/oil generating plants                    1,641
    Combustion turbines                            332
    Nuclear generating plants                      430
    Long-term contracts with other utilities       275
    Contracts with others                          593
                                                 -----
            Total                                3,271 
                                                 =====

SDG&E reported an all-time record for electricity usage of 3,960 mw 
on August 31, 1998. The previous record of 3,668 mw was reached on 
September 4, 1997.

Gas/Oil Generating Plants: In connection with electric-industry 
restructuring, in December 1998, SDG&E entered into agreements for 
the sale of its South Bay and Encina power plants and 17 combustion 
turbines. The sales are subject to regulatory approval and are 
expected to close during the first half of 1999.

San Onofre Nuclear Generating Station (SONGS): SDG&E owns 20 
percent of the three nuclear units at SONGS (south of San Clemente, 
California). The cities of Riverside and Anaheim own a total of 5 
percent of SONGS Units 2 and 3. Southern California Edison (Edison) 
owns the remaining interests and operates the units.

SONGS Unit 1 was removed from service in November 1992 when the 
CPUC issued a decision to permanently shut down the unit. At that 
time SDG&E began the recovery of its remaining capital investment, 
with full recovery completed in April 1996. SDG&E and Edison filed 
a decommissioning plan in November 1994, although final 
decommissioning is not scheduled to occur until 2013 when Units 2 
and 3 are also decommissioned. However, SDG&E and the other owners 
have requested that the CPUC grant authority to begin 
decommissioning Unit 1 on January 1, 2000. The unit's spent nuclear 
fuel has been removed from the reactor and stored on-site. In March 
1993, the NRC issued a Possession-Only License for Unit 1, and the 
unit was placed in a long-term storage condition in May 1994. 

SONGS Units 2 and 3 began commercial operation in August 1983 and 
April 1984, respectively. SDG&E's share of the capacity is 214 mw 
of Unit 2 and 216 mw of Unit 3.

During 1998 SDG&E spent $14 million on capital modifications and 
additions and expects to spend $11 million in 1999. SDG&E deposits 
funds in an external trust to provide for the future dismantling 
and decontamination of the units.

Additional Information: Additional information concerning SDG&E's 
power plants, the SONGS units, nuclear decommissioning and industry 
restructuring (including SDG&E's divestiture of its electric 
generation assets) is provided immediately below and in 
"Environmental Matters" and "Electric Properties," herein, as well 
as in "Management's Discussion and Analysis of Financial Condition 
and Results of Operations" and in Notes 6, 13 and 14 of the "Notes 
to Consolidated Financial Statements" of the 1998 Annual Report to 
Shareholders, which is incorporated by reference.

Purchased Power: The following table lists contracts with the 
various suppliers:      
                                            Megawatt   
  Supplier              Period             Commitment   Source  
- -------------------------------------------------------------------
Long-Term Contracts with Other Utilities:

Portland General
Electric (PGE)         Through December 2013    75    Coal  

Public Service
Company of 
New Mexico (PNM)       Through April 2001      100    System supply
                   
PacifiCorp             Through December 2001   100    System Supply
                                             -----
                  Total                        275
                                             =====
Contracts with Others:  

Illinova Power 
Marketing              Through December 1999   200    System Supply 

LG&E Power Marketing   Through December 2001   150    System Supply

Applied Energy         Through December 2019   102    Cogeneration  

Yuma Cogeneration      Through June 2024        50    Cogeneration  

Goal Line Limited      Through December 2025    50    Cogeneration  
Partnership  

Other (89)             Various                  41    Cogeneration  
                                            ------
                  Total                        593
                                            ======

Under the contracts with PGE and PNM, SDG&E pays a capacity charge 
plus a charge based on the amount of energy received. Charges under 
these contracts are based on the selling utility's costs, including 
a return on and depreciation of the utility's rate base (or lease 
payments in cases where the utility does not own the property), 
fuel expenses, operating and maintenance expenses, transmission 
expenses, administrative and general expenses, and state and local 
taxes. Charges under contracts from PacifiCorp, LG&E and Illinova 
are for firm energy only and are based on the amount of energy 
received. The prices under these contracts are at market value at 
the time the contracts were negotiated. Costs under the remaining 
contracts (all with Qualifying Facilities) are based on SDG&E's 
avoided cost.

Additional information concerning SDG&E's purchased-power contracts 
is described immediately below, and in "Management's Discussion and 
Analysis of Financial Condition and Results of Operations" and in 
Note 13 of the "Notes to Consolidated Financial Statements" of the 
1998 Annual Report to Shareholders, which is incorporated by 
reference.

Power Pools    
In 1964 SDG&E, Pacific Gas & Electric (PG&E), and Edison entered 
into the California Power Pool Agreement. It provided for the 
transfer of electrical capacity and energy by purchase, sale or 
exchange during emergencies and at other mutually determined times. 
Due to electric-industry restructuring (discussed elsewhere herein) 
the California Power Pool was terminated by the FERC in May 1997. 
However, SDG&E, Edison, PG&E and the Los Angeles Department of 
Water and Power will continue to abide by the provisions of the 
existing California Statewide Emergency Plan for sharing capacity 
and energy in the event of a severe resource emergency.

SDG&E is a participant in the Western Systems Power Pool (WSPP), 
which includes an electric-power and transmission-rate agreement 
with utilities and power agencies located throughout the United 
States and Canada. More than 150 investor-owned and municipal 
utilities, state and federal power agencies, energy brokers, and 
power marketers share power and information in order to increase 
efficiency and competition in the bulk power market. Participants 
are able to target and coordinate delivery of cost-effective 
sources of power from outside their service territories through a 
centralized exchange of information. Although the extent has not 
yet been determined, the status of the WSPP is likely to change due 
to industry restructuring and the initiation of the PX and the 
Independent System Operator (ISO). 

Transmission Arrangements   
In addition to interconnections with other California utilities, 
SDG&E has firm transmission capabilities for purchased power from 
the Northwest, the Southwest and Mexico.

Pacific Intertie: The Pacific Intertie, consisting of AC and DC 
transmission lines, enables SDG&E to purchase and receive surplus 
coal and hydroelectric power from the Northwest. SDG&E, PG&E, 
Edison and others share transmission capacity on the Pacific 
Intertie under an agreement that expires in July 2007. SDG&E's 
share of the intertie was 266 mw. Due to electric-industry 
restructuring (see "Transmission Access" below), the operating 
rights of SDG&E, Edison and PG&E on the Pacific Intertie have been 
transferred to the ISO.

Southwest Powerlink: SDG&E's 500-kilovolt Southwest Powerlink 
transmission line, which is shared with Arizona Public Service 
Company and Imperial Irrigation District, extends from Palo Verde, 
Arizona to San Diego and enables SDG&E to import power from the 
Southwest. SDG&E's share of the line is 931 mw, although it can be 
less, depending on specific system conditions.

Mexico Interconnection: Mexico's Baja California Norte system is 
connected to SDG&E's system via two 230-kilovolt interconnections 
with firm capability of 408 mw. SDG&E uses these interconnections 
for transactions with Comision Federal de Electricidad (CFE), 
Mexico's government-owned electric utility.

Transmission Access   
As a result of the enactment of the National Energy Policy Act of 
1992, the FERC has established rules to implement the Act's 
transmission-access provisions. These rules specify FERC-required 
procedures for others' requests for transmission service. In 
October 1997 the FERC approved the transfer of control by the 
California IOUs of their transmission facilities to the ISO. 
Beginning on March 31, 1998 the ISO is responsible for the 
operation and control of the transmission lines. Additional 
information regarding the ISO and transmission access is discussed 
below and in "Management's Discussion and Analysis of Financial 
Condition and Results of Operations" of the 1998 Annual Report to 
Shareholders, which is incorporated by reference.

Fuel and Purchased-Power Costs   
The following table shows the percentage of each electric-fuel 
source used by SDG&E and compares the costs of the fuels with each 
other and with the total cost of purchased power: 

                    Percent of Kwhr              Cents per Kwhr   
- -------------------------------------------------------------------   
                  1998    1997    1996        1998    1997    1996   
                  -----   -----   -----       ----    ----    ----   
Natural gas       17.3%   19.8%   22.8%        3.0     3.3     2.8   
Nuclear fuel      11.5    11.8    19.6         0.6     0.6     0.5   
Fuel oil                   0.1     1.1                 2.4     2.2   
                  -----   -----   -----           
Total generation  28.8    31.7    43.5   
Purchased
power - net       26.3    68.3    56.5         3.6     2.8     3.1   
ISO/PX            44.9                         3.4
                  -----   -----   -----             
Total            100.0%  100.0%  100.0%   
                 ======  ======  ======

The cost of purchased power includes capacity costs as well as the 
costs of fuel. The cost of natural gas includes transportation 
costs. The costs of natural gas, nuclear fuel and fuel oil do not 
include SDG&E's capacity costs. While fuel costs are significantly 
less for nuclear units than for other units, capacity costs are 
higher.    

Electric Fuel Supply
Natural Gas: Information concerning natural gas is provided in 
"Natural Gas Operations" herein. 

Nuclear Fuel: The nuclear-fuel cycle includes services performed by 
others. These services and the dates through which they are under 
contract are as follows: 

Mining and milling of uranium concentrate                    2003
Conversion of uranium concentrate to uranium hexafluoride    2003
Enrichment of uranium hexafluoride(1)                        2003
Fabrication of fuel assemblies                               2003
Storage and disposal of spent fuel(2)                         --

(1) SDG&E has a contract with Urenco, a British consortium, for 
enrichment services through 2003.

(2) Spent fuel is being stored at SONGS, where storage capacity 
will be adequate at least through 2006. If necessary, 
modifications in fuel-storage technology can be implemented to 
provide on-site storage capacity for operation through 2013, 
the expiration date of the NRC operating license. The plan of 
the U.S. Department of Energy (DOE) is to provide a permanent 
storage site for the spent nuclear fuel by 2010.
 
Pursuant to the Nuclear Waste Policy Act of 1982, SDG&E entered 
into a contract with the DOE for spent-fuel disposal. Under the 
agreement, the DOE is responsible for the ultimate disposal of 
spent fuel. SDG&E is paying a disposal fee of $0.90 per megawatt-
hour of net nuclear generation. Disposal fees average $3 million 
per year.

To the extent not currently provided by contract, the availability 
and the cost of the various components of the nuclear-fuel cycle 
for SDG&E's nuclear facilities cannot be estimated at this time. 

Additional information concerning nuclear-fuel costs is discussed 
in Note 13 of the "Notes to Consolidated Financial Statements" of 
the 1998 Annual Report to Shareholders, which is incorporated by 
reference.

INTERNATIONAL OPERATIONS

Sempra Energy International (SEI) develops, operates and invests in 
energy infrastructure projects, including natural gas distribution 
systems and power generation facilities, outside of the United 
States.

In August 1998, SEI was awarded a 10-year agreement by the Mexican 
Federal Electric Commission (CFE) to supply natural gas to an 
electric power plant in Rosarito, Baja California.  The terms of 
the agreement include a provision to construct a pipeline from the 
US - Mexico border to the plant and call for SEI to provide a 
complete energy supply package.  In addition, SEI and Proxima Gas 
S.A. de C.V., as partners in the Mexican companies Distribuidora de 
Gas Natural (DGN) de Mexicali and Distribuidora de Gas Natural 
(DGN) de Chihuahua, operate natural gas distribution systems in 
Mexicali and Chihuahua, Mexico.

SEI also has interests in natural gas distribution partnerships in 
Argentina and Uruguay.  In March 1998, SEI increased its existing 
investment in two Argentine natural gas utility holding companies 
(Sodigas Pampeana S.A. and Sodigas Sur S.S.) from 12.5 percent to 
21.5 percent, by purchasing an additional interest for $40 million.  

The net losses for international operations were $4 million and $9 
million, after-tax, for 1998 and 1997, respectively. Additional 
information on international operations is discussed in 
"Management's Discussion and Analysis of Financial Condition and 
Results of Operations" and in Note 3 of the "Notes to Consolidated 
Financial Statements" of the 1998 Annual Report to Shareholders, 
which is incorporated by reference.

SEMPRA ENERGY TRADING (SET)

SET, a leading natural gas and power marketing firm headquartered 
in Stamford, Connecticut, was jointly acquired by Pacific 
Enterprises (PE) and Enova Corporation (Enova) on December 31, 
1997. (PE and Enova combined to form Sempra Energy in June 1998.) 
In July 1998, SET purchased a wholesale trading and commercial 
marketing subsidiary of Consolidated Natural Gas, to expand its 
operation in the eastern United States.

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. For the year ended December 31, 1998, SET had 
operating revenues of $110 million and after-tax net losses of $13 
million. The losses were due to the amortization of costs 
associated with the acquisition by PE and Enova. Additional 
information on SET is discussed in "Management's Discussion and 
Analysis of Financial Condition and Results of Operations" and in 
Notes 3 and 10 of the "Notes to Consolidated Financial Statements" 
of the 1998 Annual Report to Shareholders, which is incorporated by 
reference.

RATES AND REGULATION

The Company's principal subsidiaries, SoCalGas and SDG&E, are 
regulated by the CPUC. The CPUC 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 the 
profitability of the Company. Both the electric and gas industries 
are currently undergoing transitions to competition (see below).

Electric Industry Restructuring
In September 1996, California enacted a law restructuring its 
electric-utility industry. The legislation adopts the December 1995 
CPUC policy decision restructuring the industry to stimulate 
competition and reduce rates. Additional information on electric-
industry restructuring is discussed in "Management's Discussion and 
Analysis of Financial Condition and Results of Operations" and in 
Note 14 of the "Notes to Consolidated Financial Statements" of the 
1998 Annual Report to Shareholders, which is incorporated by 
reference.




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 14 of the "Notes to Consolidated Financial 
Statements" of the 1998 Annual Report to Shareholders, which is 
incorporated by reference.

Balancing Accounts
Previously, earnings fluctuations from changes in the costs of fuel 
oil, purchased energy and natural gas, and consumption levels for 
electricity and the majority of natural gas were eliminated by 
balancing accounts authorized by the CPUC. This is still the case 
for most natural-gas operations. However, as a result of 
California's electric restructuring law, overcollections recorded 
in the electric balancing accounts were applied to transition cost 
recovery, and fluctuations in costs and consumption levels can 
affect earnings from electric operations. 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" of the 
1998 Annual Report to Shareholders, which is incorporated by 
reference.

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 both 
SoCalGas and SDG&E. 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 14 of the "Notes to Consolidated Financial Statements" of the 
1998 Annual Report to Shareholders, which is incorporated by 
reference.

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 14 of the "Notes to Consolidated Financial 
Statements" of the 1998 Annual Report to Shareholders, which is 
incorporated by reference.

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 14 of the "Notes 
to Consolidated Financial Statements" of the 1998 Annual Report to 
Shareholders, which is incorporated by reference.

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 14 of 
the "Notes to Consolidated Financial Statements" of the 1998 Annual 
Report to Shareholders, which is incorporated by reference.

Cost of Capital
Under PBR, annual Cost of Capital proceedings have been replaced by 
an automatic adjustment mechanism if changes in certain indicies 
exceed established tolerances. For 1999, SoCalGas is authorized to 
earn a rate of return on rate base (ROR) of 9.49 percent and a rate 
of return on common equity (ROE) of 11.6 percent, the same as in 
1998, unless interest-rate changes are large enough to trigger an 
automatic adjustment. SDG&E is seeking CPUC approval to establish 
new, separate rates of return for SDG&E's electric-distribution and 
natural-gas businesses. A CPUC decision is expected during the 
second quarter of 1999. In 1998, SDG&E's natural gas and electric 
distribution operations were authorized to earn an ROE of 11.6 
percent and an ROR of 9.35 percent. 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 14 of the "Notes to Consolidated Financial Statements" of 
the 1998 Annual Report to Shareholders, which is incorporated by 
reference.

ENVIRONMENTAL MATTERS

Discussions about environmental issues affecting the Company are 
included in "Management's Discussion and Analysis of Financial 
Condition and Results of Operations" of the 1998 Annual Report to 
Shareholders, which is incorporated by reference.  The following 
should be read in conjunction with those discussions.

Hazardous Substances
The utilities 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 
jurisdictions 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.

The Redevelopment Agency for the City of San Diego has exerted this 
authority affecting Station A and adjacent properties to 
accommodate a major league ballpark and ancillary development 
proposed by the City. During the early 1900s, the Company and its 
predecessors manufactured gas from coal and oil at its Station A 
facility and at two small facilities in Escondido and Oceanside. 
Environmental assessments have identified residual by-products from 
the gas manufacturing process and subsurface hydrocarbon 
contamination on portions of the Station A site. Initial cleanup 
actions commenced in 1998, and are expected to be completed in 
1999, at an estimated cost of $5 million. The Company is 
negotiating with the redevelopment agency to create a cooperative 
agreement as a result of which the Station A cleanup will be 
performed under the oversight of the San Diego County Department of 
Environmental Health, though the redevelopment agency will retain 
its rights to enforce the cleanup in the event the Company did not 
complete it. Contaminants resulting from the gas-manufacturing 
process by-products were assessed at the Company's Escondido and 
Oceanside sites. Remediation at the Escondido site has been 
completed and a site-closure letter received. Remediation at the 
Oceanside facility is in process and the cost is not expected to be 
significant. 

Station B is located in downtown San Diego and was operated as a 
steam and electric-generating facility between 1911 and June 1993 
when it was closed. Pursuant to a cleanup and abatement order, the 
Company remediated hydrocarbon contamination discovered as a result 
of the removal of three 100,000-gallon underground diesel-fuel 
storage tanks from an adjacent substation. Asbestos was used in the 
construction of the power plant. Activities to dismantle and 
decommission the facility required the removal of the asbestos in a 
manner complying with all applicable environmental, health and 
safety laws. This work also included the removal or cleanup of 
certain loose and flaking lead-based paints, small amounts of PCBs, 
fuel oil and other substances. These activities were completed in 
1998 at a cost of $6 million.  

The Company is in the process of selling its electric-generating 
assets. As a part of its environmental due diligence, the Company 
conducted a thorough environmental assessment of the South Bay and 
Encina power plants and 17 combustion turbine sites to determine 
the environmental condition of each. Pursuant to the sale 
agreements for such facilities, the utility and the buyers have 
apportioned responsibility for such environmental conditions 
generally based on contamination existing at the time of transfer 
and the cleanup level necessary for the continued use of the sites 
for electric generation. While the sites are relatively clean, the 
assessments identified instances of contamination, principally 
hydrocarbon releases, some of which were determined to be 
significant and to require cleanup in accordance with the 
agreement. Estimated costs to perform the necessary remediation are 
$7 to $8 million at the South Bay power plant, $0.9 million at the 
Encina power plant, and $1.9 million at the combustion turbine 
sites. These costs will be offset against the sales price for the 
facilities, together with other appropriate costs, and the 
remaining net proceeds will be offset against the Company's other 
transition costs.

The Company and its subsidiaries have been named as potential 
responsible parties (PRPs) for two landfill sites and three 
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 Company has estimated the costs of 
remediation at Casmalia to be $1.1 million. In 1998, the Company 
completed work efforts of $225,241. Remedial actions and 
negotiations with other PRPs and the United States Environmental 
Protection Agency (EPA) have been continuing since March 1993. The 
Company 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 $644,133 was completed 
during 1998. Remedial actions and negotiations have been in 
progress since June 1986.

In the early 1990s, the Company was notified of hazards at two 
former industrial waste treatment facilities, Industrial Waste 
Processing (Industrial) and Cal Compact (Compact), where the 
Company 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 approximately $3,700 of remedial action was 
completed in 1998. The nature and extent for remediation of the 
Compact site is estimated to be $120,000. During 1998, the Company 
completed remedial efforts of this site at a cost of $48,000 and is 
involved in ongoing negotiations with the California Department of 
Toxic Substances Control (DTSC). The Company and 10 other entities 
have also been named PRPs by the DTSC as liable for any required 
corrective action regarding contamination at a site in Pico Rivera, 
California. DTSC has taken this action because the Company and 
others sold used electrical transformers to the site's owner. The 
DTSC considers the Company to be responsible for 7.4 percent of the 
transformer-related contamination at the site. The estimate for the 
development of the cleanup plan is $1 million. The estimate for the 
actual cleanup is in the $2 million to $8 million range. 

At December 31, 1998, the Company's estimated remaining 
investigation and remediation liability related to hazardous waste 
sites not detailed above was $83 million, of which 90 percent is 
authorized to be recovered through the Hazardous Waste 
Collaborative mechanism. The Company believes that any costs not 
ultimately recovered through rates, insurance or other means, upon 
giving effect to previously established liabilities, will not have 
a material adverse effect on the Company's consolidated results of 
operations or its 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.	

Electric and Magnetic Fields (EMFs) 
Although scientists continue to research the possibility that 
exposure to EMFs causes adverse health effects, science, to date, 
has not demonstrated a cause-and-effect relationship between 
adverse health effects and exposure to the type of EMFs emitted by 
utilities' power lines and other electrical facilities.  Some 
laboratory studies suggest that such exposure creates biological 
effects, but those effects have not been shown to be harmful. The 
studies that have most concerned the public are epidemiological 
studies, some of which have reported a weak correlation between 
childhood leukemia and the proximity of homes to certain power 
lines and equipment. Other epidemiological studies found no 
correlation between estimated exposure and any disease. Scientists 
cannot explain why some studies using estimates of past exposure 
report correlations between estimated EMF levels and disease, while 
others do not.

To respond to public concerns, the CPUC has directed California 
utilities to adopt a low-cost EMF-reduction policy that requires 
reasonable design changes to achieve noticeable reduction of EMF 
levels that are anticipated from new projects. However, consistent 
with the major scientific reviews of the available research 
literature, the CPUC has indicated that no health risk has been 
identified.

Air and Water Quality
As mentioned above, SDG&E has entered into agreements for the sale 
of its fossil-fueled generating facilities. The completion of these 
sales will, for the most part, eliminate the potential impact of 
the following issues. 

During 1996 and 1997, SDG&E installed equipment on South Bay Unit 1 
in order to comply with the nitrogen-oxide-emission limits that the 
APCD imposed on electric-generating boilers through its Rule 69. 
The estimated capital costs for compliance with the rule have 
decreased to an immaterial amount due to the sale of the electric-
generating power plants. The California Air Resources Board has 
expressed concern that Rule 69 does not meet the requirements of 
the California Clean Air Act and may advocate or propose more 
restrictive emissions limitations which will likely cause SDG&E's 
Rule 69 compliance costs to increase.
	
Wastewater discharge permits issued by the Regional Water Quality 
Control Board (RWQCB) for the Company's Encina and South Bay power 
plants are required to enable the utility to discharge its cooling 
water and certain other wastewaters into the Pacific Ocean and into 
San Diego Bay. Wastewater discharge permits are prerequisite to the 
continuation of cooling-water and other wastewater discharges and, 
therefore, the continued operation of the power plants as they are 
currently configured. Increasingly stringent cooling-water and 
wastewater discharge limitations may be imposed in the future and 
the utility may be required to build additional facilities or 
modify existing facilities to comply with these requirements. Such 
facilities could include wastewater treatment facilities, cooling 
towers, intake structures or offshore-discharge pipelines. Any 
required construction could involve substantial expenditures, and 
certain plants or units may be unavailable for electric generation 
during construction.

In 1981, the Company submitted a demonstration study in support of 
its request for two exceptions to certain thermal discharge 
requirements imposed by the California Thermal Plan for Encina 
power plant Unit 5.  In November 1994, the RWQCB issued a new 
discharge permit, subject to the results of certain additional 
thermal discharge and cooling-water-related studies, to be used to 
evaluate the exception requests. The results of these additional 
studies were submitted to the RWQCB and the United States 
Environmental Protection Agency in 1997. If the utility's exception 
requests are denied, the utility could be required to construct 
off-shore discharge facilities, or other structures at an estimated 
cost of $75 million to $100 million or to perform mitigation, the 
costs of which may be significant.	

In November 1996, the RWQCB issued a new discharge permit to the 
Company for the South Bay power plant. The Company filed an appeal 
to the State Water Resources Control Board (SWRCB) of various 
provisions which SDG&E considered unduly stringent. Certain of 
these matters were resolved in negotiations among the RWQCB, the 
SWRCB and certain environmental groups. The SWRCB dismissed the 
remaining matters, which the Company thereafter appealed to the San 
Diego County Superior Court. These latter issues were subsequently 
settled through negotiations between the Company and the RWQCB. All 
of the settled issues have been incorporated into the November 1996 
NPDES permit by permit addendums adopted by the RWQCB. The Superior 
Court case will be dismissed after the expiration of the RWQCB 
appeal and EPA review periods.

California has enacted legislation to protect ground water from 
contamination by hazardous substances. Underground storage 
containers require permits, inspections and periodic reports, as 
well as specific requirements for new tanks, closure of old tanks 
and monitoring systems for all tanks. It is expected that cleanup 
of sites previously contaminated by underground tanks will occur 
for an unknown number of years. The Company cannot predict the cost 
of such cleanup.

In May 1987 the RWQCB issued the Company a cleanup and abatement 
order for gasoline contamination originating from an underground 
storage tank located at the Company's Mountain Empire Operation and 
Maintenance facility. SDG&E assessed the extent of the 
contamination, removed all contaminated soil and completed 
remediation of the site. Monitoring of the site confirms its 
remediation. The Company has applied for and is awaiting a site-
closure letter from the RWQCB.

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" of the 1998 Annual Report to Shareholders, 
which is incorporated by reference.

Wages
The utilities employ over 9,000 persons. Field, technical and most 
clerical employees at SoCalGas area 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. 
Employees at SDG&E are represented by the Local 465 International 
Brotherhood of Electrical Workers with two labor agreements. The 
generation contract runs through February 28, 2001 and negotiations 
for the utility contract (transmission and distribution) are 
ongoing.

Employees of Registrant
As of December 31, 1998 the Company had 11,148 employees, compared 
to 11,387 at December 31, 1997. The employment level decreased due 
to synergies resulting from the Enova and Pacific Enterprises 
business combination.

ITEM 2. PROPERTIES

Electric Properties
The Company's generating capacity is described in "Electric 
Resources" herein.

The Company's electric transmission and distribution facilities 
include substations, and overhead and underground lines. 
Periodically various areas of the service territory require 
expansion to handle customer growth.

Natural Gas Properties
At December 31, 1998, the Company owned approximately 3,024 miles 
of transmission and storage pipeline, 50,955 miles of distribution 
pipeline and 49,520 miles of service piping. It also owned 12 
transmission compressor stations and 6 underground storage 
reservoirs (with a combined working storage capacity of 
approximately 116 Bcf).

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

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.

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

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

ITEM 3. LEGAL PROCEEDINGS

Except for the matters referred to in the financial statements 
incorporated by reference in Item 8 or referred to elsewhere in 
this Annual Report, neither Sempra Energy nor any of its 
subsidiaries is a party to, nor is their 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     Vice Chairman, President and Chief 
                                 Operating Officer

Donald E. Felsinger       51     Group President - Nonregulated
                                 Business Units

Warren I. Mitchell        61     Group President - Regulated 
                                 Business Units

John R. Light             57     Executive Vice President and 
                                 General Counsel

Neal E. Schmale           52     Executive Vice President and 
                                 Chief Financial Officer

Jerry D. Florence         50     Senior Vice President - Corporate
                                 Communications

Frederick E. John         52     Senior Vice President - External
                                 Affairs

Margot A. Kyd             45     Senior Vice President and 
                                 Chief Administrative Officer

Frank H. Ault             54     Vice President and Controller


* As of December 31, 1998.    

Each Executive Officer has been an officer of the Company or one of its 
subsidiaries for more than five years, with the exception of 
Mssrs. Light, Schmale and Florence. 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. Prior to joining the Company in 1998, 
Mr. Florence held officer positions with Nissan North America, Inc. and 
Nissan Motor Corporation, U.S.A. 


                             PART II

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

Common stock of Sempra Energy is traded on the New York and 
Pacific stock exchanges. At February 28, 1999 there were 
approximately 100,000 holders of record of the Company's common 
stock. The quarterly common stock information required by Item 5 
is included in the schedule of Quarterly Financial Data of the 
1998 Annual Report to Shareholders, which is incorporated by 
reference. 

Dividend Restrictions
At December 31, 1998, $699 million of the Company's retained 
earnings was available for future dividends due to the CPUC's 
regulation of the utilities' capital structure. Additional 
information is discussed in "Management's Discussion and Analysis 
of Financial Condition and Results of Operations" of the 1998 
Annual Report to Shareholders, which is incorporated by reference.

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        $ 5,525    $ 5,127   $ 4,524   $ 4,201   $ 4,539
   Operating income                 $   639    $   939   $   927   $   886   $   867
   Net income                       $   294    $   432   $   427   $   401   $   296

Balance Sheet Data:
   Total assets                     $10,456    $10,756   $ 9,762   $ 9,837   $ 9,931
   Long-term debt                   $ 2,795    $ 3,175   $ 2,704   $ 2,721   $ 2,889
   Short-term debt (a)              $   373    $   624   $   481   $   485   $   645
   Shareholders' equity             $ 2,913    $ 2,959   $ 2,930   $ 2,815   $ 2,684

Per Share Data
   Net income per common share:
         Basic                      $  1.24    $  1.83   $  1.77   $  1.67   $  1.23
         Diluted                    $  1.24    $  1.82   $  1.77   $  1.67   $  1.23
   Dividends declared
     Per common share               $  1.56    $  1.27   $  1.24   $  1.22   $  1.16
   Book value per common share      $ 12.29    $ 12.56   $ 12.21   $ 11.70   $ 11.18


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

This data should be read in conjunction with the Consolidated Financial Statements 
and notes to Consolidated Financial Statements contained in the 1998 Annual Report 
to Shareholders, which is incorporated by reference.





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

The information required by Item 7 is incorporated by reference 
from pages 21 through 36 of the 1998 Annual Report to Shareholders.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information required by Item 7A is incorporated by reference 
from pages 34 through 35 and from Note 10 of the notes to 
Consolidated Financial Statements of the 1998 Annual Report to 
Shareholders.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required by Item 8 is incorporated by reference 
from pages 39 through 71 of the 1998 Annual Report to Shareholders. 
See Item 14 for a listing of financial statements included in the 
1998 Annual Report to Shareholders.

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

None.

                             PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information required on Identification of Directors is 
incorporated by reference from "Election of Directors" in the Proxy 
Statement prepared for the May 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 
Proxy 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 Proxy 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
                                                   Annual Report*

Statement of Management Responsibility for
  Consolidated Financial Statements. . . . . . . . . . . 38

Independent Auditors' Report . . . . . . . . . . . . . . 38

Statements of Consolidated Income for the years
  ended December 31, 1998, 1997 and 1996 . . . . . . . . 39

Consolidated Balance Sheets at December 31, 
  1998 and 1997. . . . . . . . . . . . . . . . . . . . . 40

Statements of Consolidated Cash Flows for the
  years ended December 31, 1998, 1997 and 1996 . . . . . 42

Statements of Consolidated Changes in
  Shareholders' Equity for the years ended
  December 31, 1998, 1997 and 1996 . . . . . . . . . . . 44

Notes to Consolidated Financial Statements . . . . . . . 45

Quarterly Financial Data (Unaudited) . . . . . . . . . . 71

*Incorporated by reference from the indicated pages of the 1998
Annual Report to Shareholders.

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. . . . . . . . . . . . . . . . . . 27
Schedule I--Condensed Financial Information of Parent. . 28

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 of the 1998 Annual Report to 
Shareholders.



3. Exhibits

See Exhibit Index on page 31 of this report.

(b) Reports on Form 8-K

The following reports on Form 8-K were filed after September 30, 
1998:

A Current Report on Form 8-K filed November 4, 1998 discussed the 
defeat of the Voter Initiative which sought to amend or repeal 
California electric industry restructuring legislation in various 
respects and announced the date of the 1999 Annual Meeting of 
Shareholders.

A Current Report on Form 8-K filed December 16, 1998 announced the 
execution of contracts for the sale of SDG&E's fossil-fueled power 
plants.

A Current Report on Form 8-K filed February 23, 1999 announced the 
agreement entered into by Sempra Energy and KN Energy, Inc. to 
merge the two companies.




INDEPENDENT AUDITORS' CONSENT AND REPORT ON SCHEDULE

To the Board of Directors and Shareholders of Sempra Energy:

We consent to the incorporation by reference in Registration 
Statement Number 333-51309 on Form S-3 and Registration Statement 
Number 333-56161 on Form S-8 of Sempra Energy of our report dated 
January 27, 1999, except for Note 16 as to which the date is 
February 22, 1999, incorporated by reference in the Annual Report 
on Form 10-K of Sempra Energy 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 Sempra Energy, listed in Item 14. This financial 
statement schedule is the responsibility of the Company's 
management. Our responsibility is to express an opinion based on 
our audits. In our opinion, such financial statement schedule, 
when considered in relation to the basic financial statements 
taken as a whole, presents fairly in all material respects the 
information set forth therein.


DELOITTE & TOUCHE LLP
San Diego, California
March 9, 1999





Schedule I -- CONDENSED FINANCIAL INFORMATION OF PARENT

SEMPRA ENERGY
Schedule 1
Condensed Financial Information of Parent


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

For the year ended December 31                       1998            
                                                  ----------      

Operating revenues and other income               $        -     
Operating expenses, interest and income taxes             10     
                                                  ----------     
Loss before subsidiary earnings                          (10)           
Subsidiary earnings                                      304     
                                                  ----------     
Earnings applicable to common shares              $      294      
                                                  ==========      
Average common shares outstanding (basic)            236,423      
                                                  ----------      
Average common shares outstanding (diluted)          237,124      
                                                  ----------      
Earnings per common share (basic)                 $     1.24      
                                                  ----------      
Earnings per common share (diluted)               $     1.24      
                                                  ==========      


                        Condensed Balance Sheet
                         (Dollars in millions)

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

Assets:
   Cash and temporary investments                 $       67        
   Dividends receivable                                  100      
   Other current assets                                  174      
                                                  ----------      
     Total current assets                                341        
Investments in subsidiaries                            2,820        
Deferred charges and other assets                        106       
                                                  ----------      
     Total Assets                                 $    3,267      
                                                  ==========      

Liabilities and Shareholders' Equity:
   Dividends payable                              $       93      
   Other current liabilities                             221      
                                                  ----------      
     Total current liabilities                           314      
Long-term liabilities                                     40      
Common equity                                          2,913      
                                                  ----------      
     Total Liabilities and Shareholders' Equity   $    3,267      
                                                  ==========      




SEMPRA ENERGY
Schedule 1 (continued)
Condensed Financial Information of Parent


                   Condensed Statement of Cash Flows
                       (Dollars in millions)

For the year ended December 31                    1998     
                                                ---------   

Cash flows from operating activities            $      71
                                                ---------
Sale of common stock                                    4
Dividends paid                                        (94)
                                                ---------
Cash flows from financing activities                  (90)
                                                ---------
Expenditures for property, plant and equipment        (44)
Dividends received from subsidiaries                  130
                                                ---------
Cash flows from investing activities                   86
                                                ---------
Net cash flow                                          67
Cash and temporary investments, 
   beginning of year                                   --
                                                ---------
Cash and temporary investments, end of year     $      67
                                                =========

Non cash dividends received from subsidiaries   $     597
                                                =========






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

                              SEMPRA ENERGY

                          By: 
                                /s/ 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
Vice Chairman, 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

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

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

Exhibit 1 -- Underwriting Agreements

Enova Corporation and San Diego Gas & Electric Company (SDG&E)
- --------------------------------------------------------------

1.01 Underwriting Agreement dated December 4, 1997 (Incorporated by 
     reference from Form 8-K filed by SDG&E Funding LLC on 
     December 23, 1997 (Exhibit 1.1)).

Exhibit 2 -- Plan of Acquisition, reorganization, arrangement, 
             liquidation, or succession

Sempra Energy
- -------------
2.01 Agreement and Plan of Merger (the "Merger Agreement"), dated as of 
     February 20, 1999, among the Company, Cardinal Acquisition Corp., a 
     California corporation, and KN Energy, Inc., a Kansas corporation ("KN"). 
     (Incorporated by reference from Form 8-K filed by Sempra Energy 
     filed on February 23, 1999.)

Exhibit 3 -- Bylaws and Articles of Incorporation

Bylaws

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

Articles of Incorporation

Sempra Energy
- -------------

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

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

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

Enova Corporation and San Diego Gas & Electric Company (SDG&E)
- --------------------------------------------------------------

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

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

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

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

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

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

Pacific Enterprises
- -------------------

4.07  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).

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

4.09  First Mortgage Indenture of Southern California Gas Company to American
      Trust Company dated as of October 1, 1940 (Registration Statement No.
      2-4504 filed by Southern California Gas Company on September 16, 1940;
      Exhibit B-4).
 
4.10  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).

4.11  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).
 
4.12  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).
 
4.13  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).

4.14  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).

4.15  Supplemental Indenture of Southern California Gas Company to Wells Fargo
      Bank, National Association dated as of September 15, 1981 (Pacific
      Enterprises 1981 Form 10-K; Exhibit 4.25).
 
4.16  Supplemental Indenture of Southern California Gas Company to
      Manufacturers Hanover Trust Company of California, successor to Wells
      Fargo Bank, National Association, and Crocker National Bank as
      Successor Trustee dated as of May 18, 1984 (Southern California Gas
      Company 1984 Form 10-K; Exhibit 4.29).
 
4.17  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).
 
4.18  Supplemental Indenture of Southern California Gas Company to First
      Trust of California, National Association, successor to Bankers Trust
      Company of California, N.A. dated as of August 15, 1992 (Registration
      Statement No. 33-50826 filed by Southern California Gas Company on
      August 13, 1992; Exhibit 4.37).
 

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

Sempra Energy
- -------------

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

10.02  Amendment to Employment Agreement effective December 1, 1998. 
       (Employment contract dated as of October 12, 1996 between
       Mineral Energy Company and Richard D. Farman (Enova 8-K filed 
       October 15, 1996, Exhibit 10.3)). 

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

10.04  Amendment to Employment Agreement effective December 1, 1998.
       (Employment contract, dated as of October 12, 1996 between
       Mineral Energy Company and Warren I. Mitchell (Enova 8-K filed
       October 15, 1996, Exhibit 10.5)).

Enova Corporation and San Diego Gas & Electric Company (SDG&E)
- --------------------------------------------------------------

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

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

Pacific Enterprises
- --------------------
10.07  Form of Indemnification Agreement between Pacific Enterprises
       and each of its directors and officers (Pacific Enterprises 1992
       Form 10-K Exhibit 10.07).
 
10.08  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).

Compensation

Sempra Energy
- -------------
10.09  Sempra Energy Supplemental Executive Retirement Plan as amended
       and restated effective July 1, 1998 

10.10  Sempra Energy Deferred Compensation Agreement for Directors 
       effective June 1, 1998.

10.11  Sempra Energy Executive Incentive Plan effective June 1, 1998

10.12  Sempra Energy Executive Deferred Compensation Agreement 
       effective June 1, 1998

10.13  Sempra Energy Retirement Plan for Directors effective June 1, 1998

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)).

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

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)).

Enova Corporation and San Diego Gas & Electric (SDG&E)
- ------------------------------------------------------

10.19  Form of Amendment to San Diego Gas & Electric Company
       Deferred Compensation Agreements for Officers #1 and #3 (1996
       Form 10-K Exhibit 10.6).

10.20  Form of Enova Corporation 1998 Deferred Compensation Agreement
       for Officers #1 (1998 compensation, 1998 bonus) (1997 Enova
       Form 10-K Exhibit 10.15).

10.21  Form of Enova Corporation 1997 Deferred Compensation Agreement
       for Officers #1 (1997 compensation, 1998 bonus) (1996 Form 10-K
       Exhibit 10.7).

10.22  Form of San Diego Gas & Electric Company Deferred
       Compensation Agreement for Officers #1 (1996 compensation,
       1997 bonus)(1995 SDG&E Form 10-K Exhibit 10.1).

10.23  Form of Enova Corporation 1998 Deferred Compensation
       Agreement for Officers #3. (1997 Enova Form 10-K 
       Exhibit 10.12).

10.24  Form of Enova Corporation 1997 Deferred Compensation 
       Agreement for Officers #3 (1997 compensation, 1998 bonus)(1996
       Form 10-K Exhibit 10.10).

10.25  Form of San Diego Gas & Electric Company Deferred
       Compensation Agreement for Officers #3 (1996 compensation,
       1997 bonus)(1995 SDG&E Form 10-K Exhibit 10.3).

10.26  Form of Enova Corporation 1998 Deferred Compensation
       Agreement for Nonemployee Directors. (1997 Enova
       Form 10-K Exhibit 10.16).

10.27  Form of Enova Corporation 1997 Deferred Compensation
       Agreement for Nonemployee Directors (1996 Form 10-K Exhibit
       10.13).

10.28  Form of San Diego Gas & Electric Company Deferred
       Compensation Agreement for Nonemployee Directors (1996
       compensation)(1995 SDG&E Form 10-K Exhibit 10.5).

10.29  Form of Enova Corporation 1986 Long-Term Incentive Plan
       1997 restricted stock award agreement. (1997 Enova
       Form 10-K Exhibit 10.18).
 
10.30  Form of Enova Corporation 1986 Long-Term Incentive Plan
       1996 restricted stock award agreement (1996 Form 10-K
       Exhibit 10.16).

10.31  Form of San Diego Gas & Electric Company 1986 Long-Term
       Incentive Plan 1995 restricted stock award agreement
       (1995 SDG&E Form 10-K Exhibit 10.7).

10.32  Form of San Diego Gas & Electric Company 1986 Long-Term
       Incentive Plan Special 1995 restricted stock award
       agreement (1995 SDG&E Form 10-K Exhibit 10.8).

10.33  Form of San Diego Gas & Electric Company 1986 Long-Term
       Incentive Plan 1994 restricted stock award agreement two-
       year vesting (1995 SDG&E Form 10-K Exhibit 10.9).

10.34  Form of San Diego Gas & Electric Company 1986 Long-Term
       Incentive Plan 1994 restricted stock award agreement
       (1994 SDG&E Form 10-K Exhibit 10.4).

10.35  Amended 1986 Long-Term Incentive Plan, amended and restated
       effective April 25, 1995 (SDG&E's Amendment No. 2 to 
       Form S-4 filed February 28, 1995).

10.36  Amended 1986 Long-Term Incentive Plan, Restatement as of
       October 25, 1993 (1993 SDG&E Form 10-K Exhibit 10.6).

10.37  San Diego Gas & Electric Company Severance Plan effective
       October 22, 1996 (1996 Form 10-K Exhibit 10.24).

10.38  San Diego Gas & Electric Company Severance Plan effective
       on the date of the Enova Corporation -- Pacific Enterprises
       business combination (1996 Form 10-K Exhibit 10.25).

10.39  San Diego Gas & Electric Company Retirement Plan for
       Directors, restated as of October 24, 1994 (1994 SDG&E 
       Form 10-K Exhibit 10.5).

10.40  Executive Incentive Plan dated April 23, 1985 (1991 SDG&E
       Form 10-K Exhibit 10.39).

10.41  Employment agreement between San Diego Gas & Electric
       Company and Thomas A. Page, dated June 15, 1988 (1988 SDG&E 
       Form 10-K Exhibit 10E).

10.42  Supplemental Pension Agreement with Thomas A. Page, dated as
       of April 3, 1978 (1988 SDG&E Form 10-K Exhibit 10V).

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

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

10.44  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).
 
10.45  Pacific Enterprises Supplemental Medical Reimbursement Plan for Senior
       Officers (Pacific Lighting Corporation 1980 Form 10-K
       Exhibit 10.24).
 
10.46  Pacific Enterprises Financial Services Program for Senior Officers
       (Pacific Lighting Corporation 1980 Form 10-K Exhibit 10.25).
 
10.47  Pacific Enterprises Supplemental Retirement and Survivor Plan 
       (Pacific Lighting Corporation 1984 Form 10-K Exhibit 10.36).

10.48  Pacific Enterprises Stock Payment
       Plan (Pacific Lighting Corporation 1984 Form 10-K Exhibit 10.37).
 
10.49  Pacific Enterprises Pension Restoration
       Plan (Pacific Lighting Corporation 1980 Form 10-K Exhibit 10.28).
 
10.50  Southern California Gas Company Pension Restoration Plan For 
       Certain Management Employees (Pacific Lighting Corporation 1980 
       Form 10-K Exhibit 10.29).
 
10.51  Pacific Enterprises Executive Incentive
       Plan (Pacific Enterprises 1987 Form 10-K; Exhibit 10.13).
 
10.52  Pacific Enterprises Deferred Compensation
       Plan for Key Management Employees (Pacific Lighting 
       Corporation 1985 Form 10-K Exhibit 10.41).
 
10.53  Pacific Enterprises Employee Stock Ownership Plan and Trust Agreement
       as amended effective October 1, 1992.
       (Pacific Enterprises 1992 Form 10-K Exhibit 10.18).
 
10.54  Pacific Enterprises Stock Incentive Plan
       (Registration Statement No. 33-21908 filed by Pacific Enterprises on
       May 17, 1988 Exhibit 4.01).
  
10.55  Pacific Enterprises Retirement Plan for
       Directors (Pacific Enterprises 1992 Form 10-K Exhibit 10.20).

10.56  Pacific Enterprises Director's Deferred
       Compensation Plan (Pacific Enterprises 1992 Form 10-K; Exhibit 10.21).
  
10.57  Amended and Restated Pacific Enterprises Employee
       Stock Option Plan (as of March 4, 1997)
       (Pacific Enterprises 1996 Form 10-K Exhibit 10.17).
  
10.58  Form of Severance Agreement
       (Pacific Enterprises 1996 Form 10-K Exhibit 10.18).
  
10.59  Form of Incentive Bonus Agreement
       (Pacific Enterprises 1996 Form 10-K Exhibit 10.19).

Southern California Gas Company
- -------------------------------

10.60  Southern California Gas Company Retirement Savings Plan, as amended and
       restated as of August 30, 1988 (Registration Statement No. 33-6357 
       filed by Pacific Enterprises on December 30, 1988; Exhibit 28.02).
 
10.61  Southern California Gas Company Statement of Life Insurance, Disability
       Benefit and Pension Plans, as amended and restated as of January 1,
       1985 (Southern California Gas Company 1984 Form 10-K; Exhibit 10.27).

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

Financing

Enova Corporation and San Diego Gas & Electric (SDG&E)
- ------------------------------------------------------

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

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


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

10.66  Loan agreement with City of San Diego in connection with 
       the issuance of $16.7 million of Industrial Development 
       Bonds, dated as of June 1, 1995 (June 30, 1995 SDG&E 
       Form 10-Q Exhibit 10.2).

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

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

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

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

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

10.72  Loan agreement with the City of San Diego in connection with
       the issuance of $25 million of Industrial Development
       Bonds, dated as of September 1, 1987 (1992 SDG&E Form 10-K 
       Exhibit 10.6).

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

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

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



Natural Gas Commodity, Transportation and Storage

Enova Corporation and San Diego Gas & Electric (SDG&E)
- ------------------------------------------------------

10.76  Third Amending Agreement, dated November 1, 1997 between
       Husky Oil Operations Limited and San Diego Gas & Electric
       Company.(1997 Enova Corporation Form 10-K Exhibit 10.50).

10.77  Second Amending Agreement, dated January 1, 1997 between
       Husky Oil Operations Limited and San Diego Gas & Electric
       Company. (1997 Enova Corporation Form 10-K Exhibit 10.51).

10.78  Amending Agreement dated November 1, 1994 between Husky
       Oil Operations Limited and San Diego Gas & Electric Company.
       (1997 Enova Corporation Form 10-K Exhibit 10.52).

10.79  Gas Purchase Agreement, dated March 12, 1991 between Husky
       Oil Operations Limited and San Diego Gas & Electric Company
       (1991 SDG&E Form 10-K Exhibit 10.1).

10.80  Gas Purchase Agreement, dated March 12, 1991 between
       Canadian Hunter Marketing Limited and San Diego Gas &
       Electric Company (1991 SDG&E Form 10-K Exhibit 10.2).

10.81  Gas Purchase Agreement, dated March 12, 1991 between Bow
       Valley Industries Limited and San Diego Gas & Electric
       Company (1991 SDG&E Form 10-K Exhibit 10.3).

10.82  Gas Purchase Agreement, dated March 12, 1991 between Summit
       Resources Limited and San Diego Gas & Electric Company (1991
       SDG&E Form 10-K Exhibit 10.4).

10.83  Service Agreement Applicable to Firm Transportation Service
       under Rate Schedule FS-1, dated May 31, 1991 between Alberta
       Natural Gas Company Ltd. and San Diego Gas & Electric
       Company (1991 SDG&E Form 10-K Exhibit 10.5).

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

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

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



Nuclear 
 
Enova Corporation and San Diego Gas & Electric (SDG&E)
- ------------------------------------------------------

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

10.88  Fuel Lease dated as of September 8, 1983 between SONGS Fuel
       Company, as Lessor and San Diego Gas & Electric Company, as
       Lessee, and Amendment No. 1 to Fuel Lease, dated September
       14, 1984 and Amendment No. 2 to Fuel Lease, dated March 2,
       1987 (1992 SDG&E Form 10-K Exhibit 10.11).

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

10.90  Amendment No. 1 to the Qualified CPUC Decommissioning Master
       Trust Agreement dated September 22, 1994 (see Exhibit 10.89
       herein)(1994 SDG&E Form 10-K Exhibit 10.56).

10.91  Second Amendment to the San Diego Gas & Electric Company
       Nuclear Facilities Qualified CPUC Decommissioning Master
       Trust Agreement for San Onofre Nuclear Generating Station
       (see Exhibit 10.89 herein)(1994 SDG&E Form 10-K Exhibit 10.57).

10.92  Third Amendment to the San Diego Gas & Electric Company
       Nuclear Facilities Qualified CPUC Decommissioning Master
       Trust Agreement for San Onofre Nuclear Generating Station
       (see Exhibit 10.89 herein)(1996 Form 10-K Exhibit 10.59).

10.93  Fourth Amendment to the San Diego Gas & Electric Company
       Nuclear Facilities Qualified CPUC Decommissioning Master
       Trust Agreement for San Onofre Nuclear Generating Station
       (see Exhibit 10.89 herein)(1996 Form 10-K Exhibit 10.60).

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

10.95  First Amendment to the San Diego Gas & Electric Company
       Nuclear Facilities Non-Qualified CPUC Decommissioning Master
       Trust Agreement for San Onofre Nuclear Generating Station
       (see Exhibit 10.94 herein)(1996 Form 10-K Exhibit 10.62).

10.96  Second Amendment to the San Diego Gas & Electric Company
       Nuclear Facilities Non-Qualified CPUC Decommissioning Master
       Trust Agreement for San Onofre Nuclear Generating Station
       (see Exhibit 10.94 herein)(1996 Form 10-K Exhibit 10.63).

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

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

Purchased Power

10.99  Public Service Company of New Mexico and San Diego Gas &
       Electric Company 1988-2001 100 mw System Power Agreement
       dated November 4, 1985 and Letter of Agreement dated April
       28, 1986, June 4, 1986 and June 18, 1986 (1988 SDG&E 
       Form 10-K Exhibit 10H).

10.100 San Diego Gas & Electric Company and Portland General
       Electric Company Long-Term Power Sale and Transmission
       Service agreements dated November 5, 1985 (1988 SDG&E Form
       10-K Exhibit 10I).

Other

10.101 U. S. Navy contract for electric service, Contract
       N62474-70-C-1200-P00414, dated September 29, 1988 (1988 SDG&E 
       Form 10-K Exhibit 10C).

10.102 Lease agreement dated as of March 25, 1992 with American
       National Insurance Company as lessor of an office complex at
       Century Park (1994 SDG&E Form 10-K Exhibit 10.70).

10.103 Lease agreement dated as of June 15, 1978 with Lloyds Bank
       California, as owner-trustee and lessor - Exhibit B to
       financing agreement of SDG&E's Encina Unit 5 equipment trust
       (1988 SDG&E Form 10-K Exhibit 10W).

10.104 Amendment to Lease agreement dated as of July 1, 1993 with
       Sanwa Bank California, as owner-trustee and lessor - Exhibit
       B to secured loan agreement of SDG&E's Encina Unit 5
       equipment trust (See Exhibit 10.103 herein)(1994 SDG&E Form
       10-K Exhibit 10.72).

10.105 Lease agreement dated as of July 14, 1975 with New England
       Mutual Life Insurance Company, as lessor (1991 SDG&E Form 10-K
       Exhibit 10.42). 

10.106 Assignment of Lease agreement dated as of November 19, 1993
       to Shapery Developers as lessor by New England Mutual
       Life Insurance Company (See Exhibit 10.105 herein)(1994 SDG&E 
       Form 10-K Exhibit 10.74).

Exhibit 11 -- Statement re: Computation Of Per Share Earnings

11.01  Sempra Energy Computation of Earnings per Share (see Consolidated 
       Statements of Income and Note 12 of the notes to Consolidated Financial 
       Statements contained in Exhibit 13.01).

Exhibit 12 -- Statement re: Computation Of Ratios

12.01  Computation of Ratio of Earnings to Combined Fixed Charges
       and Preferred Stock Dividends for the years ended December
       31, 1998, 1997, 1996, 1995 and 1994.

Exhibit 13 -- Annual Report to Security Holders

13.01  Sempra Energy 1998 Annual Report to Shareholders. (Such report, except  
       for the portions thereof which are expressly incorporated by reference 
       in this Annual Report, is furnished for the information of the 
       Securities and Exchange Commission and is not to be deemed "filed" as 
       part of this Annual Report).

Exhibit 21 -- Subsidiaries 
       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 Exhibit 13.01

Exhibit 23 -- Independent Auditors' Consent, page 27.

Exhibit 27 -- Financial Data Schedules 

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





GLOSSARY


AB 1890                 Assembly Bill 1890 - California's electric 
                        restructuring law

AFUDC                   Allowance for Funds Used During 
                        Construction

APCD                    Air Pollution Control District

BCAP                    Biennial Cost Allocation Proceeding

Bcf                     One Billion Cubic Feet (of natural gas) 

BRPU                    Biennial Resource Plan Update

BTU                     British Thermal Unit

CEC                     California Energy Commission

CFE                     Comision Federal de Electricidad

CPUC                    California Public Utilities Commission

CTC                     Competition Transition Charge

DOE                     Department of Energy

DGN                     Distribuidora de Gas Natural

DTSC                    Department of Toxic Substances Control

Edison                  Southern California Edison Company

EMF                     Electric and Magnetic Fields

Enova                   Enova Corporation and its wholly owned 
                        subsidiaries

EOR                     Enhanced Oil Recovery

EPS                     Earnings Per Share

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

ISO                     Independent System Operator

IT                      Information Technology

Kv                      Kilovolt

Kwhr                    Kilowatt Hour

LG&E                    Louisville Gas & Electric Power Marketing

Mcf                     Thousand Cubic Feet (of natural gas)

Mmcfd                   Million Cubic Feet (of natural gas) per day

Mw                      Megawatt

NPDES                   National Pollutant Discharge Elimination 
                        System

NRC                     Nuclear Regulatory Commission

ORA                     Office of Ratepayer Advocates

OTC                     Over The Counter

PBR                     Performance-Based Ratemaking

PCB                     Polychlorinated Biphenyl

PE                      Pacific Enterprises

PG&E                    Pacific Gas and Electric Company

PGE                     Portland General Electric Company

PNM                     Public Service Company of New Mexico

PX                      Power Exchange

QF                      Qualifying Facility

ROE                     Return on Equity

ROR                     Rate of Return

RWQCB                   Regional Water Quality Control Board

SDG&E                   San Diego Gas & Electric Company	

SEC                     Securities and Exchange Commission

SEF                     Sempra Energy Financial

SEI                     Sempra Energy International

SER                     Sempra Energy Resources

SES                     Sempra Energy Solutions

SET                     Sempra Energy Trading

SEUV                    Sempra Energy Utility Ventures

SFAS                    Statement of Financial Accounting Standards

SoCalGas                Southern California Gas Company

SONGS                   San Onofre Nuclear Generating Station

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

SWRCB                   State Water Resources Control Board

UEG                     Utility electric generation

VaR                     Value at Risk

WSPP                    Western Systems Power Pool





40




                                                    EXHIBIT 13.01


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 information 
about the capital resources, liquidity and financial performance of 
Sempra Energy and its subsidiaries (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 
included in this Annual Report.
     The company is a California-based Fortune 500 energy-services 
company whose principal subsidiaries are San Diego Gas & Electric 
(SDG&E), which provides electric and natural gas service to San 
Diego County and southern Orange County, and 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. Together, the 
two utilities serve approximately 7 million meters. Sempra Energy 
Trading is engaged in the wholesale trading and marketing of 
natural gas, power and petroleum. 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 Financial invests in limited 
partnerships representing 1,250 affordable-housing properties 
throughout the United States. 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, nonutility electric generation and other 
energy-related products and services.

BUSINESS COMBINATIONS

Sempra Energy was formed to serve as a holding company for Pacific 
Enterprises (the parent corporation of the Southern California Gas 
Company) and Enova Corporation (the parent corporation of San Diego 
Gas & Electric Company) in connection with a business combination 
that became effective on June 26, 1998 (the PE/Enova Business 
Combination). In January 1998, PE and Enova jointly acquired 
CES/Way International, Inc. Expenses incurred in connection with 
these business combinations are $85 million, aftertax, and $20 
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 PE and Enova became the holders of the 
company's common stock. PE's common shareholders received 1.5038 
shares of the company's common stock for each share of PE common 
stock, and Enova's common shareholders received one share of the 
company's common stock for each share of Enova common stock. The 
preferred stock of PE 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 the company gave effect to the combination using the 
pooling-of-interests method and are preserved as if the companies 
were combined during all periods included therein.

CAPITAL RESOURCES AND LIQUIDITY

The company's utility operations continue to be a major source of 
liquidity. In addition, working capital requirements are met 
primarily through the issuance of short- and long-term debt. Cash 
requirements primarily include capital investments in the utility 
operations. Nonutility cash requirements include investments in 
Sempra Energy Resources, Sempra Energy Utility Ventures, 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 consolidated cash flows:
- ------------------------------------------------------------
SOURCES AND (USES) OF CASH
Year Ended December 31
(Dollars in millions)               1998     1997     1996
- ------------------------------------------------------------
Operating Activities               $1,323    $918    $1,164
                                   -------------------------
Investing Activities: 
   Capital expenditures	              (438)   (397)     (413)
   Acquisitions of subsidiaries      (191)   (206)      (50)
   Other                              (50)      1       (51)
                                   -------------------------
      Total Investing Activities     (679)   (602)     (514)
                                   -------------------------
Financing Activities:
   Common stock dividends            (325)   (301)     (300)
   Sale of common stock                34      17         8
   Repurchase of common stock          (1)   (122)      (24)
   Redemption of preferred stock      (75)      _      (225)
   Long-term debt-net                (356)    382      (155)
   Short-term debt-net               (311)     92        29
                                   -------------------------
      Total Financing Activities   (1,034)     68      (667)
                                   -------------------------
Increase (decrease) in cash 
   and cash equivalents             $(390)   $384      $(17)
- ------------------------------------------------------------

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, which resulted in overcollected 
regulatory balancing accounts at year-end 1998. This increase was 
partially offset by expenses incurred in connection with the 
business combinations. The fluctuation in cash flows from 
operations was also affected by electric-industry restructuring, 
including the acceleration of depreciation of electric-generating 
assets, offset by recovery of stranded costs via the competition 
transition charge and the 10-percent rate reduction reflected in 
customers' bills in 1998. 
     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. The 
cash flow from electric operations for 1997 was consistent with 
results from 1996.

CASH FLOWS FROM INVESTING ACTIVITIES

Cash flows from investing activities primarily represent capital 
expenditures and investments in new businesses.

Capital Expenditures 

Capital expenditures were $41 million higher in 1998 than in 1997 
due to greater capital spending at the company's corporate center 
related to facility improvements and equipment purchases, and at 
SDG&E related to industry-restructuring needs and improvements to 
the electric distribution system, partially offset by lower capital 
spending at SoCalGas.
     Capital expenditures were $16 million lower in 1997 than in 
1996 due to changes in the scope and timing of several major 
capital projects primarily related to information systems. SoCalGas 
had lower capital spending related to the customer information 
system's being completed in early 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. SDG&E's capital expenditures were lower due to changes 
in scope and timing of several major capital projects.
     At SDG&E, payments to the nuclear-decommissioning trusts are 
expected to continue until San Onofre Nuclear Generating Station 
(SONGS) is decommissioned, which is not expected to occur before 
2013. Unit 1, although permanently shut down in 1992, was scheduled 
to be decommissioned concurrently with Units 2 and 3. However, 
SDG&E and the other owners of SONGS have requested that the CPUC 
grant authority to begin decommisioning Unit 1 on January 1, 2000. 
See Note 6 of the notes to the Consolidated Financial Statements 
for additional information.
     The decision of the CPUC approving the PE/Enova Business 
Combination required, among other things, that SDG&E divest itself 
of all its fossil fueled generation facilities. In December 1998, 
SDG&E entered into agreements to accomplish that. Completion is 
pending regulatory approvals and is expected during the first half 
of 1999. See "Electric-Generation Assets" below for further 
discussion of the divestiture. Anticipated proceeds from these 
plant assets, net of the assets' book value, the costs of the sales 
and certain environmental cleanup costs, will be applied for 
accounting purposes directly to the recovery of SDG&E's other 
transition costs. On a cash basis, the proceeds will be available 
for general corporate purposes. However, the divestiture of the 
facilities will eventually lead to reduced cash flow from 
operations. 
     Capital expenditures at the utilities are estimated to be $419 
million in 1999. They will be financed primarily by internally 
generated funds and will largely represent investment in utility 
operations. The level of capital expenditures in the next few years 
will depend heavily on the impact of electric-industry 
restructuring and the timing and extent of expenditures to comply 
with environmental requirements.

Investments 

In December 1997, PE and Enova jointly acquired Sempra Energy 
Trading for $225 million. In July 1998, Sempra Energy Trading 
purchased a subsidiary of Consolidated Natural Gas, a wholesale 
trading and commercial marketing operation, for $36 million to 
expand its operation in the eastern United States.
     In December 1997, Sempra Energy Resources and Reliant Energy 
Power Generation formed El Dorado Energy, a joint venture to build, 
own and operate a natural gas power plant in Boulder City, Nevada. 
Sempra Energy Resources invested $19.7 million and $2.3 million in 
El Dorado Energy in 1998 and 1997, respectively. Total cost of the 
project is projected to be $263 million. In October 1998, El Dorado 
Energy obtained a 15-year, $158-million, senior secured credit 
facility to finance the project. This financing represents 
approximately 60 percent of the estimated total project costs.
     In September 1997, Sempra Energy Utility Ventures formed a 
joint venture with Bangor Hydro to build, own and operate a $40 
million natural gas distribution system in Bangor, Maine. The 
project is under construction and is expected to be operational in 
the fourth quarter of 1999. In December 1997, Sempra Energy Utility 
Ventures entered into a partnership 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, Sempra Energy 
Utilities Ventures acquired 100 percent ownership of the system.
     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 1998. CES/Way provides energy-
efficiency services, including energy audits, engineering design, 
project management, construction, financing and contract 
maintenance.
     In March 1998, the company increased its existing 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 Sempra Energy's level of investments in the 
next few years will depend primarily on the activities of its 
subsidiaries other than SoCalGas and SDG&E.

CASH FLOWS FROM FINANCING ACTIVITIES

Net cash used in financing activities increased in 1998 due to 
greater short- and long-term debt repayments and the redemption of 
preferred stock in 1998, and the issuance of rate-reduction bonds 
in 1997, partially offset by the repurchase of common stock in 
1997. 
     Net cash was provided by financing activities in 1997 compared 
to net cash being used in 1996 due to the issuance of rate 
reduction bonds and lower repayments of long-term debt in 1997, and 
the redemption of preferred stock in 1996, partially offset by the 
redemption of common stock in 1997.

Long-Term Debt 

In December 1997, $658 million of Rate Reduction Bonds were issued 
on SDG&E's behalf at an average interest rate of 6.26 percent. A 
portion of the bond proceeds was used to retire variable-rate, 
taxable Industrial Development Bonds (IDBs). Additional information 
concerning the Rate Reduction Bonds is provided below under 
"Electric Industry Restructuring." In 1998, cash was used for the 
repayment of $247 million of first-mortgage bonds, and $66 million 
of rate-reduction bonds. Short-term debt repayments included 
repayment of $94 million of debt issued to finance SoCalGas' 
Comprehensive Settlement as discussed in Note 14 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 $252 million of SoCalGas' 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.
     SDG&E has $83 million of temporary investments that will be 
maintained into the future to offset, for regulatory purposes, a 
like amount of long-term debt. The specific debt series being 
offset consists of variable-rate IDBs. The CPUC has approved 
specific ratemaking treatment which allows SDG&E to offset IDBs as 
long as there is at least a like amount of temporary investments. 
If and when SDG&E requires all or a portion of the $83 million of 
IDBs to meet future needs for long-term debt, such as to finance 
new construction, the amount of investments which are being 
maintained will be reduced below $83 million and the level of IDBs 
being offset will be reduced by the same amount.

Stock Purchases and Redemptions 

The company, through PE and Enova, repurchased $1 million, $122 
million and $24 million of common stock in 1998, 1997 and 1996, 
respectively. The stock repurchase programs of PE and Enova were 
suspended as a result of the PE/Enova Business Combination. Sempra 
Energy does not have a stock-repurchase program. 
     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 stock amounted to $325 million in 1998, 
compared to approximately $300 million in 1997 and 1996. The 
increase in 1998 is the result of the company's paying dividends on 
its common stock at the rate previously paid by Enova, which, on an 
equivalent-share basis, is higher than the rate paid by PE.
     Dividends are paid quarterly to shareholders. The payment of 
future dividends and the amount thereof are within the discretion 
of the board of directors.

CAPITALIZATION

The debt to capitalization ratio was 50 percent at year-end 1998, 
below the 54 percent ratio in 1997. The decrease was primarily due 
to the repayment of debt. The debt to capitalization ratio 
increased to 54 percent in 1997 from 50 percent in 1996, primarily 
due to the issuance of SDG&E's Rate Reduction Bonds.



CASH AND CASH EQUIVALENTS

Cash and cash equivalents were $424 million at December 31, 1998. 
This cash is available for investment in energy-related domestic 
and international projects, and the retirement of debt and other 
corporate purposes.
     The company anticipates that cash required in 1999 for capital 
expenditures and dividend 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 
multiyear credit agreements that permit term borrowings of up to 
$995 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 $294 million, or $1.24 per share 
of common stock (diluted) in 1998, compared to net income of $432 
million, or $1.82 per share of common stock (diluted) in 1997.
     The decrease in net income is primarily due to the costs 
associated with the business combinations, and a lower base margin 
established at SoCalGas in its Performance Based Regulation 
decision (SoCalGas PBR Decision) which became effective on August 
1, 1997, as further described in Note 14 of the notes to 
Consolidated Financial Statements. Expenses related to the business 
combinations were $85 million ($0.36 per share) and $20 million 
($0.08 per share), aftertax, for 1998 and 1997, respectively.
     Also contributing to lower net income for 1998 were 
significant start-up costs at Sempra Energy Solutions and at Sempra 
Energy Trading as discussed under "Other Operations" below.
     For the fourth quarter, net income decreased compared to the 
prior fourth quarter due to PBR and Demand-Side Management awards 
in the 1997 quarter, electric seasonality effects compared to 1997, 
and the factors that affected the annual comparison. 
     Book value per share decreased to $12.29 from $12.56, due to 
common dividends' exceeding the decreased net income in 1998. 

1997 Compared to 1996 

Net income for 1997 increased to $432 million, or $1.82 per share 
of common stock (diluted), compared to net income of $427 million, 
or $1.77 per share (diluted), in 1996. The increase in net income 
per share is due primarily to the repurchases of common stock, 
which caused the weighted average number of shares of common stock 
outstanding to decrease 2 percent in 1997. The increase in net 
income is primarily due to increased net income from utility 
operations, partially offset by costs related to the PE/Enova 
Business Combination and the start-up of unregulated operations. 
     Book value per share increased to $12.56 from $12.21, due to 
net income's exceeding the combined effect of common dividends and 
the stock repurchases. 

UTILITY OPERATIONS

To understand the operations and financial results of SoCalGas and 
SDG&E, it is important to understand the ratemaking procedures that 
SoCalGas and SDG&E follow.
     SoCalGas and SDG&E are 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, SoCalGas and SDG&E have received approval 
from the CPUC for PBR.
     PBR replaces the general rate case (GRC) procedure and certain 
other regulatory proceedings. Under ratemaking procedures in effect 
prior to PBR, SoCalGas and SDG&E typically filed a GRC with the 
CPUC every three years. In a GRC, the CPUC establishes a base 
margin, which is the amount of revenue to be collected from 
customers to recover authorized operating expenses (other than the 
cost of fuel, natural gas and purchased power), 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 14 of the 
notes to Consolidated Financial Statements.
     In September 1996, California enacted a law restructuring 
California's electric-utility industry. The legislation adopted the 
December 1995 CPUC policy decision restructuring the industry to 
stimulate competition and reduce rates. Beginning on March 31, 
1998, customers were able to buy their electricity through the 
California Power Exchange (PX) that obtains power from qualifying 
facilities, nuclear units and, lastly, from the lowest-bidding 
suppliers. The PX serves as a wholesale power pool, allowing all 
energy producers to participate competitively.
     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 electric-industry and natural 
gas-industry restructuring below in "Electric-Industry 
Restructuring" and "Gas-Industry Restructuring" and in Note 14 of 
the notes to Consolidated Financial Statements.
     The table below summarizes the components of utility natural 
gas and electric volumes and revenues by customer class for 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                  304    $2,234            3       $11           307    $2,245
  Commercial and Industrial    102       571          329       277           431       848
  Utility Electric Generation*  57         9          139        66           196        75
  Wholesale                                            28         7            28         7
                      -----------------------------------------------------------------------
                               463    $2,814          499      $361           962     3,175
  Balancing accounts and other                                                         (403)
                                                                                    ---------
    Total                                                                            $2,772
- ---------------------------------------------------------------------------------------------
1997:
  Residential                  268    $1,957            3       $10           271    $1,967
  Commercial and Industrial    102       617          332       273           434       890
  Utility Electric Generation*  49        14          158        76           207        90
  Wholesale                                            18        12            18        12
                           -----------------------------------------------------------------------
                               419    $2,588          511      $371           930     2,959
  Balancing accounts and other                                                            5
                                                                                    ---------
    Total                                                                            $2,964
- ---------------------------------------------------------------------------------------------
1996:
  Residential                  264    $1,809            3       $10           267    $1,819
  Commercial and Industrial    104       573          314       257           418       830
  Utility Electric Generation*  43         9          139        70           182        79
  Wholesale                                            17        10            17        10
                           -----------------------------------------------------------------------
                               411    $2,391          473      $347           884     2,738
  Balancing accounts and other                                                          (28)
                                                                                                        ---------
    Total                                                                            $2,710
- ---------------------------------------------------------------------------------------------
* The portion representing SDG&E's sales for electric generation includes margin only.

ELECTRIC DISTRIBUTION
(Dollars in millions, volumes in millions of Kwhrs)
                                  1998                    1997                    1996
                      -----------------------------------------------------------------------
                            Volumes   Revenue      Volumes   Revenue       Volumes   Revenue
                      -----------------------------------------------------------------------
  Residential                6,282      $637        6,125      $684         5,936       $647
  Commercial                 6,821       643        6,940       680         6,467        625
  Industrial                 3,097       233        3,607       268         3,567        261
  Direct access                964        44           -         -             -          -
  Street and highway lighting   85         8           76         7            75          7
  Off-system sales             706        15        4,919       116           650         13
                      -----------------------------------------------------------------------
                            17,955     1,580       21,667     1,755        16,695      1,553
  Balancing and other                    285                     14                       38
                      -----------------------------------------------------------------------
     Total                  17,955    $1,865       21,667    $1,769        16,695     $1,591
                      -----------------------------------------------------------------------




1998 Compared to 1997  

Utility natural gas revenues decreased 6 percent in 1998 primarily 
due to the lower natural gas margin established in the SoCalGas PBR 
Decision, a decrease in the average cost of natural gas and a 
decrease in sales to utility electric-generation customers, 
partially offset by increased sales to residential customers due to 
colder weather in 1998.
     Electric revenues increased 5 percent in 1998 compared to 
1997, primarily due to the recovery of stranded costs via the 
competition transition charge (CTC), and to alternate costs 
incurred (including fuel and purchased power) due to the delay from 
January 1 to March 31, 1998, in the start-up of operations of the 
PX and Independent System Operator (ISO). These factors were 
partially offset by a decrease in retail revenue as a result of the 
10-percent small customer rate reduction, which became effective in 
January 1998, and by a decrease in sales to other utilities, due to 
the start-up of the PX. The 10-percent rate reduction and PX are 
described further under "Factors Influencing Future Performance" 
and in Note 14 of the notes to Consolidated Financial Statements. 
     Revenues from the ISO/PX reflect sales from the company's 
power plants and from long-term purchased-power contracts to the 
ISO/PX commencing April 1, 1998. 
     The company's cost of natural gas distributed decreased 18 
percent in 1998, largely due to a decrease in the average cost of 
natural gas purchased, partially offset by increases in sales 
volume.
     Purchased power decreased 34 percent in 1998 primarily as a 
result of ISO/PX purchases' replacing short-term energy sources 
commencing April 1, 1998. 
     Depreciation and amortization expense increased 54 percent in 
1998, primarily due to the recovery of stranded costs via the CTC. 
The earnings impact of the increase is offset by CTC revenue (see 
above).
     Operating expenses increased 16 percent in 1998, primarily due 
to the higher business-combination costs ($142 million in 1998, 
compared to $30 million in 1997) and additional operating expenses 
due to start-up operations in 1998, including the acquisitions of 
Sempra Energy Trading and CES/Way.

1997 Compared to 1996 

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. The increase was partially 
offset by an increase in customer purchases of natural gas directly 
from other suppliers.
     Utility electric revenues increased 11 percent in 1997, 
primarily due to an increase in sales for resale to other utilities 
and increased retail sales volume due to weather.
     Utility cost of natural gas distributed increased 22 percent 
in 1997, largely due to an increase in the average cost of natural 
gas purchased and increases in sales volume.
     Purchased power increased 42 percent in 1997, primarily due to 
increased volume, which resulted from lower nuclear-generation 
availability due to refuelings at SONGS and increased use of 
purchased power due to decreased purchased-power prices. 
     Operating expenses increased 15 percent in 1997, primarily due 
to the startup of unregulated operations, partially offset by lower 
utility operating expenses. The extent of this offset was lessened 
by reduced costs in 1996 from favorable litigation settlements.

FACTORS INFLUENCING FUTURE PERFORMANCE

Performance of the company in the near future will depend primarily 
on the results of SDG&E and SoCalGas. Because of the ratemaking and 
regulatory process, electric- and natural gas-industry 
restructuring, 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, the company 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 16 
of the notes to Consolidated Financial Statements for additional 
information.

Electric-Industry Restructuring  

As discussed above, in September 1996, California enacted a law 
restructuring California's electric-utility industry (AB 1890). 
Consumers now 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 PX that 
serves as a wholesale power pool allowing all energy producers to 
participate competitively. The local utility continues to provide 
distribution service regardless of which source the consumer 
chooses. See Note 14 of the notes to Consolidated Financial 
Statements for additional information.

Transition Costs   

AB 1890 allows utilities, within certain limits, the opportunity to 
recover their stranded costs incurred for certain above-market 
CPUC-approved facilities, contracts and obligations through the 
establishment of the CTC.
     Utilities are allowed a reasonable opportunity to recover 
their stranded costs through December 31, 2001. Stranded costs 
include sunk costs, as well as ongoing costs the CPUC finds 
reasonable and necessary to maintain generation facilities through 
December 31, 2001. These costs also include other items SDG&E has 
accrued under traditional cost-of-service regulation.
     Through December 31, 1998, SDG&E has recovered transition 
costs of $500 million for nuclear generation and $200 million for 
nonnuclear generation. Excluding the costs of purchased power and 
other costs whose recovery is not limited to the pre-2002 period, 
the balance of SDG&E's stranded assets at December 31, 1998, is 
$600 million, consisting of $400 million for the power plants and 
$200 million of related deferred taxes and undercollections. During 
the 1998-2001 period, recovery of transition costs is limited by a 
rate cap. See Note 14 of the notes to Consolidated Financial 
Statements for additional information.



Electric-Generation Assets 

In November 1997, SDG&E adopted a plan to auction its power plants 
and other electric-generating assets so that it could continue to 
concentrate its business on the transmission and distribution of 
electricity and natural gas as California opens its electric-
utility industry to competition. This plan included the divestiture 
of SDG&E's fossil-fueled power plants and combustion turbines, its 
20-percent interest in SONGS and its portfolio of long-term 
purchased-power contracts. The power plants, including the interest 
in SONGS, have a net book value as of December 31, 1998, of $400 
million ($100 million for fossil and $300 million for SONGS).
     The March 1998 decision of the CPUC approving the PE/Enova 
Business Combination required, among other things, the divestiture 
by SDG&E of its fossil-fueled generation units. On December 11, 
1998, SDG&E entered into agreements for the sale of its South Bay 
Power Plant, Encina Power Plant and 17 combustion-turbine 
generators. The sales are subject to regulatory approval and are 
expected to close during the first half of 1999. See Note 14 of the 
notes to Consolidated Financial Statements for additional 
information.
     As mentioned above, Sempra Energy Resources and Reliant Energy 
Power Generation formed a joint venture to build, own and operate a 
natural gas power plant (El Dorado) in Boulder City, Nevada. The 
joint venture plans to sell the plant's electricity into the 
wholesale market, which, in turn, sells to utilities throughout the 
Western United States. The new plant will employ an advanced 
combined-cycle gas-turbine technology, enabling it to become one of 
the most efficient and environmentally friendly power plants in the 
nation. Its proximity to existing natural gas pipelines and 
electric transmission lines will allow El Dorado to actively 
compete in the deregulated electric-generation market. The project, 
funded equally by the company and Reliant, began in the first 
quarter of 1998, with an expected operational date set for the 
fourth quarter of 1999. 

Electric Rates  

AB 1890 provides for a 10-percent reduction in rates for 
residential and small commercial customers effective in January 
1998, and provided for the issuance of rate-reduction bonds by an 
agency of the State of California to enable its investor-owned 
utilities (IOUs) to achieve this rate reduction. In December 1997, 
$658 million of rate-reduction bonds were issued on behalf of SDG&E 
at an average interest rate of 6.26 percent. These bonds are being 
repaid over 10 years by SDG&E's residential and small commercial 
customers via a nonbypassable charge on their electricity bills. In 
September 1997, SDG&E and the other California IOUs received a 
favorable ruling by the Internal Revenue Service on the tax 
treatment of the bond transaction. The ruling states, among other 
things, that the receipt of the bond proceeds does not result in 
gross income to SDG&E at the time of issuance, but rather the 
proceeds are taxable over the life of the bonds. The Securities and 
Exchange Commission determined that these bonds should be reflected 
on the utilities' balance sheets as debt, even though the bonds are 
not secured by, or payable from, utility assets, but rather by the 
future revenue streams collected from customers. SDG&E formed a 
subsidiary, SDG&E Funding LLC, to facilitate the issuance of the 
rate-reduction bonds. In exchange for the bond proceeds, SDG&E sold 
to SDG&E Funding LLC all of its rights to the revenue streams. 
Consequently, the revenue streams are not the property of SDG&E and 
are not available to creditors of SDG&E.
     AB 1890 also included a rate freeze for all customers. Until 
the earlier of March 31, 2002, or when transition-cost recovery is 
complete, SDG&E's average system rate will be held at 9.64 cents 
per kilowatt-hour, except for the impacts of fuel-cost changes and 
the 10-percent rate reduction described above. Beginning in 1998, 
system-average rates were fixed at 9.43 cents per kwh, which 
includes the maximum permitted increase related to fuel-cost 
increases and the mandatory rate reduction. SDG&E's ability to 
recover its transition costs is dependent on its total revenues 
under the rate freeze exceeding traditional cost-of-service 
revenues during the transition period by at least the amount of the 
CTC less the net proceeds from the sale of electric-generating 
assets. During the transition period, SDG&E will not earn awards 
from special programs, such as Demand-Side Management, unless total 
revenues are also adequate to cover the awards. Fuel-price 
volatility is one of the more significant uncertainties in the 
ability of SDG&E to recover its transition costs and program 
awards.
     In early 1999, SDG&E filed with the CPUC for an interim 
mechanism to deal with electric rates after the rate freeze ends, 
noting the possibility that the SDG&E rate freeze could end in 
1999.

Performance-Based Regulation 

As discussed above, 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 
by relying solely on expanding utility rate base. See additional 
discussion of PBR in Note 14 of the notes to Consolidated Financial 
Statements.

Regulatory Accounting Standards  

SoCalGas and SDG&E are accounting for the economic effects of 
regulation on all of their utility operations, except for electric 
generation, 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 rate-making 
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 14 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 IOUs 
conduct business with their affiliates. The objective of these 
rules, which became effective January 1, 1998, is to ensure that 
the utilities' energy affiliates do not gain an unfair advantage 
over other competitors in the marketplace and that utility 
customers do not subsidize affiliate activities.
     The CPUC excluded utility-to-utility transactions between 
SDG&E and SoCalGas from the affiliate-transaction rules in its 
March 1998 decision approving the PE/Enova Business Combination. As 
a result, the affiliate-transaction rules will not substantially 
impact the company's ability to achieve anticipated synergy 
savings. See Notes 1 and 14 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. SDG&E was authorized to earn 
a rate of return on rate base of 9.35 percent and a rate of return 
on common equity of 11.6 percent, unchanged from 1997. See 
additional discussion in Note 14 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 investment within the amounts authorized to be collected in 
rates.
     It is the intent of management to control operating expenses 
and investments within the amounts authorized to be collected in 
rates in the PBR decision. The utilities intend to make the 
efficiency improvements, changes in operations and cost reductions 
necessary to achieve this objective and earn their authorized rates 
of return. However, in view of the earnings-sharing mechanism and 
other elements of the PBR, it is more difficult to exceed 
authorized returns to the degree experienced in past years. See 
additional discussion of PBR in Note 14 of the notes to 
Consolidated Financial Statements.

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 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 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 has not had 
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 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 hydroelectric 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 14 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 possibly may have been required to pay for the 
capacity released back to El Paso and Transwestern that cannot be 
remarketed. Of the remaining 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 SoCalGas' ability to 
compete in highly contested markets, SoCalGas 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. Whereas it is anticipated that the environmental costs 
associated with natural gas operations and with electric 
transmission and generation operations will continue to be 
recoverable in rates, the restructuring of the California electric-
utility industry, described above under "Electric Industry 
Restructuring," will change the way utility rates are set and costs 
associated with electric generation are recovered. Capital costs 
related to environmental regulatory compliance for electric 
generation are intended to be included in transition costs for 
recovery through 2001. However, depending on the final outcome of 
industry restructuring and the impact of competition, the costs of 
future compliance with environmental regulations may not be fully 
recoverable.
     Capital expenditures to comply with environmental laws and 
regulations were $1 million in 1998, $5 million in 1997 and $9 
million in 1996, and are not expected to be significant during the 
next five years. These projected expenditures primarily consist of 
the estimated cost of reducing air emissions by retrofitting power 
plants. This estimate anticipates that SDG&E completes the planned 
sale of its fossil-fueled power plants during the first half of 
1999. Additional information on SDG&E's divestiture of its 
electric-generating assets is discussed above under "Electric 
Generation Assets" and in Note 14 of the notes to Consolidated 
Financial Statements. 

Hazardous Substances  

In 1994, the CPUC approved the Hazardous Waste Collaborative, a 
mechanism which allows SoCalGas, SDG&E and other utilities to 
recover, through rates, costs associated with the cleanup of sites 
contaminated with hazardous waste. In general, utilities are 
allowed to recover 90 percent of their cleanup costs and any 
related costs of litigation through rates. In early 1998, the CPUC 
modified this mechanism to exclude these costs related to electric-
generation activities. These costs are now eligible for inclusion 
in the Competition Transition Cost (CTC) recovery process described 
above.  
     During the early 1900s, SDG&E, SoCalGas and their predecessors 
manufactured gas from coal or oil, the sites of which have often 
become contaminated with the hazardous residual by-products of the 
process. SDG&E has identified three former manufactured-gas plant 
sites. One of these sites has been remediated and a site-closure 
letter has been received from the San Diego County Department of 
Environmental Health. An environmental site assessment has been 
conducted and the estimated cost to remediate the other two sites 
is $6 million. SoCalGas has identified 42 former manufactured-gas 
plant sites at which it (together with other utilities of these 
sites) may have clean up obligations. As of December 31, 1998, 12 
of these sites have been remediated and a certificate of closure 
has been received from the California Environmental Protection 
Agency for 10 of the sites. A preliminary environmental site 
assessment has been conducted on 39 of the sites and it is 
estimated that the cost for the remaining sites is $68 million. In 
addition, other company subsidiaries have been named as potentially 
responsible parties (PRPs) in relation to two landfills and three 
industrial waste disposal sites, and it is estimated that the 
subsidiaries' share of the costs to remediate such sites is $5 
million. Ninety percent of SoCalGas' and SDG&E's costs to clean up 
the gas plants and to meet their PRP obligations, a total estimated 
to be $75 million, is recoverable through the Hazardous Waste 
Collaborative mechanism.
     As a part of its sale of the South Bay and Encina power plants 
and 17 combustion turbines (described above), SDG&E retained 
limited remediation obligations for contamination existing on these 
sites upon the closing of the sales. SDG&E's costs to perform its 
remediation obligations as a part of such sales is estimated to be 
$10 million. These costs are eligible for inclusion in the CTC 
recovery process.

Air and Water Quality   

California's air quality standards are more restrictive than 
federal standards. However, due to the sale of the electric-
generating power plants, the company's primary air-quality issue 
compliance with these standards will be less significant in the 
future.
     In connection with the issuance of operating permits, SDG&E 
and the other owners of SONGS reached agreement with the California 
Coastal Commission to mitigate the environmental damage to the 
marine environment attributed to the cooling-water discharge from 
SONGS Units 2 and 3. This mitigation program includes an enhanced 
fish-protection system, a 150-acre artificial reef and restoration 
of 150 acres of coastal wetlands. In addition, the owners must 
deposit $3.6 million with the state for the enhancement of marine 
fish hatchery programs and pay for monitoring and oversight of the 
mitigation projects. SDG&E's share of the cost is estimated to be 
$23 million. The pricing structure contained in the CPUC's decision 
regarding accelerated recovery of SONGS Units 2 and 3 is expected 
to accommodate most of these added mitigation costs.
     The environmental laws and regulations regarding natural gas 
affect the operations of customers as well as the company's 
regulated natural gas entities. Increasingly complex administrative 
and reporting requirements of environmental agencies applicable to 
commercial and industrial customers utilizing natural gas are not 
generally required of those using electricity. However, anticipated 
advancements in natural gas technologies are expected to enable 
natural gas equipment to remain competitive with alternate energy 
sources.
     The transmission and distribution of natural gas require the 
operation of compressor stations, which are subject to increasingly 
stringent air-quality standards. Costs to comply with these 
standards are recovered in rates.

INTERNATIONAL OPERATIONS

Sempra Energy International (SEI) was formed in June 1998, merging 
the international operations of PE and Enova. Prior to the business 
combination, PE and Enova were already partners in two natural gas 
distribution projects in Mexico. In addition, PE held an interest 
in two natural gas utility holding companies in Argentina. 
     SEI develops, operates and invests in energy-infrastructure 
systems and power-generation facilities outside the United States. 
SEI has interests in natural gas transmission and distribution 
projects in Mexico, Argentina and Uruguay and is pursuing projects 
in other parts of Latin America and in Asia.
     In March 1998, PE 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, PE'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.
     SEI is part of a binational consortium named Distribuidora de 
Gas Natural de Mexicali, S. de R.L. de C.V. (DGN-Mexicali), a 
Mexican company that won the first license awarded to a private 
company to build a natural gas distribution system in Mexico. On 
August 20, 1997, DGN-Mexicali began to deliver natural gas to 
customers in Mexicali, Baja California. DGN-Mexicali will invest up 
to $25 million to provide service to 25,000 customers during the 
first five years of operation. Proxima Gas, S.A. de C.V. (Proxima), 
a group of prominent Mexican businesspeople, is the project 
partner. SEI owns a 60-percent interest in the Mexicali project. 
     SEI also has partnered with Proxima to form Distribuidora de 
Gas Natural de Chihuahua, S. de R.L. de C.V. (DGN-Chihuahua), which 
distributes natural gas to the city of Chihuahua, Mexico and 
surrounding areas. On July 9, 1997, DGN-Chihuahua assumed ownership 
of a 16-mile transmission pipeline serving 20 industrial customers. 
DGN-Chihuahua will invest nearly $50 million to provide service to 
50,000 customers in the first five years of operation. SEI owns a 
95-percent interest in DGN-Chihuahua.
     On August 27, 1998, SEI was awarded a 10-year agreement by the 
Mexican Federal Electric Commission to provide natural gas for the 
Presidente Juarez power plant in Rosarito, Baja California. The 
contract includes provisions for delivery of up to 300 million 
cubic feet per day of natural gas transportation services in the 
United States and construction of a 23-mile pipeline from the U.S.-
Mexico border to the plant. This pipeline will also serve other 
customers in the region. In today's dollars, future revenues under 
the contract could approach $1 billion.
     In May 1998, PE was awarded a concession by the government of 
Uruguay to build a natural gas and propane distribution system to 
serve most of the country, excluding Montevideo. SEI is currently 
in discussions with regards to the terms of the concession 
agreement with the Uruguayan government.
     The net losses for international operations were $4 million 
and $9 million, aftertax, for 1998 and 1997, respectively.

OTHER OPERATIONS

Sempra Energy Trading (SET), a leading natural gas power marketing 
firm headquartered in Stamford, Connecticut, was jointly acquired 
by PE and Enova on December 31, 1997. For the year ended December 
31, 1998, SET recorded aftertax income of $1 million from its 
operations and a net loss of $13 million after amortization of 
costs associated with the acquisition. Additional information 
concerning SET is provided in Note 10 of the notes to Consolidated 
Financial Statements.
     Sempra Energy Solutions (Solutions), formed in 1997 as a joint 
venture of PE 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), which was acquired by Solutions in 
January 1998, provides energy-efficiency services including energy 
audits, engineering design, project management, construction, 
financing and contract maintenance.
     Solutions' operating losses were $27 million and $14 million, 
aftertax, for the years ended December 31, 1998, and 1997, 
respectively. The losses are primarily due to startup costs.



OTHER INCOME, INTEREST EXPENSE AND INCOME TAXES 

Other Income   

Other income, which primarily consists of interest income from 
short-term investments and regulatory-balancing accounts, decreased 
in 1998 to $44 million from $58 million in 1997. The decrease was a 
result of lower interest income from short-term investments. The 
increase to $58 million from $28 million in 1996 was due to higher 
interest from short-term investments during much of 1997.

Interest Expense  

Interest expense for 1998 increased slightly to $207 million from 
$206 million in 1997. Interest expense for 1997 increased to $206 
million from $200 million in 1996, as a result of a higher long-
term debt balance.

Income Taxes  

Income tax expense for 1998 was $138 million, less than the $301 
million for 1997. The effective income tax rate was 32 percent for 
1998 and 41 percent for 1997. The decrease in income tax expense is 
primarily due to the decrease in pretax income, combined with an 
increase in affordable-housing tax credits.

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 10 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 periodically enter into 
interest-rate swap and cap agreements to moderate exposure to 
interest-rate changes and to lower the overall cost of borrowing. 
These swap and cap agreements generally remain off the balance 
sheet as they involve the exchange of fixed-rate and variable-rate 
interest payments without the exchange of the underlying principal 
amounts. The related gains or losses are reflected in the income 
statement as part of interest expense. The company would be exposed 
to interest-rate fluctuations on the underlying debt should other 
parties to the agreement not perform. Such nonperformance is not 
anticipated. At December 31, 1998, the notional amount of swap 
transactions associated with the regulated operations totaled $45 
million. See Note 5 of the notes to Consolidated Financial 
Statements for further information regarding these swap 
transactions.
     The company's regulated operations use energy derivatives to 
manage natural gas price risk associated with servicing their load 
requirements. In addition, they make limited use of natural gas 
derivatives for trading purposes. These instruments include forward 
contracts, futures, swaps, options and other contracts, with 
maturities ranging from 30 days to 12 months. In the case of both 
price-risk management and trading 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 10 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 equity and energy. The 
company 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 company-wide energy-price risk-management and trading 
activities to ensure compliance with the company'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.
     A portion of the company's borrowings are denominated in 
foreign currencies, which expose the company to market risk 
associated with exchange-rate movements. The company's policy 
generally is to hedge major foreign-currency cash exposures through 
swap transactions. These contracts are entered into with major 
international banks, thereby minimizing the risk of credit loss.
     The VaR on the company's fixed rate long term debt is 
estimated at approximately $312 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, petroleum and electricity commodity 
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, petroleum and electricity markets. The company's 
policy is to manage this risk within a framework that considers the 
unique markets, operating and regulatory environment of each 
affiliate. 

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, 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. 

SDG&E

SDG&E is exposed to market risk in its natural gas purchase, sale 
and storage activities whenever natural gas prices fall outside the 
PBR tolerance band. SDG&E 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 SDG&E's natural gas 
positions was not material. 
     SDG&E is exposed to market risk on its electricity purchases 
and sales under the electricity rate cap. See Note 14 of the notes 
to Consolidated Financial Statements and the discussion under 
"Factors Influencing Future Performance" for further information 
regarding the electricity rate cap. 

SoCalGas

SoCalGas is exposed to market risk on its natural gas purchase, 
sale and storage activities whenever natural gas prices fall 
outside the Gas Cost Incentive Mechanism 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. 

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 the 
company's overall Year 2000 readiness effort. The company has 
established a central Year 2000 Program Office, which reports to 
the company's Chief Information Technology Officer and reports 
periodically to the audit committee of the board of directors.

The Company's State of Readiness  

Sempra Energy is identifying all IT and non-IT systems that might 
not be Year 2000 ready and categorizing them in the following 
areas: IT applications, computer hardware and software 
infrastructure, telecommunications, embedded systems and third 
parties. The company 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. The company 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.
     The company'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 the company's 
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 the company's schedule to change.

Costs to Address the Company's Year 2000 Issues  

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

The Risks of the Company's Year 2000 Issues   

Based upon its current assessment and testing of the Year 2000 
issue, the company believes the reasonably likely worst-case Year 
2000 scenarios would have the following impacts upon Sempra Energy 
and its operations. With respect to the company's ability to 
provide energy to its domestic utility customers, the company 
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. The 
company is in the process of contacting its critical suppliers and 
customers to survey their Year 2000 remediation programs. While 
risks related to the lack of Year 2000 readiness by third parties 
could materially and adversely affect the company's business, 
results of operations and financial condition, the company expects 
its Year 2000 readiness efforts to reduce significantly the 
company's level of uncertainty about the impact of third party Year 
2000 issues on both its IT systems and non-IT systems.



Company's Contingency Plans 

Sempra Energy's contingency plans for interruptions related to Year 
2000 issues are being incorporated in the company's 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. The company 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 the company'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 Annual 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.







STATEMENT OF MANAGEMENT RESPONSIBILITY FOR
CONSOLIDATED FINANCIAL STATEMENTS

The consolidated financial statements have been prepared by 
management in accordance with generally accepted accounting 
principles. The integrity and objectivity of these financial 
statements and the other financial information in the Annual 
Report, including the estimates and judgments on which they are 
based, are the responsibility of management. The financial 
statements have been audited by Deloitte & Touche LLP, independent 
certified public accountants appointed by the Board of Directors. 
Their report is shown below. Management has made available to 
Deloitte & Touche LLP all of the company's financial records and 
related data, as well as the minutes of shareholders' and 
directors' meetings.
     Management maintains a system of internal accounting control 
which it believes is adequate to provide reasonable, but not 
absolute, assurance that assets are properly safeguarded and 
accounted for, that transactions are executed in accordance with 
management's authorization and are properly recorded and reported, 
and for the prevention and detection of fraudulent financial 
reporting. The concept of reasonable assurance recognizes that the 
cost of a system of internal controls should not exceed the 
benefits derived and that management makes estimates and judgments 
of these cost/benefit factors.
     Management monitors the system of internal control for 
compliance through its own review and a strong internal auditing 
program which also independently assesses the effectiveness of the 
internal controls. In establishing and maintaining internal 
controls, the company must exercise judgment in determining whether 
the benefits derived justify the costs of such controls.
     Management acknowledges its responsibility to provide 
financial information (both audited and unaudited) that is 
representative of the company's operations, reliable on a 
consistent basis, and relevant for a meaningful financial 
assessment of the company. Management believes that the control 
process enables it to meet this responsibility.
     Management also recognizes its responsibility for fostering a 
strong ethical climate so that the company's affairs are conducted 
according to the highest standards of personal and corporate 
conduct. This responsibility is characterized and reflected in the 
company's code of corporate conduct, which is publicized throughout 
the company. The company maintains a systematic program to assess 
compliance with this policy.
     The Board of Directors has an Audit Committee composed solely 
of directors who are not officers or employees. The Committee 
recommends for approval by the full Board the appointment of the 
independent auditors. The Committee meets regularly with 
management, with the company's internal auditors and with the 
independent auditors. The independent auditors and the internal 
auditors periodically meet alone with the Audit Committee and have 
free access to the Audit Committee at any time.


/s/ Neal E. Schmale

Neal E. Schmale
Executive Vice President and Chief Financial Officer


/s/ Frank H. Ault

Frank H. Ault
Vice President and Controller  




INDEPENDENT AUDITORS' REPORT

To the Board of Directors and Shareholders of Sempra Energy:

We have audited the accompanying consolidated balance sheets of 
Sempra Energy and subsidiaries (the "company") 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 Sempra 
Energy 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 16 as to which the date is 
February 22, 1999








SEMPRA ENERGY
Statements of Consolidated Income


                                                        Years Ended December 31,
                                                    -------------------------------
(Dollars in millions, except per share amounts)     1998          1997         1996
- -----------------------------------------------------------------------------------
                                                                 
Revenues and Other Income
  Utility revenues:
    Natural gas                                $   2,772     $   2,964    $   2,710
    Electric                                       1,865         1,769        1,591
    PX/ISO power                                     500            --           --
  Other operating revenues                           344           336          195
  Other income                                        44            58           28
                                                --------      --------     --------
        Total                                      5,525         5,127        4,524
                                                --------      --------     --------
Expenses
  Cost of natural gas distributed                    954         1,168          958
  PX/ISO power                                       468            --           --
  Purchased power                                    292           441          311
  Electric fuel                                      177           164          134
  Operating expenses                               1,872         1,615        1,405
  Depreciation and amortization                      929           604          587
  Franchise payments and other taxes                 182           178          180
  Preferred dividends of subsidiaries                 12            18           22
                                                --------      --------     --------
        Total                                      4,886         4,188        3,597
                                                --------      --------     --------
Income Before Interest and Income Taxes              639           939          927
Interest                                             207           206          200
                                                --------      --------     --------
Income Before Income Taxes                           432           733          727
Income taxes                                         138           301          300
                                                --------      --------     --------
Net Income                                      $    294      $    432     $    427
                                                ========      ========     ========
Net Income Per Share of Common Stock (Basic)    $   1.24      $   1.83     $   1.77
                                                ========      ========     ========
Net Income Per Share of Common Stock (Diluted)  $   1.24      $   1.82     $   1.77
                                                ========      ========     ========
Common Dividends Declared Per Share             $   1.56      $   1.27     $   1.24
                                                ========      ========     ========



See notes to Consolidated Financial Statements.









SEMPRA ENERGY
Consolidated Balance Sheets


                                                      December 31,
                                                    ----------------
(Dollars in millions)                               1998        1997
- --------------------------------------------------------------------
                                                      
Assets
Current assets:
   Cash and cash equivalents                    $    424    $    814
   Accounts receivable - trade                       586         633
   Accounts and notes receivable - other             159         202
   Deferred income taxes                              93          15
   Energy trading assets                             906         587
   Inventories                                       151         111
   Regulatory balancing accounts - net                --         297
   Other                                             139         102
                                                 -------     -------
      Total current assets                         2,458       2,761
                                                 -------     -------

Investments and other assets:
   Regulatory assets                                 980       1,186
   Nuclear-decommissioning trusts                    494         399
   Investments                                       548         429
   Other assets                                      535         439
                                                 -------     -------
      Total investments and other assets           2,557       2,453
                                                 -------     -------

Property, plant and equipment:
   Property, plant and equipment                  11,235      10,902
   Less accumulated depreciation      
     and amortization                             (5,794)     (5,360)
                                                 -------     -------
      Total property, plant and 
        equipment - net                            5,441       5,542
                                                 -------     -------
      Total assets                              $ 10,456    $ 10,756
                                                 =======     =======



See notes to Consolidated Financial Statements.










SEMPRA ENERGY
Consolidated Balance Sheets


                                                    December 31,
                                                 -----------------
(Dollars in millions)                              1998       1997
- ------------------------------------------------------------------
                                                    
Liabilities
Current liabilities:
  Short-term debt                             $     43    $   354
  Accounts payable - trade                         702        625
  Accrued income taxes                              27          5
  Energy trading liabilities                       805        557
  Dividends and interest payable                   168        121
  Regulatory balancing accounts - net              120         --
  Long-term debt due within one year               330        270
  Other                                            271        279
                                               -------    -------
      Total current liabilities                  2,466      2,211
                                               -------    -------
Long-term debt:
  Long-term debt                                 2,795      3,045
  Debt of Employee Stock Ownership Plan             --        130
                                               -------    -------
      Total long-term debt                       2,795      3,175
                                               -------    -------
Deferred credits and other liabilities:
  Customer advances for construction                72         72
  Post-retirement benefits other than pensions     240        248
  Deferred income taxes                            634        741
  Deferred investment tax credits                  147        155
  Deferred credits and other liabilities           985        916
                                               -------    -------
      Total deferred credits and 
        other liabilities                        2,078      2,132
                                               -------    -------
Preferred stock of subsidiaries                    204        279
                                               -------    -------
Commitments and contingent liabilities (Note 13)

Shareholders' Equity
Common stock                                     1,883      1,849
Retained earnings                                1,075      1,157
Less deferred compensation relating to 
  Employee Stock Ownership Plan                    (45)       (47)
                                               -------    -------
      Total shareholders' equity                 2,913      2,959
                                               -------    -------
      Total liabilities and shareholders' 
        equity                                $ 10,456   $ 10,756
                                               =======    =======



See notes to Consolidated Financial Statements.









SEMPRA ENERGY
Statements of Consolidated Cash Flows 

                                                               Years Ended December 31     
                                                         --------------------------------- 
(Dollars in millions)                                      1998        1997         1996   
- ------------------------------------------------------------------------------------------ 
                                                                        
CASH FLOWS FROM OPERATING ACTIVITIES
  Net Income                                            $     294   $     432   $     427   
  Adjustments to reconcile net income to net cash  
    provided by operating activities:  
      Depreciation and amortization                           929         604         587   
      Deferred income taxes and investment tax credits       (199)        (16)         26   
      Other - net                                            (180)         62          56   
      Net changes in other working capital components         479        (164)         68   
                                                        ----------   ---------   ---------  
        Net cash provided by operating activities           1,323         918       1,164   
                                                        ----------   ---------   ---------  
CASH FLOWS FROM INVESTING ACTIVITIES    
  Expenditures for property, plant and equipment             (438)       (397)       (413)  
  Acquisitions of subsidiaries                               (191)       (206)        (50)  
  Contributions to decommissioning trusts                     (22)        (22)        (22)  
  Other                                                       (28)         23         (29)  
                                                        ---------  -----------  ---------- 
        Net cash used in investing activities                (679)       (602)       (514)  
                                                        ---------  -----------  ---------- 
CASH FLOWS FROM FINANCING ACTIVITIES    
  Common stock dividends                                     (325)       (301)       (300)  
  Sale of common stock                                         34          17           8   
  Repurchase of common stock                                   (1)       (122)        (24)  
  Redemption of preferred stock                               (75)         --        (225)  
  Issuances of other long-term debt                            75         140         304   
  Issuance of rate-reduction bonds                             --         658          --   
  Payment on long-term debt                                  (431)       (416)       (459)  
  Increase (decrease) in short-term debt - net               (311)         92          29   
                                                        ---------  -----------  ----------  
Net cash provided by (used in) financing activities        (1,034)         68        (667)  
                                                        ---------  -----------  ----------  
Increase (Decrease) in Cash and Cash Equivalents             (390)        384         (17)  
Cash and Cash Equivalents, January 1                          814         430         447   
                                                        ---------  -----------  ----------  
Cash and Cash Equivalents, December 31                  $     424   $     814   $     430   
                                                        =========  ===========  ========== 



See notes to Consolidated Financial Statements.









SEMPRA ENERGY
Statements of Consolidated Cash Flows 

                                                               Years Ended December 31      
                                                         --------------------------------- 
(Dollars in millions)                                      1998        1997         1996   
- ------------------------------------------------------------------------------------------ 
                                                                       
CHANGES IN OTHER WORKING CAPITAL COMPONENTS
 (Excluding cash and cash equivalents, short-term
   debt and long-term debt due within one year) 

  Accounts and notes receivable                         $      90   $    (129)  $     (58)  
  Net trading assets                                          (71)         --          --   
  Inventories                                                 (40)         (2)         32   
  Regulatory balancing accounts                               417          48           9   
  Other current assets                                        (26)         41          40   
  Accounts payable and other current liabilities              109        (122)         45   
                                                         --------    --------     --------  
          Net change in other working
           capital components                           $     479   $    (164)  $      68   
                                                         ========    ========     ========  

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid during the year for:
   Interest (net of amounts capitalized)                $     211   $     193   $      205  

   Income taxes (net of refunds)                        $     366   $     274   $      268  


SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES
    Acquisition of Sempra Energy Trading:
      Assets acquired                                   $      --   $    609    $      --  
      Cash paid                                                --       (225)          --  
                                                       ----------  -----------  --------- 
      Liabilities assumed                               $      --   $    384    $      --  
                                                       ==========  ===========  ========= 

    Liabilities assumed for real estate investments     $      36   $    126    $      97 
                                                       ==========  ===========  ========= 

    Nonutility electric generation assets sold:
      Book value of assets sold                         $      --   $     77   $      --  
      Cash received                                            --        (20)         --  
      Loss on sale                                             --         (6)         --  
                                                       ----------  -----------  --------- 
      Note receivable obtained                          $      --   $     51   $      --  
                                                       ==========  ===========  ========= 



See notes to Consolidated Financial Statements.








 
SEMPRA ENERGY
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY 
 

For the years ended December 31, 1998, 1997, 1996 
(Dollars in millions)
 
 

                                                          Deferred     
                                                          Compensation  Total
                                 Common       Retained    Relating      Shareholders'
                                 Stock        Earnings    to ESOP       Equity
- ------------------------------------------------------------------------------------
                                                              
Balance at December 31, 1995     $ 1,968      $  899      $  (52)       $ 2,815

Net income                                       427                        427  
Common stock dividends declared                 (300)                      (300)  
Sale of common stock                   8                                      8
Repurchase of common stock           (24)                                   (24)
Common stock released
   from ESOP                                                   3              3 
Long-term incentive plan               1                                      1
- ------------------------------------------------------------------------------------ 
Balance at December 31, 1996       1,953       1,026         (49)         2,930

Net income                                       432                        432
Common stock dividends declared                 (301)                      (301)
Sale of common stock                  17                                     17
Repurchase of common stock          (122)                                  (122)
Common stock released
   from ESOP                                                   2              2
Long-term incentive plan               1                                      1
- ------------------------------------------------------------------------------------
Balance at December 31, 1997       1,849       1,157         (47)         2,959

Net income                                       294                        294
Common stock dividends declared                 (376)                      (376) 
Sale of common stock                  34                                     34
Repurchase of common stock            (1)                                    (1)
Common stock released
   from ESOP                                                   2              2
Long-term incentive plan               1                                      1
- ------------------------------------------------------------------------------------
Balance at December 31, 1998     $ 1,883      $1,075      $  (45)       $ 2,913
====================================================================================
 
See notes to Consolidated Financial Statements. 





NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1     BUSINESS COMBINATION

On June 26, 1998, Enova Corporation (Enova) and Pacific Enterprises 
(PE) combined into a new company named Sempra Energy (the company). 
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.
     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 the first half of 1999. 
Additional information concerning the sale of SDG&E's power plants 
is provided in Note 14. 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 electric-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.
     The Consolidated Financial Statements are those of the company 
and its subsidiaries and give effect to the business combination 
using the pooling-of-interests method and, therefore, are presented 
as if the companies were combined during all periods included 
therein. The per-share data shown on the Statements Of Consolidated 
Income reflect the conversion of Enova common stock and of PE 
common stock into Sempra Energy common stock as described above. 
All significant intercompany transactions, including SoCalGas' 
sales of natural gas transportation and storage to SDG&E, have been 
eliminated. These sales amounted to approximately $60 million in 
each of the years presented. 
     The results of operations for PE and Enova as reported as 
separate companies through June 30, 1998, are as follows:

- ---------------------------------------------------------------
                          Six months 
                        ended June 30,
(Dollars in millions)        1998          1997          1996
- ---------------------------------------------------------------
PACIFIC ENTERPRISES
Revenue and Other Income    $1,263        $2,777        $2,588
Net Income                  $   50        $  180        $  196

ENOVA
Revenue and Other Income    $1,299        $2,224        $1,996
Net Income                  $   68        $  252        $  231
- ---------------------------------------------------------------

2     SIGNIFICANT ACCOUNTING POLICIES

Property, Plant and Equipment  

This primarily represents the buildings, equipment and other 
facilities used by SDG&E and SoCalGas to provide natural gas and 
electric utility 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. Information regarding electric-
industry restructuring and its effect on utility plant is included 
in Note 14. Utility plant balances by major functional categories 
at December 31, 1998, are: natural gas operations $7.0 billion, 
electric distribution $2.4 billion, electric transmission $0.7 
billion, electric generation $0.6 billion and other electric $0.3 
billion. The corresponding amounts at December 31, 1997, were 
essentially the same. Accumulated depreciation and decommissioning 
of natural gas and electric utility plant in service at December 
31, 1998, are $3.5 billion and $2.2 billion, respectively, and at 
December 31, 1997, were $3.3 billion and $2.0 billion, 
respectively. 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 (by major 
functional categories) in 1998, 1997, and 1996, respectively are: 
natural gas operations 4.32, 4.31, 4.35, electric generation 6.49, 
5.60, 5.60, electric distribution 4.49, 4.39, 4.38, electric 
transmission 3.31, 3.28, 3.25, and other electric 6.29, 6.02, 5.95. 
The increase for electric generation in 1998 reflects the 
accelerated recovery of generation facilities. See Note 14 for 
additional discussion of generation facilities and industry 
restructuring.

Inventories  

Included in inventories at December 31, 1998, are $61 million of 
utility materials and supplies ($56 million in 1997), and $78 
million of natural gas and fuel oil ($47 million in 1997). 
Materials and supplies are generally valued at the lower of average 
cost or market; fuel oil and natural gas are valued by the last-in 
first-out method.

Trading Instruments  

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  

SDG&E and 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.
     SDG&E and SoCalGas have been preparing their 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. To the extent that portions 
of the utility operations were no longer subject to SFAS No. 71, or 
recovery was no longer probable as a result of changes in 
regulation or their competitive position, the related regulatory 
assets and liabilities would be written off. 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. 
As discussed in Note 14, California enacted a law restructuring the 
electric-utility industry. The law adopts the December 1995 CPUC 
policy decision, and allows California electric utilities the 
opportunity to recover existing utility plant and regulatory assets 
over a transition period that ends in 2001. In 1997, SDG&E ceased 
the application of SFAS No. 71 with respect to its electric-
generation business. The application of SFAS No. 121 continues to 
be evaluated as industry restructuring progresses. Additional 
information concerning regulatory assets and liabilities is 
described below in "Revenues and Regulatory Balancing Accounts" and 
in Note 14.

Revenues and Regulatory Balancing Accounts  

Revenues from utility customers consist of deliveries to customers 
and the changes in regulatory balancing accounts. The amounts 
included in regulatory balancing accounts at December 31, 1998, 
represent a $129 million net payable for SoCalGas combined with a 
$9 million net receivable for SDG&E. The corresponding amounts at 
December 31, 1997 were $355 million net receivable and $58 million 
net payable for SoCalGas and SDG&E, respectively.
     Previously, earnings fluctuations from changes in the costs of 
fuel oil, purchased energy and natural gas, and consumption levels 
for electricity and the majority of natural gas were eliminated by 
balancing accounts authorized by the CPUC. This is still the case 
for most natural gas operations. However, as a result of 
California's electric-restructuring law, overcollections recorded 
in SDG&E's Energy Cost Adjustment Clause and Electric Revenue 
Adjustment Mechanism balancing accounts were transferred to the 
Interim Transition Cost Balancing Account, which is being applied 
to transition cost recovery, and fluctuations in costs and 
consumption levels can affect earnings from electric operations. 
Additional information on electric-industry restructuring is 
included in Note 14.

Regulatory Assets  

Regulatory assets include San Onofre Nuclear Generating Station 
(SONGS), unrecovered premium on early retirement of debt, post-
retirement benefit costs, deferred income taxes recoverable in 
rates and other regulatory-related expenditures that the utilities 
expect to recover in future rates. See Note 14 for additional 
information.

Nuclear-Decommissioning Liability  

Deferred credits and other liabilities at December 31, 1998, 
include $146 million ($117 million in 1997) of accumulated 
decommissioning costs associated with SDG&E's SONGS Unit 1, which 
was permanently shut down in 1992. Additional information on SONGS 
Unit 1 decommissioning costs is included in Note 6. The 
corresponding liability for Units 2 and 3 is included in 
accumulated depreciation and amortization.

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 
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.

Basis of Presentation  

Certain prior-year amounts have been reclassified from the 
predecessor companies' classifications to conform to the format of 
these financial statements.

New Accounting Standard

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


3     ACQUISITIONS AND JOINT VENTURES

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.

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 approximately 
60 percent of 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. Natural 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 a 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 provides 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. Construction costs incurred to date are $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 Natural Gas Projects  

Sempra Energy International (SEI) is a wholly owned subsidiary of 
Sempra Energy. Sempra Energy International 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 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-Chihuahua 
assumed ownership of natural gas distribution facilities during the 
third quarter of 1997. SEI owns interests of 60 and 95 percent in 
the DGN-Mexicali and DGN-Chihuahua projects, respectively. In 
August 1998, SEI was awarded a 10-year agreement by the Mexican 
Federal Electric Commission to provide a complete energy-supply 
package for a power plant in Rosarito, Baja California. The 
contract includes provisions for delivery of up to 300 million 
cubic feet per day of natural gas, transportation services in the 
U.S. and construction of a 23-mile pipeline from the U.S.-Mexico 
border to the plant. The pipeline is expected to cost approximately 
$35 million and take a year to build. Delivery of natural gas is 
expected to commence in December 1999. 
     SEI also has interests in Argentina and Uruguay. In March 
1998, SEI 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 interest for $40 million.


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.
     SDG&E has $30 million of bank lines available to support 
commercial paper and $265 million of bank lines available to 
support variable-rate, long-term debt. The credit agreements expire 
at varying dates from 1999 through 2000 and bear interest at 
various rates based on market rates and the company's credit 
rating. SDG&E's bank lines of credit were unused at both December 
31, 1998, and 1997.
     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 gas-supply contracts under the 
Comprehensive Settlement. See Note 14 for additional information.




5     LONG-TERM DEBT

- --------------------------------------------------------------
                                             December 31,
(Dollars in millions)                     1998          1997
- --------------------------------------------------------------
Long-Term Debt
First mortgage bonds
     5.25% March 1, 1998               $     _     $     100
     7.625% June 15, 2002                    28           80
     6.875% August 15, 2002                 100          100
     5.75% November 15, 2003                100          100
     6.8% June 1, 2015                       14           14
     5.9% June 1, 2018                       71           71
     5.9% September 1, 2018                  93           93
     6.1% and 6.4% September 1, 2018
        and 2019                            118          118
     9.625% April 15, 2020                   10           54
     Variable rates September 1, 2020        58           75
     5.85% June 1, 2021                      60           60
     8.75% October 1, 2021                  150          150
     8.5% April 1, 2022                      10           44
     7.375% March 1, 2023                   100          100
     7.5% June 15, 2023                     125          125
     6.875% November 1, 2025                175          175
     Various rates December 1, 2027         250          250
                                        ----------------------
          Total                           1,462        1,709
Rate-reduction bonds                        592          658
Debt incurred to acquire limited 
  partnerships, secured by real estate,
  at 6.8% to 9.0%, payable annually 
  through 2008                              305          313
Various unsecured bonds at 4.15%
  to 10% from 1998 to 2006                  453          296
Various unsecured bonds at 5.9%
  or at variable rates (4.3% to 5.0% at
  December 31, 1998) from 2014 to 2023      254          254
Capitalized leases                           76          106
                                        ----------------------
          Total                           3,142        3,336
                                        ----------------------
Less:
Current portion of long-term debt           330          270
Unamortized discount on long-term debt       17           21
                                        ----------------------
                                            347          291
                                        ----------------------
Total                                 $   2,795    $   3,045
- --------------------------------------------------------------

     Excluding capital leases, which are described in Note 13, 
maturities of long-term debt, including PE's Employees Stock 
Ownership Plan, are $271 million in 1999, $96 million in 2000, $186 
million in 2001, $193 million in 2002 and $241 million in 2003. 
SDG&E and SoCalGas have CPUC authorization to issue an additional 
$752 million in long-term debt. Although holders of variable-rate 
bonds may elect to redeem them prior to scheduled maturity, for 
purposes of determining the maturities listed above, it is assumed 
the bonds will be held to maturity.

First-Mortgage Bonds  

First-mortgage bonds are secured by a lien on substantially all 
utility plant. In addition, certain non-utility subsidiary assets 
are pledged as collateral for SoCalGas' first-mortgage bonds. SDG&E 
and SoCalGas may issue additional first-mortgage bonds upon 
compliance with the provisions of their bond indentures, which 
provide for, among other things, the issuance of additional first-
mortgage bonds ($1.5 billion as of December 31, 1998).
     During 1998, the company retired $247 million of first-
mortgage bonds, of which $147 million was retired prior to 
scheduled maturity. 
     Certain first-mortgage bonds may be called at SDG&E's or 
SoCalGas' option. SoCalGas has no variable-rate bonds. SDG&E has 
$188 million of bonds with variable interest-rate provisions that 
are callable at various dates within one year. Of the company's 
remaining callable bonds, $10 million are callable in the year 
2000, $150 million in 2001, $203 million in 2002, and $624 million 
in 2003. $242 million of the bonds are not callable.

Rate-Reduction Bonds  

In December 1997, $658 million of rate-reduction bonds were issued 
on behalf of SDG&E at an average interest rate of 6.26 percent. 
These bonds were issued to facilitate the 10-percent rate reduction 
mandated by California's electric-restructuring law. See Note 14 
for additional information. These bonds are being repaid over 10 
years by SDG&E's residential and small commercial customers via a 
charge on their electricity bills. These bonds are secured by the 
revenue streams collected from customers and are not secured by, or 
payable from, utility assets.

Unsecured Debt  

Various long-term obligations totaling $707 million are unsecured. 
During 1998, SoCalGas issued $75 million of unsecured debt in 
medium-term notes used to finance working capital requirements. 
Unsecured bonds totaling $124 million have variable-interest-rate 
provisions.

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 fund part of their retirement savings 
program. It has an ESOP feature and holds approximately 3.1 million 
shares of the company'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 as 
part of the various unsecured bonds at 4.15 percent to 10 percent. 
Principal is due on November 30, 1999, and interest is payable 
monthly. The company is obligated to make contributions to the 
Trust sufficient to satisfy debt service requirements. As the 
company makes contributions to the Trust, these contributions, plus 
any dividends paid on the unallocated shares of the company'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 each in 1998, 1997 and 1996. Dividends used for debt 
service amounted to $3 million each in 1998, 1997, and 1996, and 
are deductible only for federal income tax purposes.

Currency Interest-Rate Swaps  

SDG&E periodically enters into interest-rate swap and cap 
agreements to moderate its exposure to interest-rate changes and to 
lower its overall cost of borrowings. At December 31, 1998, SDG&E 
had such an agreement, maturing in 2002, with underlying debt of 
$45 million.


6     FACILITIES UNDER JOINT OWNERSHIP

SONGS and the Southwest Powerlink transmission line are owned 
jointly with other utilities. The company's interests at December 
31, 1998, are:

- -----------------------------------------------------------
(Dollars in millions)                         Southwest
Project                            SONGS      Powerlink
- -----------------------------------------------------------
Percentage ownership                 20            89
Regulatory assets                $  312             _
Utility plant in service              _        $  217
Accumulated depreciation 
  and amortization                    -        $  104
Construction work in progress    $   18        $    1
- -----------------------------------------------------------

     The company's share of operating expenses is included in the 
Statements of Consolidated Income. Each participant in the project 
must provide its own financing. The amounts specified above for 
SONGS include nuclear production, transmission and other 
facilities. $11 million of substation equipment included in these 
amounts is wholly owned by the company.

SONGS Decommissioning  

Objectives, work scope and procedures for the future dismantling 
and decontamination of the SONGS units must meet the requirements 
of the Nuclear Regulatory Commission, the Environmental Protection 
Agency, the California Public Utilities Commission and other 
regulatory bodies.
     The company's share of decommissioning costs for the SONGS 
units is estimated to be $425 million in today's dollars and is 
based on a cost study completed in 1998. Cost studies are performed 
and updated periodically by outside consultants. Although electric-
industry restructuring legislation requires that stranded costs, 
which include SONGS' costs, be amortized in rates by 2001, the 
recovery of decommissioning costs is allowed until the time that 
the costs are fully recovered.
     The amount accrued each year is based on the amount allowed by 
regulators and is currently being collected in rates. This amount 
is considered sufficient to cover the company's share of future 
decommissioning costs. Payments to the nuclear-decommissioning 
trusts are expected to continue until SONGS is decommissioned, 
which is not expected to occur before 2013. Unit 1, although 
permanently shut down in 1992, was scheduled to be decommissioned 
concurrently with Units 2 and 3. However, the company and the other 
owners of SONGS have requested that the CPUC grant authority to 
begin decommissioning Unit 1 on January 1, 2000.
     The amounts collected in rates are invested in externally 
managed trust funds. The securities held by the trust are 
considered available for sale and shown on the Consolidated Balance 
Sheets adjusted to market value. The fair values reflect unrealized 
gains of $149 million and $89 million at December 31, 1998, and 
1997, respectively.
     The Financial Accounting Standards Board is reviewing the 
accounting for liabilities related to closure and removal of long-
lived assets, such as nuclear power plants, including the 
recognition, measurement and classification of such costs. The 
Board could require, among other things, that the company's future 
balance sheets include a liability for the estimated 
decommissioning costs, and a related increase in the cost of the 
asset.
     Additional information regarding SONGS is included in Notes 13 
and 14.


7     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                          6.3       7.1       6.2
State income taxes-net of 
  federal income tax benefit          7.4       6.7       6.2
Tax credits                         (12.9)     (5.7)     (4.8)
Equipment leasing activities         (1.5)     (1.1)     (1.4)
Capitalized expenses not deferred     0.2      (1.4)     (2.1)
Other-net                            (2.6)      0.5       2.2
                                   ---------------------------
    Effective income tax rate        31.9%     41.1%     41.3%
- --------------------------------------------------------------

The components of income tax expense are as follows:

- --------------------------------------------------------------
(Dollars in millions)                  1998     1997     1996
- --------------------------------------------------------------
Current:
  Federal                              $278     $236     $183
  State                                  89       63       65
                                   ---------------------------
    Total current taxes                 367      299      248
                                   ---------------------------
Deferred:
  Federal                              (165)       1       52
  State                                 (58)       7        6
                                   ---------------------------
    Total deferred taxes               (223)       8       58
                                   ---------------------------
Deferred investment tax credits-net      (6)      (6)      (6)
                                   ---------------------------
    Total income tax expense           $138     $301     $300
- --------------------------------------------------------------

Accumulated 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                  $924   $1,063
  Regulatory balancing accounts                   23      133
  Regulatory assets                               76      120
  Partnership income                              27       21
  Other                                           71       53
                                            ------------------
  Total deferred tax liabilities               1,121    1,390
                                            ------------------
Deferred Tax Assets:
  Unamortized investment tax credits              88       89
  Comprehensive Settlement (see Note 14)          95      117
  Postretirement benefits                         76       90
  Other deferred liabilities                     102      110
  Restructuring costs                             42       54
  Other                                          177      204
                                            ------------------
  Total deferred tax assets                      580      664
                                            ------------------
Net deferred income tax liability                541      726
Current portion (net asset)                       93       15
                                            ------------------
Non-current portion (net liability)             $634     $741
- --------------------------------------------------------------


8     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 
subsidiaries' plans to those of Sempra Energy.

Pension and Other Postretirement Benefits  

The company sponsors several 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%     7.07%          6.75%     7.02%
Expected return on plan assets             8.50%     8.13%          8.50%     7.87%
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        $2,117    $1,981         $ 531     $ 442
Service cost                                   55        53            13        15
Interest cost                                 148       144            36        35
Plan participants' contributions                _         _             1         1
Plan amendments                                18         _             _         _
Actuarial (gain) loss                         (44)       54             _        57
Special termination benefits                   63        13             3         2
Gross benefits paid                          (277)     (128)          (21)      (21)
                                       ----------------------------------------------
Net benefit obligation at December 31       2,080     2,117           563       531
                                       ----------------------------------------------
Change in Plan Assets:

Fair value of plan assets at January 1      2,653     2,373           363       286
Actual return on plan assets                  407       406            64        59
Employer contributions                         13         2            36        38
Plan participants' contributions                _         _             1         1
Gross benefits paid                          (277)     (128)          (21)      (21)
                                       ----------------------------------------------
Fair value of plan assets at December 31    2,796     2,653           443       363
                                       ----------------------------------------------
Funded status at December 31                  716       536          (120)     (168)
Unrecognized net actuarial gain              (926)     (733)         (107)      (66)
Unrecognized prior service cost                73        61           (13)      (14)
Unrecognized net transition obligation          3         4             _         _
                                       ----------------------------------------------
Net liability at December 31 (3)           $ (134)   $ (132)        $(240)    $(248)
- -------------------------------------------------------------------------------------

(1) Decreasing to ultimate trend of 6.50% in 2004.
(2) Decreasing to ultimate trend of 6.50% in 1998.
(3) 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                       $55      $53      $58        $13      $15     $18
Interest cost                      148      144      141         36       35      36
Expected return on assets         (196)    (178)    (161)       (24)     (22)    (19)
Amortization of:
  Transition obligation              1        1        1          2        2       2
  Prior service cost                 6        5        5         (1)      (1)     (1)
  Actuarial (gain) loss            (23)     (18)      (4)         _        1       1
Special termination benefit         63       13        _          3        2       _
Settlement credit                  (30)       _        _          _        _       _
Regulatory adjustment                _        _      (12)         9       12      12
                                -----------------------------------------------------
Total net periodic benefit cost    $24      $20      $28        $38      $44     $49
- -------------------------------------------------------------------------------------





     Assumed health care cost trend rates have a significant effect 
on the amounts reported for the health care plans. A 1% change in 
assumed health care cost trend rates would have the following 
effects:

- ------------------------------------------------------------------
(Dollars in millions)                1% Increase       1% Decrease
- ------------------------------------------------------------------
Effect on total of service 
  and interest cost components of
  net periodic postretirement 
  health care benefit cost                 $11              $(10)

Effect on the health care component
  of the accumulated postretirement 
  benefit obligation                       $72              $(65)
- ------------------------------------------------------------------

     The projected benefit obligation and accumulated benefit 
obligation were $55 million and $45 million, respectively, as of 
December 31, 1998, and $53 million and $44 million, as of December 
31, 1997. There were no pension plans with accumulated benefit 
obligations in excess of plan assets for 1998 or 1997.
     Other postretirement benefits include medical benefits for 
retirees and their spouses (and Medicare Part B reimbursement for 
certain retirees) and retiree life insurance.

Savings Plans  

Sempra Energy and its subsidiaries 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. Employer contributions, after 
one year of completed service, are made in shares of company 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. During 1998, the 
SDG&E plan contribution was age-based for represented employees. 
The employee's contributions, at the direction of the employees, 
are primarily invested in company stock, mutual funds or guaranteed 
investment contracts. Employer contributions for the Sempra and 
SoCalGas plans are partially funded by the Pacific Enterprises 
Employee Stock Ownership Plan and Trust. Annual expense for the 
savings plans was $14 million in 1998, $11 million in 1997 and $10 
million in 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 ESOP, the ESOP 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 million and 3.3 million shares of 
company common stock, with fair values of $77.9 million and $80.3 
million, at December 31, 1998, and 1997, respectively.


9     STOCK-BASED COMPENSATION

Sempra Energy has stock-based compensation plans that align 
employee and shareholder objectives related to the long-term growth 
of the company. The company's 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.
     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, the company adopted its 
disclosure-only requirements and continues to account for stock-
based compensation in accordance with the provisions of accounting 
Principles Board Opinion No. 25, "Accounting for Stock Issued to 
Employees."
     In 1998, 102,640 shares of Sempra Energy common stock were 
awarded to officers. Under the predecessor plan, in each of the 
last 10 years, Enova awarded between 49,000 and 75,000 shares to 
key executives. These awards are subject to forfeiture over four 
years if certain corporate goals are not met. Holders of this stock 
have voting rights and receive dividends prior to the time the 
restrictions lapse if, and to the extent, dividends are paid on 
Sempra Energy common stock. Compensation expense for the issuance 
of these restricted shares was approximately $2 million in 1998, $1 
million in 1997 and $1 million in 1996.
     In 1998, Sempra Energy granted 3,425,800 stock options. The 
option price is equal to the market price of common stock at the 
date of grant. The grants, which vest over a four-year period, 
include options with and without performance-based features. The 
stock options expire in ten years from the date of grant. All 
options granted prior to 1997 became immediately exercisable upon 
approval by PE's shareholders of the business combination with 
Enova. The options were originally scheduled to vest annually over 
a service period ranging from three to five years.
     Sempra Energy's plans allow for the granting of dividend 
equivalents based upon performance goals. This feature provides 
grantees, upon exercise of the option, with the opportunity to 
receive all or a portion of the cash dividends that would have been 
paid on the shares if the shares had been outstanding since the 
grant date. Dividend equivalents are payable only if corporate 
goals are met and, for grants prior to July 1, 1998, if the 
exercise price exceeds the market value of the shares purchased. 
The percentage of dividends paid as dividend equivalents will 
depend upon the extent to which the performance goals are met. 
     The following information is presented after conversion of PE 
stock into company stock as described in Note 1. 
     Stock option activity is summarized in the following tables.

- -----------------------------------------------------------------
Options With Performance Features
- -----------------------------------------------------------------
                        Shares       Average        Options
                        Under        Exercise      Exercisable
                        Option        Price        at Year End
- -----------------------------------------------------------------
December 31, 1995       846,188       $16.23              _
     Granted          1,030,404        17.95
                     --------------------------------------------
December 31, 1996     1,876,592        17.17         282,063
     Granted          1,040,103        20.37
     Exercised         (359,288)       16.53
     Cancelled          (71,190)       20.37
                     --------------------------------------------
December 31, 1997     2,486,217        18.51       1,513,545
     Granted          2,131,803        25.23
     Exercised         (512,059)       17.12
     Cancelled         (509,301)       23.00
                     --------------------------------------------
December 31, 1998     3,596,660       $22.06       1,387,523
- -----------------------------------------------------------------



- -----------------------------------------------------------------
Options Without Performance Features
- -----------------------------------------------------------------
                        Shares       Average        Options
                        Under        Exercise      Exercisable
                        Option        Price        at Year End
- -----------------------------------------------------------------
December 31, 1995     2,302,018       $18.14       1,200,183
     Exercised         (304,520)       15.00
     Cancelled         (125,417)       26.05
                     --------------------------------------------
December 31, 1996     1,872,081        18.12       1,197,687
     Exercised         (493,848)       14.94
     Cancelled          (14,737)       35.24
                     --------------------------------------------
December 31, 1997     1,363,496        19.08       1,363,496
     Granted          1,293,997        26.33
     Exercised         (596,629)       15.72
     Cancelled         (240,632)       29.78
                     --------------------------------------------
December 31, 1998     1,820,232       $23.92         523,661
- -----------------------------------------------------------------

Additional information on options outstanding at December 31, 1998, 
is as follows:

- -----------------------------------------------------------------
Outstanding Options
- -----------------------------------------------------------------
Range of                 Number        Average         Average
Exercise                     of      Remaining        Exercise
Prices                   Shares           Life           Price
- -----------------------------------------------------------------
$12.80-$16.12            623,362           5.55          $15.29
$16.79-$20.36          1,584,272           7.47          $19.03
$24.10-$31.00          3,209,258           9.05          $25.82
                      ----------
                       5,416,892           8.19          $22.64

- -----------------------------------------------------------------
Exercisable Options
- -----------------------------------------------------------------
Range of                 Number                        Average
Exercise                     of                       Exercise
Prices                   Shares                          Price
- -----------------------------------------------------------------
$12.80-$16.12            623,362                         $15.29
$16.79-$20.36          1,109,878                         $18.46
$24.11-$31.00            177,944                         $26.70
                      ----------
                       1,911,184                         $18.20
- -----------------------------------------------------------------

     The fair value of each option grant (including the dividend 
equivalent) was estimated on the date of grant using the modified 
Black-Scholes option-pricing model. Weighted average fair values 
for options granted in 1998, 1997, and 1996 were $8.20, $5.23 and 
$5.00, respectively.
     The assumptions that were used to determine these fair values 
are as follows:


- -----------------------------------------------------------------
                                  Year Ended December 31
                                  1998     1997     1996
- -----------------------------------------------------------------
Stock price volatility             16%      18%      19%
Risk-free rate of return          5.6%     6.4%     6.1%
Annual dividend yield               0%       0%       0%
Expected life                  6 Years   3.8 Years  4.3 Years
- -----------------------------------------------------------------

     Compensation expense for the stock option grants was $11.7 
million, $16.9 million and $5.5 million in 1998, 1997 and 1996, 
respectively. The differences between compensation cost included in 
net income and the related cost measured by the fair-value-based 
method defined in SFAS No. 123 are immaterial.


10     FINANCIAL INSTRUMENTS

Fair Value  

The fair values of the company's financial instruments (cash, 
temporary investments, funds held in trust, notes receivable, 
investments in limited partnerships, dividends payable, short- and 
long-term debt, customer deposits, and preferred stock of 
subsidiaries) are not materially different from the carrying 
amounts, except for long-term debt and preferred stock of 
subsidiaries. The carrying amounts and fair values of long-term 
debt are $3.1 billion and $3.2 billion, respectively, at December 
31, 1998, and $3.4 billion and $3.5 billion at December 31, 1997. 
The carrying amounts and fair values of subsidiaries' preferred 
stock are $204 million and $182 million, respectively, at December 
31, 1998, and $279 million and $258 million, respectively, at 
December 31, 1997. The fair values of the first-mortgage and other 
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. Included in long-term debt are SDG&E's rate-
reduction bonds. The carrying amounts and fair values of the bonds 
are $592 million and $607 million, respectively, at December 31, 
1998.

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. Additional information on this topic is discussed in 
Note 2.

Swap Agreements  

The company periodically enters into interest-rate-swap and cap 
agreements to moderate exposure to interest-rate changes and to 
lower the overall cost of borrowing. These agreements generally 
remain off the balance sheet as they involve the exchange of fixed- 
and variable-rate interest payments without the exchange of the 
underlying principal amounts. The related gains or losses are 
reflected in the consolidated income statement as part of interest 
expense.
     At December 31, 1998, and 1997, SDG&E had one interest-rate-
swap agreement: a floating-to-fixed-rate swap associated with $45 
million of variable-rate bonds maturing in 2002. SDG&E expects to 
hold this financial instrument to its maturity. This swap agreement 
has effectively fixed the interest rate on the underlying variable-
rate debt at 5.4 percent. SDG&E would be exposed to interest-rate 
fluctuations on the underlying debt should the counterparty to the 
agreement not perform. Such nonperformance is not anticipated. This 
agreement, if terminated, would result in an obligation of $3 
million at December 31, 1998, and $2 million at December 31, 1997. 
Additional information on this topic is included in Note 5.

Energy Derivatives  

Information on derivative financial instruments of SET is provided 
below. The company's regulated operations use energy derivatives 
for both price-risk management and trading purposes within certain 
limitations imposed by company policies and regulatory 
requirements. Energy derivatives are used to mitigate risk and 
better manage costs. These instruments include forward contracts, 
swaps, options and other contracts which have maturities ranging 
from 30 days to 12 months.
     SoCalGas is subject to price risk on its natural gas purchases 
if its cost exceeds a 2-percent tolerance band above the benchmark 
price. This is discussed further in Note 14. SoCalGas becomes 
subject to price risk when positions are incurred during the 
buying, selling and storage of natural gas. As a result of the Gas 
Cost Incentive Mechanism (GCIM), SoCalGas enters into a certain 
amount of gas futures contracts in the open market with the intent 
of reducing gas costs within the GCIM tolerance band. The CPUC has 
approved the use of 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. These 
instruments are included in other current assets on the 
Consolidated Balance Sheet. Certain instruments such as swaps are 
entered into and closed out within the same month and, therefore, 
do not have any balance-sheet impact. Gains and losses are included 
in electric or natural gas revenue or expense, whichever is 
appropriate, in the Consolidated Income Statements.
     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
- -----------------------------------------------------------------




11     PREFERRED STOCK OF SUBSIDIARIES

- -----------------------------------------------------------------
Pacific Enterprises                       Call       December 31,
(Dollars in millions except call price)   Price     1998     1997
- -----------------------------------------------------------------
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 
price 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. No shares of 
Unclassified or Class A preferred stock are outstanding.

- -----------------------------------------------------------------
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.



- -----------------------------------------------------------------
SDG&E                                      Call      December 31,
(Dollars in millions except call price)   Price     1998     1997
- -----------------------------------------------------------------
Not subject to mandatory redemption
  $20 par value, authorized 
    1,375,000 shares:
       5% Series, 375,000 
         shares outstanding              $24.00       $8      $8
       4.50% Series, 300,000 
         shares outstanding              $21.20        6       6 
       4.40% Series, 325,000 
         shares outstanding              $21.00        7       7
       4.60% Series, 373,770 
         shares outstanding              $20.25        7       7 
  Without par value: 
       $1.70 Series, 1,400,000 
         shares outstanding              $25.85       35      35
       $1.82 Series, 640,000
         shares outstanding              $26.00       16      16
                                                   --------------
   Total not subject to
     mandatory redemption                            $79     $79
                                                   --------------
Subject to mandatory redemption
  Without par value:  
       $1.7625 Series, 1,000,000 
         shares outstanding              $25.00      $25     $25
- -----------------------------------------------------------------

     All series of SDG&E's preferred stock have cumulative 
preferences as to dividends. The $20 par value preferred stock has 
two votes per share on matters being voted upon by shareholders of 
SDG&E and a liquidation value at par, whereas the no-par-value 
preferred stock is nonvoting and has a liquidation value of $25 per 
share. SDG&E is authorized to issue 10,000,000 shares of no-par-
value stock (both subject to and not subject to mandatory 
redemption). All series are currently callable except for the $1.70 
and $1.7625 series (callable in 2003). The $1.7625 series has a 
sinking fund requirement to redeem 50,000 shares per year from 2003 
to 2007; the remaining 750,000 shares must be redeemed in 2008.




12     SHAREHOLDERS EQUITY AND EARNINGS PER SHARE

The company's outstanding stock options represent the only forms of 
potential common stock at December 31, 1998, 1997 and 1996. The 
reconciliation between basic and diluted EPS is as follows:

- -----------------------------------------------------------------
                       Income           Shares           Earnings
                   (in millions)     (in thousands)     Per Share
- -----------------------------------------------------------------
1998:
Basic                    $294           236,423           $1.24  
Effect of dilutive 
  stock options                             701
- -----------------------------------------------------------------
Diluted                  $294           237,124           $1.24
- -----------------------------------------------------------------
1997:
Basic                    $432           236,662           $1.83
Effect of dilutive 
  stock options                             587
- -----------------------------------------------------------------
Diluted                  $432           237,249           $1.82
- -----------------------------------------------------------------
1996:
Basic                    $427           240,825           $1.77
Effect of dilutive 
  stock options                             332
- -----------------------------------------------------------------
Diluted                  $427           241,157           $1.77
- -----------------------------------------------------------------

     The company is authorized to issue 750,000,000 shares of no 
par value common stock and 50,000,000 shares of Preferred Stock. At 
December 31, 1998, there were 240,026,439 shares of common stock 
outstanding, compared to 235,598,111 shares outstanding at December 
31, 1997. No shares of Preferred Stock were issued and outstanding.


13     COMMITMENTS AND CONTINGENCIES

Natural Gas Contracts  

The company 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.
     SDG&E has long-term capacity contracts with interstate 
pipelines which expire on various dates between 2007 and 2023. 
SDG&E has long-term natural gas supply contracts (included in the 
table below) with four Canadian suppliers that expire between 2001 
and 2004. SDG&E has been involved in negotiations and litigation 
with the suppliers concerning the contracts' terms and prices. 
SDG&E has settled with three of the suppliers. One of the three is 
delivering natural gas under the terms of the settlement agreement; 
the other two have ceased deliveries. The fourth supplier has 
ceased deliveries pending legal resolution. A U.S. Court of Appeal 
has upheld a U.S. District Court's invalidation of the contracts 
with two of these suppliers. If the supply of Canadian natural gas 
to SDG&E is not resumed to a level approximating the related 
committed long-term pipeline capacity, SDG&E intends to continue 
using the capacity in other ways, including the transport of 
replacement gas and the release of a portion of this capacity to 
third parties.
     At December 31, 1998, the future minimum payments under 
natural gas contracts were:

- -----------------------------------------------------------------
                               Storage and
(Dollars in millions)       Transportation          Natural Gas 
- -----------------------------------------------------------------
1999                                $193                $288
2000                                 195                 170
2001                                 197                 175
2002                                 197                 179
2003                                 193                 181
Thereafter                           587                   _
                               ----------------------------------
Total minimum payments            $1,562                $993
- -----------------------------------------------------------------

     Total payments under the short-term and long-term contracts 
were $1.0 billion in 1998, $1.2 billion in 1997, and $1.0 billion 
in 1996.
     All of SDG&E's gas is delivered through SoCalGas pipelines 
under a short-term transportation agreement. In addition, SoCalGas 
provides SDG&E six billion cubic feet of natural gas storage 
capacity under an agreement expiring March 2000. These agreements 
are not included in the above table.

Purchased-Power Contracts  

SDG&E buys electric power under several long-term contracts. The 
contracts expire on various dates between 1999 and 2025. Under 
California's Electric Industry Restructuring law, which is 
described in Note 14, the California investor-owned electric 
utilities (IOUs) are obligated to bid their power supply, including 
owned generation and purchased-power contracts, into the California 
Power Exchange (PX). As a result, SDG&E's system requirements are 
met primarily through purchases from the PX.
     At December 31, 1998, the estimated future minimum payments 
under the long-term contracts were:

- -----------------------------------------------------------------
(Dollars in millions)
- -----------------------------------------------------------------
1999                                                      $249
2000                                                       211
2001                                                       174
2002                                                       136
2003                                                       135
Thereafter                                               2,001
                                                       ----------
Total minimum payments                                  $2,906
- -----------------------------------------------------------------

     These payments for actual purchases represent capacity charges 
and minimum energy purchases. SDG&E is required to pay additional 
amounts for actual purchases of energy that exceed the minimum 
energy commitments. Total payments, including actual energy 
payments, under the contracts were $293 million in 1998, $421 
million in 1997 and $296 million in 1996. Payments under purchased-
power contracts decreased in 1998 as a result of the purchases from 
the PX, which commenced April 1, 1998.
     SDG&E has entered into agreements to sell its power plants and 
other electric-generating resources (excluding SONGS), and has 
announced a plan to auction its long-term purchased power 
contracts. Additional information on this topic is provided in Note 
14.

Leases  

The company has leases (primarily operating) on real and personal 
property expiring at various dates from 1999 to 2030. Certain 
leases on office facilities contain escalation clauses requiring 
annual increases in rent ranging from 2 percent to 7 percent. 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 the company. The company also has nuclear fuel, 
office buildings, a generating facility and other properties that 
are financed by long-term capital leases. Utility plant includes 
$177 million at December 31, 1998, and $198 million at December 31, 
1997, related to these leases. The associated accumulated 
amortization is $114 million and $102 million, respectively.
     The minimum rental commitments payable in future years under 
all noncancellable leases are:

- -----------------------------------------------------------------
                                     Operating     Capitalized
(Dollars in millions)                   Leases          Leases
- -----------------------------------------------------------------
1999                                     $60             $31
2000                                      58              14
2001                                      55              14
2002                                      52              14
2003                                      51              11
Thereafter                               380               9
                                   ------------------------------
Total future rental commitment          $656              93
Imputed interest (6% to 9%)                              (17)
                                                      -----------
Net commitment                                           $76
- -----------------------------------------------------------------

     Rent expense totaled $105 million in 1998, $137 million in 
1997 and $146 million in 1996.
     In connection with the quasi-reorganization described in Note 
2, 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.

Environmental Issues  

The company 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 and SDG&E incur significant 
costs to operate their 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. Environmental 
liabilities that may arise are recorded when remedial efforts are 
probable and the costs can be estimated.
     The company's capital expenditures to comply with 
environmental laws and regulations were $1 million in 1998, $5 
million in 1997, and $9 million in 1996, and are not expected to be 
significant during the next five years. These expenditures 
primarily include the cost of retrofitting SDG&E's power plants to 
reduce air emissions. These costs will be reduced significantly by 
SDG&E's sale of its non-nuclear generating facilities. The company 
has been associated with various sites which may require 
remediation under federal, state or local environmental laws. The 
company 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.
     As discussed in Note 14, restructuring of the California 
electric-utility industry will change the way utility rates are set 
and costs are recovered. SDG&E asked that the collaborative account 
be modified, and that electric generation-related cleanup costs be 
eligible for transition-cost recovery. The final outcome of this 
decision is that SDG&E's costs of compliance with environmental 
regulations may be fully recoverable.

Nuclear Insurance  

SDG&E and the co-owners of SONGS have purchased primary insurance 
of $200 million, the maximum amount available, for public-liability 
claims. An additional $8.7 billion of coverage is provided by 
secondary financial protection required by the Nuclear Regulatory 
Commission and provides for loss sharing among utilities owning 
nuclear reactors if a costly accident occurs. SDG&E could be 
assessed retrospective premium adjustments of up to $32 million in 
the event of a nuclear incident involving any of the licensed, 
commercial reactors in the United States, if the amount of the loss 
exceeds $200 million. In the event the public-liability limit 
stated above is insufficient, the Price-Anderson Act provides for 
Congress to enact further revenue-raising measures to pay claims, 
which could include an additional assessment on all licensed 
reactor operators.
     Insurance coverage is provided for up to $2.8 billion of 
property damage and decontamination liability. Coverage is also 
provided for the cost of replacement power, which includes 
indemnity payments for up to three years, after a waiting period of 
17 weeks. Coverage is provided primarily through mutual insurance 
companies owned by utilities with nuclear facilities. If losses at 
any of the nuclear facilities covered by the risk-sharing 
arrangements were to exceed the accumulated funds available from 
these insurance programs, SDG&E could be assessed retrospective 
premium adjustments of up to $6 million.



Department of Energy Decommissioning  

The Energy Policy Act of 1992 established a fund for the 
decontamination and decommissioning of the Department of Energy 
nuclear-fuel-enrichment facilities. Utilities which have used DOE 
enrichment services are being assessed a total of $2.3 billion, 
subject to adjustment for inflation, over a 15-year period ending 
in 2006. Each utility's share is based on its share of enrichment 
services purchased from the DOE through 1992. SDG&E's annual 
assessment is approximately $1 million. This assessment is 
recovered through SONGS revenue.

Litigation  

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

Electric Distribution System Conversion  

Under a CPUC-mandated program and through franchise agreements with 
various cities, SDG&E is committed, in varying amounts, to 
converting overhead distribution facilities to underground. As of 
December 31, 1998, the aggregate unexpended amount of this 
commitment was approximately $104 million. Capital expenditures for 
underground conversions were $17 million in 1998, $17 million in 
1997, and $15 million in 1996.

Concentration of Credit Risk  

The company 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. SDG&E and SoCalGas grant 
credit to their utility customers, substantially all of whom are 
located in their service territories, which together cover most of 
Southern California and a portion of central California.
     SET monitors and controls its credit-risk exposures through 
various systems which evaluate its credit risk, and through credit 
approvals and limits. To manage the level of credit risk, SET deals 
with a majority of counterparties with good credit standing, enters 
into master netting arrangements whenever possible and, where 
appropriate, obtains collateral. Master netting agreements 
incorporate rights of setoff that provide for the net settlement of 
subject contracts with the same counterparty in the event of 
default. 


14     REGULATORY MATTERS

Electric-Industry Restructuring  

In September 1996, California enacted a law restructuring its 
electric-utility industry (AB 1890). The legislation adopts the 
December 1995 CPUC policy decision restructuring the industry to 
stimulate competition and reduce rates.
     Beginning on March 31, 1998, customers were given the 
opportunity to choose to continue to purchase their electricity 
from the local utility under regulated tariffs, to enter into 
contracts with other energy-service providers (direct access) or to 
buy their power from the independent Power Exchange (PX) that 
serves as a wholesale power pool allowing all energy producers to 
participate competitively. The PX obtains its power from qualifying 
facilities, from nuclear units and, lastly, from the lowest-bidding 
suppliers. The California investor-owned electric utilities (IOUs) 
are obligated to sell their power supply, including owned-
generation and purchased-power contracts, to the PX. The IOUs are 
also obligated to purchase from the PX the power that they 
distribute. An Independent System Operator (ISO) schedules power 
transactions and access to the transmission system. The local 
utility continues to provide distribution service regardless of 
which source the consumer chooses. An example of these changes in 
the electric-utility environment is the U.S. Navy, SDG&E's largest 
customer. The U.S. Navy's contract to purchase energy from SDG&E 
was not renewed when it expired on September 30, 1998. Instead, the 
U.S. Navy elected to obtain energy through direct access and SDG&E 
continues to provide the distribution service.
     Utilities are allowed a reasonable opportunity to recover 
their stranded costs via a competition transition charge (CTC) to 
customers through December 31, 2001. Stranded costs include sunk 
costs, as well as ongoing costs the CPUC finds reasonable and 
necessary to maintain generation facilities through December 31, 
2001. These costs also include other items SDG&E has recorded under 
traditional cost-of-service regulation. Certain stranded costs, 
such as those related to reasonable employee-related costs directly 
caused by restructuring, and purchased-power contracts (including 
those with qualifying facilities) may be recovered beyond December 
31, 2001. To the extent that the opportunity to recover stranded 
costs is reduced by the costs to accommodate the implementation of 
direct access and the ISO/PX during the rate freeze, those 
displaced stranded costs may be recovered after December 31, 2001. 
Outside of those exceptions, stranded costs not recovered through 
2001 will not be collected from customers. Such costs, if any, 
would be written off as a charge against earnings. Nuclear 
decommissioning costs are nonbypassable until fully recovered, but 
are not included as part of transition costs. Additional 
information is provided in Note 10.
     Through December 31, 1998, SDG&E has recovered transition 
costs of $500 million for nuclear generation and $200 million for 
non-nuclear generation. Excluding the costs of purchased power and 
other costs whose recovery is not limited to the pre-2002 period, 
the balance of SDG&E's stranded assets at December 31, 1998, is 
$600 million, consisting of $400 million for the power plants and 
$200 million of related deferred taxes and undercollections.
     In November 1997, SDG&E announced a plan to auction its power 
plants and other electric-generating assets. This plan includes the 
divestiture of SDG&E's fossil power plants and combustion turbines, 
its 20-percent interest in SONGS and its portfolio of long-term 
purchased-power contracts. The power plants, including the interest 
in SONGS, have a net book value as of December 31, 1998, of $400 
million ($100 million for fossil and $300 million for SONGS) and a 
combined generating capacity of 2,400 megawatts. The proceeds from 
the sales, net of the costs of the sales and certain environmental 
cleanup costs, will be applied directly to SDG&E's transition 
costs. The fossil-fuel assets' auction is being separated from the 
auction of SONGS and the purchased-power contracts. In October 1998 
the CPUC issued an interim decision approving the commencement of 
the fossil fuel assets' auction. 
     On December 11, 1998, contracts were executed for the sale of 
SDG&E's South Bay Power Plant, Encina Power Plant and 17 
combustion-turbine generators. The South Bay Power Plant is being 
sold to the San Diego Unified Port District for $110 million. The 
Encina Power Plant and the combustion-turbine generators are being 
sold to a special-purpose entity owned equally by Dynegy Power 
Corp. and NRG Energy, Inc. for $356 million. The sales are subject 
to regulatory approval and are expected to close during the first 
half of 1999.
     During the 1998-2001 period, recovery of transition costs is 
limited by the rate freeze discussed below. Management believes 
that rates and the proceeds from the sale of electric-generating 
assets will be sufficient to recover all of SDG&E's approved 
transition costs by December 31, 2001, not including the post-2001 
purchased-power contracts payments that may be recovered after 
2001. However, if 1998-2001 generation costs, principally fuel 
costs, are greater than anticipated, SDG&E may be unable to recover 
all of its approved transition costs. This would result in a charge 
against earnings at the time it ceases to be probable that SDG&E 
will be able to recover all of the transition costs.
     AB 1890 requires a 10-percent reduction of residential and 
small commercial customers' rates, beginning in January 1998, and 
provides for the issuance of rate-reduction bonds by an agency of 
the state of California to enable the IOUs to achieve this rate 
reduction. In December 1997, $658 million of rate-reduction bonds 
were issued on behalf of SDG&E at an average interest rate of 6.26 
percent. These bonds are being repaid over 10 years by SDG&E's 
residential and small commercial customers via a nonbypassable 
charge on their electric bills. In 1997, SDG&E formed a subsidiary, 
SDG&E Funding LLC, to facilitate the issuance of the bonds. In 
exchange for the bond proceeds, SDG&E sold to SDG&E Funding LLC all 
of its rights to certain revenue streams collected from such 
customers. Consequently, the transaction is structured to cause 
such revenue streams not to be the property of SDG&E nor to be 
available to satisfy any claims of SDG&E's creditors.
     AB 1890 includes a rate freeze for all electric customers. 
Until the earlier of March 31, 2002, or when transition-cost 
recovery is complete, SDG&E's system-average rate will be frozen at 
the June 10, 1996, levels of 9.64 cents per kwh, except for the 
impact of fuel-cost changes and the 10-percent rate reduction 
described above. Beginning in 1998, system-average rates were fixed 
at 9.43 cents per kwh, which includes the maximum permitted 
increase related to fuel-cost increases and the mandatory rate 
reduction. 
     In early 1999, SDG&E filed with the CPUC for an interim 
mechanism to deal with electric rates after the rate freeze ends, 
noting the possibility that the SDG&E rate freeze could end in 
1999.
     As discussed in Note 2, SDG&E has been accounting for the 
economic effects of regulation in accordance with SFAS No. 71. The 
SEC indicated a concern that California's investor-owned utilities 
(IOUs) may not meet the criteria of SFAS No. 71 with respect to 
their electric-generation regulatory assets. SDG&E has ceased the 
application of SFAS No. 71 to its generation business, in 
accordance with the conclusion of the Emerging Issues Task Force of 
the Financial Accounting Standards Board that the application of 
SFAS 71 should be discontinued when legislation is issued that 
determines that a portion of an entity's business will no longer be 
subject to traditional cost-of-service regulation. The 
discontinuance of SFAS No. 71 applied to the IOUs' generation 
business did not result in a write-off of their net regulatory 
assets since the CPUC has approved the recovery of these assets by 
the distribution portion of their operations, subject to the rate 
freeze.
     In October 1997, the FERC approved key elements of the 
California IOUs' restructuring proposal. This included the transfer 
by the IOUs of the operational control of their transmission 
facilities to the ISO, which is under FERC jurisdiction. The FERC 
also approved the establishment of the California PX to operate as 
an independent wholesale power pool. The IOUs pay to the PX an 
upfront restructuring charge (in four annual installments) and an 
administrative-usage charge for each megawatt hour of volume 
transacted. SDG&E's share of the restructuring charge is 
approximately $10 million, which is being recovered as a transition 
cost. The IOUs have guaranteed $300 million of commercial loans to 
the ISO and PX for their development and initial start-up. SDG&E's 
share of the guarantee is $30 million.
     Thus far, electric-industry deregulation has been confined to 
generation. Transmission and distribution have remained subject to 
traditional cost-of-service regulation. However, the CPUC is 
exploring the possibility of opening up electric distribution to 
competition. During 1999, the CPUC will be conducting a rulemaking, 
one objective of which may be to develop a coordinated proposal for 
the state legislature regarding how various distribution 
competition issues should be addressed. SDG&E and SoCalGas will 
actively participate in this effort.

Gas Industry Restructuring  

The natural gas industry experienced an initial phase of 
restructuring during the 1980s by deregulating 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 implementation 
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. SDG&E and 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 both 
SoCalGas and SDG&E. 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.
     SDG&E continues to participate in a PBR process for base rates 
for its electric and natural gas distribution business. In 
conjunction therewith, in December 1998, a Cost of Service 
settlement agreement among SDG&E, the CPUC's Office of Ratepayers' 
Advocates (ORA) and the Utility Consumers' Action Network (UCAN) 
was approved by the CPUC, resulting in an authorized revenue 
increase of $12 million (an electric-distribution increase of $18 
million and a natural gas decrease of $6 million). The electric-
distribution increase does not affect rates during the rate freeze 
and, therefore, reduces the amount available for transition cost 
recovery. Revised rates were effective January 1, 1999.
     In January 1999, an administrative law judge's proposed 
decision was issued on SDG&E's distribution PBR application. The 
proposed decision recommends a revenue-per-customer indexing 
mechanism (similar to the indexing mechanism in SoCalGas' PBR) 
rather than the rate-indexing mechanism proposed by SDG&E. In 
addition, the proposed decision recommends much tighter earnings 
sharing bands (similar to SoCalGas'). The performance indicators 
are as adopted in the settlement agreement, including employee 
safety, electric reliability, customer satisfaction, call-center 
responsiveness and electric-system maintenance. SDG&E would be 
authorized to earn or be penalized up to a maximum of $14.5 million 
annually as a result of its performance in those areas. 

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 and SDG&E 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' and SDG&E's PBRs. The applications seek 
overall decreases in natural gas revenues of $204 million for 
SoCalGas and $9 million for SDG&E.

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 (ROE) of 11.6 percent and a 9.49 
percent return on rate base (ROR), the same as in 1998, unless 
interest-rate changes are large enough to trigger an automatic 
adjustment as discussed above under "Performance-Based Regulation." 
For SDG&E, electric-industry restructuring is changing the method 
of calculating the utility's annual cost of capital. In May 1998, 
SDG&E filed with the CPUC its unbundled Cost of Capital application 
for 1999 rates. The application seeks approval to establish new, 
separate rates of return for SDG&E's electric-distribution and 
natural gas businesses. The application proposes a 12.00 percent 
ROE, which would produce an overall ROR of 9.33 percent. The ORA, 
UCAN and other intervenors have filed testimony recommending 
significantly lower RORs. The ORA is recommending an electric ROR 
of 7.68 percent and a gas ROR of 8.01 percent. A CPUC decision is 
expected during the second quarter of 1999. In 1998, SDG&E's 
electric and natural gas distribution operations were authorized to 
earn an ROE of 11.6 percent and an ROR of 9.35 percent, unchanged 
from 1997. In addition, the authorized rates of return on nuclear 
and non-nuclear generating assets are 7.14 percent and 6.75 
percent, respectively.

Transactions Between Utilities and Affiliated Companies  

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).


15     SEGMENT INFORMATION

The company, primarily an energy-services company, has three 
separately managed reportable segments comprised of SoCalGas, SDG&E 
and Sempra Energy Trading (SET). The two utilities operate in 
essentially separate service territories under separate regulatory 
frameworks and rate structures set by the CPUC. As described in 
Note 1, SDG&E provides electric and natural gas service to San 
Diego and southern Orange counties. 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 
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 generally are 
recorded the same as sales or transactions with third parties. 
Utility transactions are primarily based on rates set by the CPUC 
and FERC.

- -----------------------------------------------------------------
                                   For the year ended December 31
(Dollars in millions)                   1998     1997     1996
- -----------------------------------------------------------------
Operating Revenues:
  Southern California Gas           $2,427     $2,641     $2,422
  San Diego Gas & Electric           2,749      2,167      1,939
  Sempra Energy Trading                110          _          _
  Intersegment revenues                (59)       (55)       (60)
  All other                            254        316        195
                                   ------------------------------
    Total                           $5,481     $5,069     $4,496
                                   ------------------------------
Interest Revenue:
  Southern California Gas               $4        $16         $5
  San Diego Gas & Electric              40          9          7
  Sempra Energy Trading                  3          _          _
  All other interest                     3         21         23
                                   ------------------------------
    Total interest                      50         46         35
  Sundry income (loss)                  (6)        12         (7)
                                   ------------------------------
    Total other income                 $44        $58        $28
                                   ------------------------------
Depreciation and Amortization:
  Southern California Gas             $254       $251       $248
  San Diego Gas & Electric          
    (See Note 14)                      603        324        314
  Sempra Energy Trading                 13          _          _
  All other                             59         29         25
                                   ------------------------------
    Total                             $929       $604       $587
                                   ------------------------------
Interest Expense:
  Southern California Gas              $80        $87        $86
  San Diego Gas & Electric             116         86         91
  Sempra Energy Trading                  5          _          _
  All other                              6         33         23
                                   ------------------------------
    Total                             $207       $206       $200
                                   ------------------------------
Income Tax Expense (Benefit):
  Southern California Gas             $128       $178       $148
  San Diego Gas & Electric             142        219        198
  Sempra Energy Trading                 (9)         _          _
  All other                           (123)       (96)       (46)
                                   ------------------------------
    Total                             $138       $301       $300
                                   ------------------------------
Net Income:
  Southern California Gas             $158       $231       $193
  San Diego Gas & Electric             185        232        216
  Sempra Energy Trading                (13)         _          _
  All other                            (36)       (31)        18
                                   ------------------------------
    Total                             $294       $432       $427
                                   ------------------------------

- -----------------------------------------------------------------
                                       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
  San Diego Gas & Electric           4,257      4,654      4,161
  Sempra Energy Trading              1,225        846          _
  All other                          1,253      1,181      1,257
  Eliminations                        (113)      (130)       (10)
                                   ------------------------------
    Total                          $10,456    $10,756     $9,762
                                   ------------------------------
Capital Expenditures:
  Southern California Gas             $128       $159       $197
  San Diego Gas & Electric             227        197        209
  Sempra Energy Trading                  _          _          _
  All other                             83         41          7
                                   ------------------------------
    Total                             $438       $397       $413
                                   ------------------------------


Geographic Information:
  Long-lived assets:
    United States                   $5,849     $5,904     $6,647
    Latin America                      140         67         50
                                   ------------------------------
      Total                         $5,989     $5,971     $6,697
                                   ------------------------------
Operating Revenues:
    United States                   $5,474     $5,058     $4,488
    Latin America                        7         11          8
                                   ------------------------------
      Total                         $5,481     $5,069     $4,496
- -----------------------------------------------------------------


16     SUBSEQUENT EVENT

On February 22, 1999, the company and KN Energy, Inc. (KN Energy) 
announced that their respective boards of directors approved the 
company'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 company 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.







Sempra Energy
Quarterly Financial Data (unaudited)

                                                                          Quarter ended
                                                     -------------------------------------------------------
                                                       March 31     June 30     September 30     December 31
Dollars in millions except per share amounts                                                                    
- ------------------------------------------------------------------------------------------------------------
                                                                                      
1998
Revenues and other income                              $  1,350    $  1,335         $  1,398        $  1,442
Operating expenses                                        1,164       1,249            1,192           1,281
                                                       -----------------------------------------------------
Operating income                                       $    186    $     86         $    206        $    161
                                                       -----------------------------------------------------
Net income                                             $     87    $     31         $     91        $     85
Average common shares outstanding (diluted)               236.4       236.9            237.4           237.6
Net income per common share (diluted)                  $   0.37    $   0.13         $   0.38        $   0.36

1997
Revenues and other income                              $  1,301    $  1,130         $  1,251        $  1,445
Operating expenses                                        1,093         878            1,018           1,199
                                                       -----------------------------------------------------
Operating income                                       $    208    $    252         $    233        $    246
                                                       -----------------------------------------------------
Net income                                             $     98    $    112         $    102        $    120
Average common shares outstanding (diluted)               239.2       236.3            236.2           236.6
Net income per common share (diluted)                  $   0.41    $   0.47         $   0.43        $   0.51
- ------------------------------------------------------------------------------------------------------------






Quarterly Common Stock Data (unaudited)

                                                  1998                                  1997
                                 --------------------------------------------------------------------------
                                   First    Second    Third    Fourth    First    Second    Third    Fourth
                                  Quarter  Quarter   Quarter  Quarter   Quarter  Quarter   Quarter  Quarter
- -----------------------------------------------------------------------------------------------------------
                                                                           
Market price
    High                             *        *       28       29 5/16      *        *        *       *    
    Low                              *        *       23 3/4   24 9/16      *        *        *       *    
Dividends declared(1)               $0.32    $0.46   $0.39    $0.39        $0.31    $0.45    $0.19   $0.32
- -----------------------------------------------------------------------------------------------------------


*Not presented as the formation of Sempra Energy was not completed until June 26, 1998.

(1) Prior to the formation of Sempra Energy on June 26, 1998, dividends declared represents the sum of 
dividends declared by Pacific Enterprises and Enova Corporation, divided by the sum of the combining 
companies' shares after the conversion of PE's shares into Sempra Energy shares as described in Note 1 to 
the notes to Consolidated Financial Statements.






 
                               EXHIBIT 12.1 
                      SAN DIEGO GAS & ELECTRIC COMPANY 
         COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES 
                       AND PREFERRED STOCK DIVIDENDS 
                          (Dollars in thousands)

                             1994     1995     1996     1997     1998*    1998**
                           -------- -------- -------- -------- --------- ----------
                                                              
Fixed Charges: 
 
Interest:
  Long-Term Debt           $ 81,749 $ 82,591 $ 76,463 $ 69,546  $ 54,664   $ 54,664
  Short-Term Debt             8,894   17,886   12,635   13,825    12,933     12,933
  Rate Reduction Bonds           --       --       --       --        --     40,912
Amortization of Debt
 Discount and Expense,
 Less Premium                 4,604    4,870    4,881    5,154     7,749      7,749
Interest Portion of 
 Annual Rentals               9,496    9,631    8,446    9,496     8,250      8,250
                           -------- -------- -------- -------- --------- ----------
   Total Fixed 
    Charges                 104,743  114,978  102,425   98,021    83,596    124,508
                           -------- -------- -------- -------- --------- ----------
Preferred Dividends    
 Requirements                 7,663    7,663    6,582    6,582     6,582      6,582
Ratio of Income Before 
 Tax to Net Income          1.83501  1.78991  1.88864  1.91993   1.73993    1.73993
                           -------- -------- -------- -------- --------- ----------
Preferred Dividends 
 for Purpose of Ratio        14,062   13,716   12,431   12,637    11,452     11,452
                           -------- -------- -------- -------- --------- ----------
 Total Fixed Charges
  and Preferred 
  Dividends for
  Purpose of Ratio         $118,805 $128,694 $114,856 $110,658  $ 95,048   $135,960
                           ======== ======== ======== ======== ========= ==========
Earnings:

Net Income (before
 preferred dividend 
 requirements)             $206,296 $219,049 $222,765 $238,232  $191,204   $191,204
Add: 
 Fixed Charges 
  (from above)              104,743  114,978  102,425   98,021    83,596    124,508
 Less: Fixed Charges 
  Capitalized                 1,424    2,040    1,495    2,052       846        846
Taxes on Income             172,259  173,029  197,958  219,156   141,477    141,477
                           -------- -------- -------- -------- --------- ----------
 Total Earnings for 
  Purpose of Ratio         $481,874 $505,016 $521,653 $553,357  $415,431   $456,343
                           ======== ======== ======== ======== ========= ==========
Ratio of Earnings 
 to Combined Fixed 
 Charges and Preferred 
 Dividends                     4.06     3.92     4.54     5.00      4.37       3.36
                           ======== ======== ======== ======== ========= ==========

*  Not including interest for rate reduction bonds.
** Including interest for rate reduction bonds.



  

       
UT 1,000,000 YEAR DEC-31-1998 DEC-31-1998 PER-BOOK 5,252 737 2,458 980 1,029 10,456 1,883 0 1,030 2,913 25 179 2,795 43 0 0 330 0 0 0 4,171 10,456 5,481 138 4,886 5,024 457 44 501 207 294 0 294 376 0 1,323 1.24 1.24 PREFERRED DIVIDEND OF SUBSIDIARY INCLUDED IN OTHER OPERATING EXPENSE
Exhibit 10.1
AMENDMENT TO EMPLOYMENT AGREEMENT 
 
By this Agreement, Sempra Energy (the "Company"),  a California  
corporation formerly known as Mineral Energy Company, and STEPHEN BAUM  
(the "Executive") amend the Employment Agreement (the "Agreement")  
between Mineral Energy Company and Executive dated October 12, 1996, to  
be effective December 1, 1998, as follows: 
 
1.	Paragraph 4 (d) (iii) of the Agreement is stricken and replaced  
with the following language: 
 
"(iii)	the relocation of the Executive's principal place of  
employment to a location away from the Company's headquarters or a  
relocation of the Company's headquarters to a location further away  
which is both further away from Executive's residence and more than  
thirty (30) miles from such headquarters or a substantial increase in  
the Executive's business travel obligations outside of the Southern  
California area as of the Effective Date other than any such increase  
that (A) arises in connection with extraordinary business activities of  
the Company and (B) is understood not to be part of the Executive's  
regular duties with the Company;" 
2.	Paragraph 5 (a) (vi) of the Agreement is modified in its opening  
phrase to read: 
 
		"(vi)	Continuation of Welfare Benefits.  For a period of  
three (3) years or until the Executive is eligible for retiree medical  
benefits, whichever is longer, ..." 
 
3.	Paragraphs 5 (d), (e) and (f) of the Agreement are stricken and  
replaced by the following: 
 
"(d)   Code Section 280G 
(i)	Gross-Up.  Notwithstanding any other provisions of this Agreement,  
in the event that any payment or benefit received or to be received by  
the Executive (whether pursuant to the terms of this Agreement or any  
other plan, arrangement or agreement with (A) the Company, (B) any  
Person (as defined in Section 4(e))whose actions result in a Change in  
Control or (C) any Person affiliated with the Company or such Person)  
(all such payments and benefits, including the Severance Payments, being  
hereinafter called the "Total Payments") would be subject (in whole or  
part) to the tax (the "Excise Tax") imposed under section 4999 of the  
Code, the Company shall pay to the Executive such additional amounts  
(the "Gross-Up Payment") such that the net amount retained by the  
Executive, after deduction of any Excise Tax on the Total Payments and  
any federal, state and local income and employment taxes and Excise Tax  
upon the Gross-Up Payment, shall be equal to the Total Payments.  For  
purposes of determining the amount of the Gross-Up Payment, the  
Executive shall be deemed to pay federal income tax at the highest  
marginal rate of federal income taxation in the calendar year in which  
the Gross-Up Payment is to be made and state and local income taxes at  
the highest marginal rate of taxation in the state and locality of the  
Executive's residence on the date on which the Gross-Up Payment is  
calculated for purposes of this section, net of the maximum reduction in  
federal income taxes which could be obtained from deduction of such  
state and local taxes.  In the event that the Excise Tax is subsequently  
determined to be less than the amount taken into account hereunder, the  
Executive shall repay to the Company, at the time that the amount of  
such reduction in Excise Tax is finally determined, the portion of the  
Gross-Up Payment attributable to such reduction (plus that portion of  
the Gross-Up Payment attributable to the Excise Tax and federal, state  
and local income tax imposed on the Gross-Up Payment being repaid by the  
Executive to the extent that such repayment results in a reduction in  
Excise Tax and/or a federal, state or local income tax deduction) plus  
interest on the amount of such repayment at the rate provided in section  
1274(b)(2)(B) of the Code.  In the event that the Excise Tax is  
determined to exceed the amount taken into account hereunder (including  
by reason of any payment the existence or amount of which cannot be  
determined at the time of the Gross-Up Payment), the Company shall make  
an additional Gross-Up Payment in respect of such excess (plus any  
interest, penalties or additions payable by the Executive with respect  
to such excess) at the time that the amount of such excess is finally  
determined.  The Executive and the Company shall each reasonably  
cooperate with the other in connection with any administrative or  
judicial proceedings concerning the existence or amount of liability for  
Excise Tax with respect to the Total Payments. 
(ii)	Accounting Firm.  All determinations to be made with respect to  
this Section 5 (d) shall be made by the Company's independent accounting  
firm (or, in the case of a payment following a Change in Control, the  
accounting firm that was, immediately prior to the Change in Control,  
the Company's independent auditor).  The accounting firm shall be paid  
by the Company for its services performed hereunder." 
  
4.	Sections 5 (e) and (f) of the Agreement are added to read: 
 
"(e)	Outplacement Services.  The Executive shall receive  
outplacement services suitable to his or her position for a period of  
eighteen (18) months following the Date of Termination, or if earlier,  
until the first acceptance of an offer of employment with a subsequent  
employer, in an aggregate amount not to exceed $50,000. 
(f)	Financial Planning Services.  The Executive shall  
receive financial planning services for a period of eighteen (18) months  
following the Date of Termination at a level consistent with the  
benefits provided under the Company's financial planning program for the  
Executive, as in effect immediately prior to the Date of Termination." 
5.	Section 5(h) of the Agreement is added to read: 
 
	(h)	Notwithstanding anything contained herein, if a Change in  
Control occurs and if, prior to the date of the Change in Control, the  
Executive's employment is terminated by the Company (other than for  
Cause, death or Disability), or by the Executive for Good Reason, and if  
such Termination (i) was at the request of a third party who has taken  
steps reasonably calculated to effect the Change in Control or (ii)  
otherwise arose in connection with or in anticipation of the Change in  
Control, then such Termination shall be treated as a Termination  
following a Change in Control for purposes of this Agreement (including,  
without limitation, for purposes of determining the amounts of the  
Severance Payments under this Section 5). 
 
 
6.	Paragraph 8 ("Arbitration") of the Agreement is stricken and  
replaced with the following language: 
 
"8.	Dispute Resolution.   
 
	Any disagreement, dispute, controversy or claim arising out of or  
relating to this Agreement or the interpretation of this Agreement or  
any arrangements relating to this Agreement or contemplated in this  
Agreement or the breach, termination or invalidity thereof shall be  
settled by final and binding arbitration administered by JAMS/Endispute  
in San Diego, California in accordance with the then existing  
JAMS/Endispute Arbitration Rules and Procedures for Employment Disputes.   
In the event of such an arbitration proceeding, the Executive and the  
Company shall select a mutually acceptable neutral arbitrator from among  
the JAMS/Endispute panel of arbitrators.  In the event the Executive and  
the Company cannot agree on an arbitrator, the Administrator of  
JAMS/Endispute will appoint an arbitrator.  Neither the Executive nor  
the Company nor the arbitrator shall disclose the existence, content, or  
results of any arbitration hereunder without the prior written consent  
of all parties.  Except as provided herein, the Federal Arbitration Act  
shall govern the interpretation, enforcement and all proceedings.  The  
arbitrator shall apply the substantive law (and the law of remedies, if  
applicable) of the state of California, or federal law, or both, as  
applicable and the arbitrator is without jurisdiction to apply any  
different substantive law.  The arbitrator shall have the authority to  
entertain a motion to dismiss and/or a motion for summary judgment by  
any party and shall apply the standards governing such motions under the  
Federal Rules of Civil Procedure.  The arbitrator shall render an award  
and a written, reasoned opinion in support thereof.  Judgment upon the  
award may be entered in any court having jurisdiction thereof." 
 
	IN WITNESS WHEREOF, the Executive and, pursuant to authorization  
from its Board of Directors, the Company have caused this Amendment to  
Employment Agreement to be executed as of the effective date, above. 
 
SEMPRA ENERGY 
By:	________________________ 
Richard D. Farman Chairman & Chief Executive Officer 
			 
________________________ 
STEPHEN BAUM 
 
 
 
1 
 
 
3 
4TOPS/123198 
 
 
  
 
4TOPS/123198 
 


Exhibit 10.02
AMENDMENT TO EMPLOYMENT AGREEMENT 
 
By this Agreement, Sempra Energy (the "Company"),  a California  
corporation formerly known as Mineral Energy Company, and RICHARD FARMAN  
(the "Executive") amend the Employment Agreement (the "Agreement") between  
Mineral Energy Company and Executive dated October 12, 1996, to be  
effective December 1, 1998, as follows: 
 
1.Paragraph 4 (e) (iii) of the Agreement is stricken and replaced with the  
following language: 
 
"(iii)   the relocation of the Executive's principal place of employment  
to a location away from the Company's headquarters or a relocation of the  
Company's headquarters to a location further away which is both further  
away from Executive's residence and more than thirty (30) miles from such  
headquarters or a substantial increase in the Executive's business travel  
obligations outside of the Southern California area as of the Effective  
Date other than any such increase that (A) arises in connection with  
extraordinary business activities of the Company and (B) is understood not  
to be part of the Executive's regular duties with the Company;" 
2.   Paragraph 5 (a) (vi) of the Agreement is modified in its opening  
phrase to read: 
 
      "(vi)   Continuation of Welfare Benefits.  For a period of three (3)  
years or until the Executive is eligible for retiree medical benefits,  
whichever is longer, ..." 
 
3.   Paragraphs 5 (d), (e) and (f) of the Agreement are stricken and  
replaced by the following: 
 
"(d)   Code Section 280G 
(i)   Gross-Up.  Notwithstanding any other provisions of this Agreement,  
in the event that any payment or benefit received or to be received by the  
Executive (whether pursuant to the terms of this Agreement or any other  
plan, arrangement or agreement with (A) the Company, (B) any Person (as  
defined in Section 4(e))whose actions result in a Change in Control or (C)  
any Person affiliated with the Company or such Person) (all such payments  
and benefits, including the Severance Payments, being hereinafter called  
the "Total Payments") would be subject (in whole or part) to the tax (the  
"Excise Tax") imposed under section 4999 of the Code, the Company shall  
pay to the Executive such additional amounts (the "Gross-Up Payment") such  
that the net amount retained by the Executive, after deduction of any  
Excise Tax on the Total Payments and any federal, state and local income  
and employment taxes and Excise Tax upon the Gross-Up Payment, shall be  
equal to the Total Payments.  For purposes of determining the amount of  
the Gross-Up Payment, the Executive shall be deemed to pay federal income  
tax at the highest marginal rate of federal income taxation in the  
calendar year in which the Gross-Up Payment is to be made and state and  
local income taxes at the highest marginal rate of taxation in the state  
and locality of the Executive's residence on the date on which the  
Gross-Up Payment is calculated for purposes of this section, net of the  
maximum reduction in federal income taxes which could be obtained from  
deduction of such state and local taxes.  In the event that the Excise Tax  
is subsequently determined to be less than the amount taken into account  
hereunder, the Executive shall repay to the Company, at the time that the  
amount of such reduction in Excise Tax is finally determined, the portion  
of the Gross-Up Payment attributable to such reduction (plus that portion  
of the Gross-Up Payment attributable to the Excise Tax and federal, state  
and local income tax imposed on the Gross-Up Payment being repaid by the  
Executive to the extent that such repayment results in a reduction in  
Excise Tax and/or a federal, state or local income tax deduction) plus  
interest on the amount of such repayment at the rate provided in section  
1274(b)(2)(B) of the Code.  In the event that the Excise Tax is determined  
to exceed the amount taken into account hereunder (including by reason of  
any payment the existence or amount of which cannot be determined at the  
time of the Gross-Up Payment), the Company shall make an additional  
Gross-Up Payment in respect of such excess (plus any interest, penalties  
or additions payable by the Executive with respect to such excess) at the  
time that the amount of such excess is finally determined.  The Executive  
and the Company shall each reasonably cooperate with the other in  
connection with any administrative or judicial proceedings concerning the  
existence or amount of liability for Excise Tax with respect to the Total  
Payments. 
(ii)   Accounting Firm.  All determinations to be made with respect to  
this Section 5 (d) shall be made by the Company's independent accounting  
firm (or, in the case of a payment following a Change in Control, the  
accounting firm that was, immediately prior to the Change in Control, the  
Company's independent auditor).  The accounting firm shall be paid by the  
Company for its services performed hereunder." 
  
4.   Sections 5 (e) and (f) of the Agreement are added to read: 
 
"(e)   Outplacement Services.  The Executive shall receive outplacement  
services suitable to his or her position for a period of eighteen (18)  
months following the Date of Termination, or if earlier, until the first  
acceptance of an offer of employment with a subsequent employer, in an  
aggregate amount not to exceed $50,000. 
(f)   Financial Planning Services.  The Executive shall receive financial  
planning services for a period of eighteen (18) months following the Date  
of Termination at a level consistent with the benefits provided under the  
Company's financial planning program for the Executive, as in effect  
immediately prior to the Date of Termination." 
5.   Section 5(h) of the Agreement is added to read: 
 
   (h)   Notwithstanding anything contained herein, if a Change in Control  
occurs and if, prior to the date of the Change in Control, the Executive's  
employment is terminated by the Company (other than for Cause, death or  
Disability), or by the Executive for Good Reason, and if such Termination  
(i) was at the request of a third party who has taken steps reasonably  
calculated to effect the Change in Control or (ii) otherwise arose in  
connection with or in anticipation of the Change in Control, then such  
Termination shall be treated as a Termination following a Change in  
Control for purposes of this Agreement (including, without limitation, for  
purposes of determining the amounts of the Severance Payments under this  
Section 5). 
 
 
6.   Paragraph 8 ("Arbitration") of the Agreement is stricken and replaced  
with the following language: 
 
"8.   Dispute Resolution.   
 
   Any disagreement, dispute, controversy or claim arising out of or  
relating to this Agreement or the interpretation of this Agreement or any  
arrangements relating to this Agreement or contemplated in this Agreement  
or the breach, termination or invalidity thereof shall be settled by final  
and binding arbitration administered by JAMS/Endispute in San Diego,  
California in accordance with the then existing JAMS/Endispute Arbitration  
Rules and Procedures for Employment Disputes.  In the event of such an  
arbitration proceeding, the Executive and the Company shall select a  
mutually acceptable neutral arbitrator from among the JAMS/Endispute panel  
of arbitrators.  In the event the Executive and the Company cannot agree  
on an arbitrator, the Administrator of JAMS/Endispute will appoint an  
arbitrator.  Neither the Executive nor the Company nor the arbitrator  
shall disclose the existence, content, or results of any arbitration  
hereunder without the prior written consent of all parties.  Except as  
provided herein, the Federal Arbitration Act shall govern the  
interpretation, enforcement and all proceedings.  The arbitrator shall  
apply the substantive law (and the law of remedies, if applicable) of the  
state of California, or federal law, or both, as applicable and the  
arbitrator is without jurisdiction to apply any different substantive law.   
The arbitrator shall have the authority to entertain a motion to dismiss  
and/or a motion for summary judgment by any party and shall apply the  
standards governing such motions under the Federal Rules of Civil  
Procedure.  The arbitrator shall render an award and a written, reasoned  
opinion in support thereof.  Judgment upon the award may be entered in any  
court having jurisdiction thereof." 
 
   IN WITNESS WHEREOF, the Executive and, pursuant to authorization from  
its Board of Directors, the Company have caused this Amendment to  
Employment Agreement to be executed as of the effective date, above. 
 
SEMPRA ENERGY 
By:   ________________________   By:   ________________________ 
    Stephen L. Baum                    G. Joyce Rowland    
    Vice Chairman, President & COO     Senior Vice President, 
                                          Human Resources 
          
________________________ 
RICHARD FARMAN 
 
 
 
1 
 
 
3 
4TOPS/123198 
 
 
  
 
4TOPS/123198 
 


Exhibit 10.03
AMENDMENT TO 
EMPLOYMENT AGREEMENT 
 
By this Agreement, Sempra Energy (the "Company"), a California  
corporation formerly known as Mineral Energy Company, and DONALD  
FELSINGER (the "Executive") amend the Employment Agreement (the  
"Agreement") between Mineral Energy Company and Executive dated  
October 12, 1996, to be effective December 1, 1998, as follows: 
 
1. Paragraph 4 (d) (iii) of the Agreement is stricken and replaced  
with the following language: 
 
"(iii) the relocation of the Executive's principal place of  
employment to a location away from the Company's headquarters or a  
relocation of the Company's headquarters to a location further  
away which is both further away from Executive's residence and  
more than thirty (30) miles from such headquarters or a  
substantial increase in the Executive's business travel  
obligations outside of the Southern California area as of the  
Effective Date other than any such increase that (A) arises in  
connection with extraordinary business activities of the Company  
and (B) is understood not to be part of the Executive's regular  
duties with the 
Company;" 
 
2.  Paragraph 5 (a) (vi) of the Agreement is modified in its  
opening phrase to read: 
 
"(vi)  Continuation of Welfare Benefits.  For a period of three  
(3) years or until the Executive is eligible for retiree benefits,  
whichever is longer, ..." 
 
3.  Paragraphs 5 (d), (e) and (f) of the Agreement are stricken  
and replaced by the following: 
 
"(d)   Code Section 280G 
 
(i)  Gross-Up.  Notwithstanding any other provisions of this  
Agreement, in the event that any payment or benefit received or to  
be received by the Executive (whether pursuant to the terms of  
this Agreement or any other plan, arrangement or agreement with  
(A) the Company, (B) any Person (as defined in Section 4(e))whose  
actions result in a Change Control or (C) any Person affiliated  
with the Company or such Person) (all such payments and benefits,  
including the Severance Payments, hereinafter called the "Total  
Payments") would be subject (in whole or part) to the tax (the  
"Excise Tax") imposed under section 4999 of the Code, the Company  
shall pay to the Executive such additional amounts (the "Gross-Up  
Payment") such that the net amount retained by the Executive,  
after deduction of any Excise Tax on the Total Payments and any  
federal, state and local income and employment taxes and Excise  
Tax upon the Gross-Up Payment, shall be equal to the Total  
Payments.  For purposes of determining the amount of the Gross-Up  
Payment, the Executive shall be deemed to pay federal income tax  
at the highest marginal rate of federal income taxation in the  
calendar year in which the Gross-Up Payment is be made and state  
and local income taxes at the highest marginal rate taxation in  
the state and locality of the Executive's residence on the date on  
which the Gross-Up Payment is calculated for purposes of this  
section, net of the maximum reduction in federal income taxes  
which could be obtained from deduction of such state and local  
taxes.  In the event that the Excise Tax is subsequently  
determined to be less than the amount taken into account  
hereunder, the Executive shall repay to the Company, at the time  
that the amount of such reduction in Excise Tax is finally  
determined, the portion of the Gross-Up Payment attributable to  
such reduction (plus that portion of the Gross-Up Payment  
attributable to the Excise Tax and federal, state and local income  
tax imposed on the Gross-Up Payment being repaid by the Executive  
to the extent that such repayment results in a reduction in Excise  
Tax and/or a federal, state or local income tax deduction) plus  
interest on the amount of such repayment at the rate provided in  
section 1274(b)(2)(B) of the Code.  In the event that the Excise  
Tax is determined to exceed the amount taken into account  
hereunder (including by reason of any payment the existence or  
amount of cannot be determined at the time of the Gross-Up  
Payment), the Company shall make an additional Gross-Up Payment in  
respect of such excess (plus any interest, penalties or additions  
payable by the Executive with respect to such excess) at the time  
that the amount of such excess is finally determined.  The  
Executive and the Company shall each reasonably cooperate with the  
other in connection with any administrative or judicial  
proceedings concerning the existence or amount of liability for  
Excise with respect to the Total Payments. 
 
(ii)  Accounting Firm.  All determinations to be made with respect  
to this Section 5 (d) shall be made by the Company's independent  
accounting firm (or, in the case of a payment following a Change  
in Control, the accounting firm that was, immediately prior to the  
Change in Control, the Company's independent auditor).  The  
accounting firm shall be paid by the Company for its services  
performed hereunder." 
 
4.  Sections 5 (e) and (f) of the Agreement are added to read: 
 
"(e)  Outplacement Services.  The Executive shall receive  
outplacement services suitable to his or her position for a period  
of eighteen (18) months following the Date of Termination, or if  
earlier, until the first acceptance of an offer of employment with  
a subsequent employer, in an aggregate amount not to exceed  
$50,000. 
 
(f)  Financial Planning Services.  The Executive shall receive  
financial planning services for a period of eighteen (18) months  
following the Date of Termination at a level consistent with the  
benefits provided under the Company's financial planning program  
for the Executive, as in effect immediately prior to the Date of  
Termination." 
 
5.  Section 5(h) of the Agreement is added to read: 
 
(h)  Notwithstanding anything contained herein, if a Change in  
Control occurs and if, prior to the date of the Change in Control,  
the Executive's employment is terminated by the Company (other  
than for Cause, death or Disability), or by the Executive for Good  
Reason, and if such Termination (i) was at the request of a third  
party who has taken steps reasonably calculated to effect the  
Change in Control or (ii) otherwise arose in connection with or in  
anticipation of the Change in Control, then such Termination shall  
be treated as a Termination following a Change in Control for  
purposes of this Agreement (including, without limitation, for  
purposes of determining the amounts of the Severance Payments  
under this Section 5). 
 
6.  Paragraph 8 ("Arbitration") of the Agreement is stricken and  
replaced with the following language: 
 
"8.  Dispute Resolution.   
 
Any disagreement, dispute, controversy or claim arising out of or  
relating to this Agreement or the interpretation of this Agreement  
or any arrangements relating to this Agreement or contemplated in  
this Agreement or the breach, termination or invalidity thereof  
shall be settled by final and binding arbitration administered by  
JAMS/Endispute in San Diego, California in accordance with the  
then existing JAMS/Endispute Arbitration Rules and Procedures for  
Employment Disputes.  In the event of such an arbitration  
proceeding, the Executive and the Company shall select a mutually  
acceptable neutral arbitrator from among the JAMS/Endispute panel  
of arbitrators.  In the event the Executive and the Company cannot  
agree on an arbitrator, the Administrator of JAMS/Endispute will  
appoint an arbitrator.  Neither the Executive nor the Company nor  
the arbitrator shall disclose the existence, content, or results  
of any arbitration hereunder without the prior written consent of  
all parties.  Except as provided herein, the Federal Arbitration  
Act shall govern the interpretation, enforcement and all  
proceedings.  The arbitrator shall apply the substantive law (and  
the law of remedies, if applicable) of the state of California, or  
federal law, or both, as applicable and the arbitrator is without  
jurisdiction to apply any different substantive law.  The  
arbitrator shall have the authority to entertain a motion to  
dismiss and/or a motion for summary judgment by any party and  
shall apply the standards governing such motions under the Federal  
Rules of Civil Procedure.  The arbitrator shall render an award  
and a written, reasoned opinion in support thereof.  Judgment upon  
the award may be entered in any court having jurisdiction  
thereof." 
 
IN WITNESS WHEREOF, the Executive and, pursuant to authorization  
from its Board of Directors, the Company have caused this  
Amendment to Employment Agreement to be executed as of the  
effective date, above. 
 
SEMPRA ENERGY 
 
 
 
 
By: ________________________ 
    Richard D. Farman 
    Chairman & Chief Executive Officer 
 
 
 
 
    ________________________ 
    DONALD FELSINGER 
 
 


Exhibit 10.04
AMENDMENT TO  
EMPLOYMENT AGREEMENT  
  
By this Agreement, Sempra Energy (the "Company"),  a California corporation  
formerly known as Mineral Energy Company, and WARREN MITCHELL (the  
"Executive") amend the Employment Agreement (the "Agreement") between  
Mineral Energy Company and Executive dated October 12, 1996, to be  
effective December 1, 1998, as follows:  
  
1.  Paragraph 5 (a) (vi) of the Agreement is modified in its opening phrase  
to read:  
  
"(vi)  Continuation of Welfare Benefits.  For a period of three (3) years  
or until the Executive is eligible for retiree medical benefits, whichever  
is longer, ..."  
  
2.  Paragraphs 5 (d), (e) and (f) of the Agreement are stricken and  
replaced by the following:  
  
"(d)   Code Section 280G  
(i)  Gross-Up.  Notwithstanding any other provisions of this Agreement, in  
the event that any payment or benefit received or to be received by the  
Executive (whether pursuant to the terms of this Agreement or any other  
plan, arrangement or agreement with (A) the Company, (B) any Person (as  
defined in Section 4(e))whose actions result in a Change in Control or (C)  
any Person affiliated with the Company or such Person) (all such payments  
and benefits, including the Severance Payments, being hereinafter called  
the "Total Payments") would be subject (in whole or part) to the tax (the  
"Excise Tax") imposed under section 4999 of the Code, the Company shall pay  
to the Executive such additional amounts (the "Gross-Up Payment") such that  
the net amount retained by the Executive, after deduction of any Excise Tax  
on the Total Payments and any federal, state and local income and  
employment taxes and Excise Tax upon the Gross-Up Payment, shall be equal  
to the Total Payments.  For purposes of determining the amount of the  
Gross-Up Payment, the Executive shall be deemed to pay federal income tax  
at the highest marginal rate of federal income taxation in the calendar  
year in which the Gross-Up Payment is to be made and state and local income  
taxes at the highest marginal rate of taxation in the state and locality of  
the Executive's residence on the date on which the Gross-Up Payment is  
calculated for purposes of this section, net of the maximum reduction in  
federal income taxes which could be obtained from deduction of such state  
and local taxes.  In the event that the Excise Tax is subsequently  
determined to be less than the amount taken into account hereunder, the  
Executive shall repay to the Company, at the time that the amount of such  
reduction in Excise Tax is finally determined, the portion of the Gross-Up  
Payment attributable to such reduction (plus that portion of the Gross-Up  
Payment attributable to the Excise Tax and federal, state and local income  
tax imposed on the Gross-Up Payment being repaid by the Executive to the  
extent that such repayment results in a reduction in Excise Tax and/or a  
federal, state or local income tax deduction) plus interest on the amount  
of such repayment at the rate provided in section 1274(b)(2)(B) of the  
Code.  In the event that the Excise Tax is determined to exceed the amount  
taken into account hereunder (including by reason of any payment the  
existence or amount of which cannot be determined at the time of the Gross- 
Up Payment), the Company shall make an additional Gross-Up Payment in  
respect of such excess (plus any interest, penalties or additions payable  
by the Executive with respect to such excess) at the time that the amount  
of such excess is finally determined.  The Executive and the Company shall  
each reasonably cooperate with the other in connection with any  
administrative or judicial proceedings concerning the existence or amount  
of liability for Excise Tax with respect to the Total Payments.  
(ii)  Accounting Firm.  All determinations to be made with respect to this  
Section 5 (d) shall be made by the Company's independent accounting firm  
(or, in the case of a payment following a Change in Control, the accounting  
firm that was, immediately prior to the Change in Control, the Company's  
independent auditor).  The accounting firm shall be paid by the Company for  
its services performed hereunder."  
  
3.  Sections 5 (e) and (f) of the Agreement are added to read:  
  
"(e) Outplacement Services.  The Executive shall receive outplacement  
services suitable to his or her position for a period of eighteen (18)  
months following the Date of Termination, or if earlier, until the first  
acceptance of an offer of employment with a subsequent employer, in an  
aggregate amount not to exceed $50,000.  
(f)  Financial Planning Services.  The Executive shall receive financial  
planning services for a period of eighteen (18) months following the Date  
of Termination at a level consistent with the benefits provided under the  
Company's financial planning program for the Executive, as in effect  
immediately prior to the Date of Termination."  
  
4.  Section 5(h) of the Agreement is added to read:  
  
(h)  Notwithstanding anything contained herein, if a Change in Control  
occurs and if, prior to the date of the Change in Control, the Executive's  
employment is terminated by the Company (other than for Cause, death or  
Disability), or by the Executive for Good Reason, and if such Termination  
(i) was at the request of a third party who has taken steps reasonably  
calculated to effect the Change in Control or (ii) otherwise arose in  
connection with or in anticipation of the Change in Control, then such  
Termination shall be treated as a Termination following a Change in Control  
for purposes of this Agreement (including, without limitation, for purposes  
of determining the amounts of the Severance Payments under this Section 5).  
  
  
5.  Paragraph 8 ("Arbitration") of the Agreement is stricken and replaced  
with the following language:  
  
"8.  Dispute Resolution.    
  
Any disagreement, dispute, controversy or claim arising out of or relating  
to this Agreement or the interpretation of this Agreement or any  
arrangements relating to this Agreement or contemplated in this Agreement  
or the breach, termination or invalidity thereof shall be settled by final  
and binding arbitration administered by JAMS/Endispute in San Diego,  
California in accordance with the then existing JAMS/Endispute Arbitration  
Rules and Procedures for Employment Disputes.  In the event of such an  
arbitration proceeding, the Executive and the Company shall select a  
mutually acceptable neutral arbitrator from among the JAMS/Endispute panel  
of arbitrators.  In the event the Executive and the Company cannot agree on  
an arbitrator, the Administrator of JAMS/Endispute will appoint an  
arbitrator.  Neither the Executive nor the Company nor the arbitrator shall  
disclose the existence, content, or results of any arbitration hereunder  
without the prior written consent of all parties.  Except as provided  
herein, the Federal Arbitration Act shall govern the interpretation,  
enforcement and all proceedings.  The arbitrator shall apply the  
substantive law (and the law of remedies, if applicable) of the state of  
California, or federal law, or both, as applicable and the arbitrator is  
without jurisdiction to apply any different substantive law.  The  
arbitrator shall have the authority to entertain a motion to dismiss and/or  
a motion for summary judgment by any party and shall apply the standards  
governing such motions under the Federal Rules of Civil Procedure.  The  
arbitrator shall render an award and a written, reasoned opinion in support  
thereof.  Judgment upon the award may be entered in any court having  
jurisdiction thereof."  
  
  
  
  
  
  
  
IN WITNESS WHEREOF, the Executive and, pursuant to authorization from its  
Board of Directors, the Company have caused this Amendment to Employment  
Agreement to be executed as of the effective date, above.  
  
  
SEMPRA ENERGY  
By:  ________________________  
     Richard D. Farman  
     Chairman & Chief Executive Officer  
     ________________________  
     WARREN MITCHELL

Exhibit 10.09
SEMPRA ENERGY  
SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN 
 
This Supplemental Executive Retirement Plan provides retirement income,  
disability income and death benefits to key executives and their spouses  
under specified circumstances. 
This amended and restated Plan is effective July 1, 1998. 
 
TC "1. Definitions"\l  
SECTION 1 
DEFINITIONS 
 
1.1 "Actuarial Equivalent" means equivalent value when computed using the  
applicable mortality table promulgated by the IRS under Code Section  
417(e)(3) as in effect on the first day of the Plan Year and the applicable  
interest rate promulgated by the IRS under Code Section 417(e)(3) for the  
November preceding the first day of the Plan Year.  
1.2 "Average Bonus" means the average of the three highest annual incentive  
awards earned by a Participant under the Executive Incentive Plan during the  
Participant's last ten years of Service, determined an follows: 
(a) Annual incentive awards shall be counted whether or not deferred under  
the Deferred Compensation Plan. 
(b) If a Participant was designated as a participant in the Executive  
Incentive Plan for a year, but earned no annual incentive award during that  
year, the award will be counted as zero, and if the Participant did not earn  
three annual incentive awards during the other years during the last ten  
years of Service, the zero amount will be used to attain the average of the  
three highest annual incentive awards. 
(c) If the Participant was not designated as a participant in the Executive  
Incentive Plan for three full years of the last ten years of Service, the  
average shall be based on the number of full years the Participant was  
designated as a participant in the Executive Incentive Plan during the last  
ten years of Service. 
(d) As to a Participant in the Executive Incentive Plan who did not earn  
annual incentive awards during the last ten years of Service solely due to a  
disability which qualified him for a Basic Disability Plan Benefit, a  
Supplemental Disability Benefit or both, the applicable ten year period will  
be extended backwards for each year of such occurrence. 
(e) Prorated annual incentive awards earned under the Executive Incentive  
Plan will not be used in determining the average. 
(f) If a Participant works past his Normal Retirement Date, his "Average  
Bonus" will be determined and fixed as of such date. 
1.3 "Average Earnings" means the average Earnings of the highest two years  
of Service in the last ten years while a Participant was not receiving a  
Basic Disability Plan Benefit, a Supplemental Disability Benefit or both. 
1.4 "Basic Disability Plan" means a disability plan maintained by Sempra  
Energy or a subsidiary which provides coverage for most full time employees  
of the plan sponsor. 
1.5 "Basic Disability Plan Benefit" means the annual amount of benefit  
payable from the Basic Disability Plan to a Participant. 
1.6 "Basic Pension Plan" means the Sempra Energy Cash Balance Plan, and  
where applicable by the context, the pension plan of a subsidiary of Sempra  
Energy. 
1.7 "Basic Pension Plan Benefit" means the annual amount of benefit payable  
from the Basic Pension Plan to a Participant on his Retirement Date in the  
form of a straight life annuity without a cost-of-living feature. 
1.8 "Committee" means the Compensation Committee of the Company's Board of  
Directors. 
1.9 "Company" means Sempra Energy. 
1.10 "Deferred Compensation Plan" means the Sempra Energy Executive Deferred  
Compensation Plan. 
1.11 "Earnings" means base compensation only including any deferral under  
the Savings Plan, the Supplemental Savings Plan and the Deferred  
Compensation Plan. 
1.12 "Employer" means the Company and any of its subsidiaries (any  
corporation of which 50% or more of the issued and outstanding stock having  
ordinary voting rights is owned directly or indirectly by the Company or any  
other business entity or association of which 50% or more of the outstanding  
equity interest is so owned) which adopt this Plan. 
1.13 "Employment" means employment by the Employer, including the period  
during which a Participant is receiving a Basic Disability Plan Benefit, and  
any additiona1 period during which a Participant is receiving a Supplemental  
Disability Benefit under this Plan. 
1.14 "Executive Incentive Plan" means the Sempra Energy Executive Incentive  
Plan. 
1.15 "Normal Retirement Date" means the first day of the month following the  
month in which a Participant attains age 65. 
1.16 "Participant" means an employee of the Employer designated to  
participate in this Plan as specified in Section 2.1. 
1.17 "Plan" means this Supplemental Executive Retirement Plan. 
1.18 "Preretirement Spouse's Benefit" means the benefit payable or paid  
under the Basic Pension Plan and Excess Cash Balance Plan to a Surviving  
Spouse of a Participant who dies in Employment.  
1.19 "Prior Plan" shall mean the Pacific Enterprises Supplemental Retirement  
and Survivor Plan and the San Diego Gas and Electric Supplemental Executive  
Retirement Plan. 
1.20 "Retirement" means the termination of a Participant's Employment with  
the Employer after five years of Service on or after the Participant attains  
age 55.  
1.21 "Retirement Date" means the first day of the month following a  
Participant's Retirement. 
1.22 "Service" means  a Participant's credited service which would be used  
to compute retirement benefits under the Basic Pension Plan.  
1.23 "Social Security Benefit" means the annual Primary Insurance Amount  
estimated to be payable to the Participant at age 65 under the Federal  
Social Security Act in effect at the time of the event. 
1.24 "Spouse's Supplemental Retirement Benefits" means the benefit payable  
to the Surviving Spouse of a Participant under Section 2.3 of this Plan  
after the Participant has died on or after his Retirement Date. 
1.25 "Supplemental Disability Benefit" means the benefit payable to a  
disabled Participant under Section 2.5 of this Plan. 
1.26 "Excess Cash Balance Plan" means the Sempra Energy Excess Cash Balance  
Plan, or any other supplemental pension plan of any Employer providing  
essentially the same benefits for one or more Participants. 
1.27 "Excess Cash Balance Plan Benefits" means the annual amount of benefit  
payable or paid from the Excess Cash Balance Plan to a Participant on his  
Retirement Date in the form of a straight life annuity without a cost-of- 
living adjustment feature. 
1.28 "Supplemental Retirement Benefit" means the benefit payable to a  
Participant under Section 2.2 of this Plan on his Retirement Date. 
1.29 "Surviving Spouse" means in the case of a Spouse's Death Benefit, a  
spouse married to the Participant for at least the one-year period ending on  
the Participant's date of death, and means in the case of a Spouse's  
Supplemental Retirement Benefit, a spouse who is married to the Participant  
for at least the one-year period ending on the Participant's Retirement Date  
and who is still married to the Participant on the date of the Participant's  
death.  Surviving Spouse also means a Spousal Equivalent as defined by the  
Company (subject to the one year requirements) under the Company Medical  
Plan. 
1.30 The masculine pronoun whenever used shall include the feminine pronoun,  
and the singular shall include the plural where the context requires it. 
1.31 "Vesting Factor" means the following for a Participant who qualifies  
for Retirement under paragraph 1.20 
Vesting Schedule 
 
                 Age 
                 55     56     57     58     59     60 and older 
Service 
5                50%    60%    70%    80%    90%    100% 
 
6                55%    60%    70%    80%    90%    100% 
 
7                60%    65%    70%    80%    90%    100% 
 
8                65%    70%    75%    80%    90%    100% 
 
9                70%    75%    80%    85%    90%    100% 
 
10               75%    80%    85%    90%    95%    100% 
 
11               80%    85%    90%    95%    100%   100% 
 
12               85%    90%    95%    100%   100%   100% 
 
13               90%    95%    100%   100%   100%   100% 
 
14               95%    100%   100%   100%   100%   100% 
 
15 and more      100%   100%   100%   100%   100%   100% 
 
Based on attained age and completed years of service. 
 
TC "2. Eligibility for Benefits"\l  
SECTION 2  
ELIGIBILITY FOR BENEFITS 
TC "2.1 Participation "\l2  
2.1 Participation 
Executive Officers of the Company as designated shall be eligible to  
participate in this Plan.  The Committee may designate additional officers  
and key employees of the Employer who shall participate in this Plan and the  
effective date of such participation, subject to agreement by the Board of  
Directors of the executive's Employer (if not the Company) that such  
executive participate and that such Employer pay the costs of this Plan for  
the executive and his Surviving Spouse.  
TC "2.2 Supplemental Retirement Benefit "\l2  
2.2 Supplemental Retirement Benefit 
Each Participant is eligible to retire and receive a benefit under this Plan  
as specified in Sections 3.1 and 3.4 beginning on his Retirement Date.  No  
Supplemental Retirement Benefit will be paid to a Participant who leaves  
Employment prior to attaining age 55 or completing five years of Service,  
except as provided under other agreements. 
TC "2.3 Spouse's Supplemental Retirement Benefit "\l2  
2.3 Spouse's Supplemental Retirement Benefit 
The Surviving Spouse of a Participant who dies on or after his Retirement  
Date who did not receive a lump sum payment is eligible for a Spouse's  
Supplemental Retirement Benefit in accordance with Sections 3.2 and 3.4. 
TC "2.4 Spouse's Death Benefit "\l2  
2.4 Spouse's Death Benefit 
The Surviving Spouse of a Participant who dies in Employment is eligible for  
a Spouse's Death Benefit as specified in Sections 4.1 and 4.2 in either the  
form of a lump sum benefit or lifetime annuity benefit as elected by the  
Participant.  There is no cost to the Participant for this benefit.  If a  
Participant dies during Employment without an eligible Surviving Spouse, no  
Spouse's Death Benefit is payable under this Plan. 
TC "2.5 Supplemental Disability Benefit "\l2  
2.5 Supplemental Disability Benefit 
A Participant who becomes disabled may be eligible to receive a supplemental  
Disability Benefit  as specified in Section 5. 
TC "3. Retirement Benefits "\l  
SECTION 3 
RETIREMENT BENEFITS 
TC "3.1 Amount of Supplemental Retirement Benefit "\l2  
3.1 Amount of Supplemental Retirement Benefit 
The annual Supplemental Retirement Benefit payable to a Participant as of  
his Retirement Date is equal to (a) minus (b) with the resultant product  
multiplied by the Participant's Vesting Factor and then the resultant  
product multiplied by the early retirement reduction (pursuant to Appendix  
A) for Retirement Dates which precede attainment of 62 years of age.  The  
benefit will also be reduced as provided in Section 8: 
(a) is the sum of the following percent of the total of the Participant's  
Average Earnings and Average Bonus 
(i) 1/3% for each month of Service  through 120 (40% for 10 years of  
Service), plus 
(ii) 1/6% for each month of Service in excess of 120, through 240 (60% for  
20 years of Service), plus 
(iii) 1/48% for each month of Service in excess of 240 (65% for 40 years of  
Service). 
(b) is the sum of his 
(i) Basic Pension Plan Benefit, plus  
(ii) Excess Cash Balance Plan Benefit  
Provided however, that if a Participant commences receipt of benefits under  
this Plan on a different date than the Participant commences receipt of  
benefits under the Basic Pension Plan, this paragraph (b) shall be  
calculated based on the benefits the Participant would have received if the  
Participant elected the same Retirement Date under the Basic Pension Plan  
that he elected under this Plan.  
If (a) minus (b) results in zero or less, then no Supplemental Retirement  
Benefit is payable. 
The Participant may elect to receive the Supplemental Retirement Plan  
benefits, payable on his behalf, paid in an actuarially equivalent lump sum,  
provided the Participant elects such lump sum one year prior to retirement  
and submits evidence of good health satisfactory to the Committee. 
TC "3.2 Amount of Spouse's Supplemental Retirement Benefit "\l2  
3.2 Amount of Spouse's Supplemental Retirement Benefit 
The annual Spouse's Supplemental Retirement Benefit payable to a Surviving  
Spouse of a Participant who did not receive a lump sum optional payment is  
equal to 50% of the Participant's Supplemental Retirement Benefit in Station  
3.1(a) without the reduction in 3.1(b) but adjusted by the Vesting Factor  
and the early retirement reduction pursuant to appendix A.  
TC "3.3 Adjustments "\l2  
3.3 Adjustments 
The annual Supplemental Retirement Benefit or the annual Spouse's  
Supplemental Retirement Benefit will not be decreased or increased on  
account of any increase or decrease in the Basic Pension Plan Benefit,  
Supplemental Pension Plan Benefit, or Social Security Benefit occurring  
after a Participant's Retirement Date or death. 
TC "3.4 Payment "\l2  
3.4 Payment 
A Supplemental Retirement Benefit will be paid monthly, beginning on the  
last day of the month of the Participant's Retirement Date, and will  
continue to be paid monthly during the life of the Participant, the last  
payment to be made to the Participant's spouse, or if none, to the  
Participant's estate, on the last day of the month in which the death of the  
Participant occurs.  If the Participant is survived by a Surviving Spouse,  
the Surviving Spouse will receive a Spouse's Supplemental Retirement  
Benefit.  The Spouse's Supplemental Retirement Benefit will be paid monthly,  
and will commence on the last day of the month following the month in which  
the Participant dies and will continue during the life of the Surviving  
Spouse. 
The Participant may elect to receive all Supplemental Retirement Plan  
benefit payable on behalf of the Participant in an actuarially equivalent  
lump sum, provided the Participant elects one year prior to retirement and  
submits evidence satisfactory to the Committee of his/her good health. 
TC "4. Supplemental Preretirement Spouse's Death Benefits "\l  
SECTION 4  
SUPPLEMENTAL PRERETIREMENT SPOUSE'S DEATH BENEFITS 
TC "4.1 Benefit "\l2  
4.1 Benefit 
The annual Spouse's Death Benefit that will be paid to a Surviving Spouse of  
a Participant who dies in Employment prior to his Retirement Date is equal  
to (a) minus (b) when:  
(a) is 50% of the Participant's accrued benefit calculated in accordance  
with 3.1(a).  If the Participant is under age 55 at the time of death, the  
age 55 early retirement factor shall be used, and 
(b) is the Surviving Spouse's Preretirement Spouse's Benefit, plus any life  
insurance benefit payable under any Split Dollar Life Insurance purchased in  
accordance with Section 8.1 herein.  
 TC "4.2 Form of Benefit "\l2  
4.2 Form of Benefit 
A Participant may elect to have his Surviving Spouse receive either the  
annuity benefit described above or, an Actuarially Equivalent lump sum  
payment.  The payment of a lump sum requires that the election be made at  
least one year prior to the Participant's date of death and that the  
Surviving Spouse submits evidence satisfactory to the Committee of his/her  
good health.  
The initial election of benefit form must be made at the time of  
commencement of Participation.   
If a Participant wishes to change from the lump sum benefit to the lifetime  
annuity benefit or vice versa thereafter, the Participant may apply for such  
change as long as it is received by the Company in writing at least one year  
prior to termination under the Basic Plan. Spouse's Death Benefit shall  
automatically cease upon the earliest of: 
(i) the Participant's termination of Employment,  
(ii) the death of the Surviving Spouse, and  
(iii) the Participant's Retirement Date.  
TC "5. Supplemental Disability Benefits "\l  
SECTION 5 
SUPPLEMENTAL DISABILITY BENEFITS 
TC "5.1 Amount "\l2  
5.1 Amount 
The annual Supplemental Disability Benefit payable to a Participant is equal  
to (a) minus (b) when: (a) is 60% multiplied by the total of the  
Participant's Average Bonus and annual rate of Earnings in effect on the day  
immediately preceding the day the Participant becomes eligible, and (b) is  
the sum of 
(i) the Participant's Basic Disability Plan Benefit, and any other Company  
provided disability plan, plus 
(ii) the amount of benefits for which the Participant is eligible under the  
provisions of any federal or state law providing payments on account of  
disability, as these payments are defined in the Basic Disability Plan,  
during the period of eligibility for a Supplemental Disability Benefit.  
If (a) minus (b) results in zero or less, then no Supplemental Disability  
Benefit is payable.  If the Basic Disability Plan Benefit increases under  
the Basic Disability Plan, the Supplemental Disability Benefit will be  
decreased by the same amount. 
TC "5.2 Payment "\l2  
5.2 Payment 
Eligibility for a Supplemental Disability Benefit is determined by the  
Committee.  The Supplemental Disability Benefit will be paid monthly. The  
last Supplemental Disability Benefit will be paid to the Participant at the  
earliest of (i) when the Committee deems that the Participant is no longer  
disabled, (ii) when Participant starts receiving a Supplemental Retirement  
Benefit, or (iii) when the Participant attains age 65. 
TC "6. Administration "\l  
SECTION 6 
ADMINISTRATION 
TC "6.1 Authority of Committee "\l2  
6.1 Authority of Committee 
This Plan shall be administered by the Committee. Subject to the express  
provisions of this Plan, the Committee shall have full and final authority  
to interpret this Plan, to prescribe, amend and rescind rules, regulations  
and guides relating to the Plan, and to make any other determinations that  
it believe. necessary or advisable for the administration of the Plan.  The  
Committee may delegate certain responsibilities in the administration of the  
Plan.  All decisions and determinations by the Committee shall be final and  
binding upon all parties. 
TC "6.2 Calculation of Benefits "\l2  
6.2 Calculation of Benefits 
Any and all payments to be made under this Plan and all Actuarial  
Equivalents shall be calculated by the Company's regularly employed  
independent actuaries, and their determinations shall be final and binding  
on all parties. 
TC "7. Miscellaneous "\l  
SECTION 7 
MISCELLANEOUS 
TC "7.1 Amendment, Termination or Removal of Participant "\l2  
7.1 Amendment, Termination or Removal of Participant 
The Committee may, in its sole discretion, terminate, suspend, or amend this  
Plan at any time, in whole or in part.  However, no amendment or suspension  
of the Plan will affect a retired or disabled Participant's right or the  
right of a Surviving Spouse to continue receiving a benefit in accordance  
with this Plan as in effect on the date such Participant or Surviving Spouse  
began to receive a benefit under this Plan.  The Committee may, in its sole  
discretion, remove an executive as a Participant in this Plan due to changed  
job responsibilities or other changed circumstances as long as no benefits  
are then being paid to the Participant under this Plan. 
TC "7.2 No Employment Right "\l2  
7.2 No Employment Right 
Nothing contained herein will confer upon any Participant the right to be  
retained in Employment, nor will it interfere with the right of his Employer  
to discharge or otherwise deal with the Participant without regard to the  
existence of this Plan. 
TC "7.3 Funding "\l2  
7.3 Funding 
This Plan is unfunded, and the Employer will make Plan Benefit Payments  
solely on a current disbursement basis.  Participants and their  
Beneficiaries shall have no legal or equitable rights, claims, or interest  
in any specific property or assets of the Employer, and the rights of the  
Participants and Beneficiaries shall be no greater than those of unsecured  
general creditors. 
TC "7.4 Allocation of Costs "\l2  
7.4 Allocation of Costs 
Amounts accrued as expenses under this Plan, and the cost of any life  
insurance policies purchased to fund for benefits payable under this Plan,  
shall be allocated to Employers whose employees are Participants in this  
Plan. 
TC "7.5 Nonassignment "\l2  
7.5 Nonassignment 
To the maximum extent permitted by law, no benefit under this Plan will be  
assignable or subject in any manner to alienation, sale, transfer, claims of  
creditors, pledge, attachment, or encumbrances of any kind. 
TC "7.6 Governing Law "\l2  
7.6 Governing Law 
This Plan is established under and will be construed according to the laws  
of the State of California. 
TC "8. Offset for Certain Benefits Payable Under Split-Dollar Life Insurance  
"\l  
SECTION 8 
OFFSET FOR CERTAIN BENEFITS PAYABLE UNDER  
OTHER PLANS 
8.1 Some of the Participants under this Plan own life insurance policies  
(the "Policies") purchased on their behalf by the Company.  The ownership of  
these Policies by each Participant is, however, subject to certain  
conditions (set forth in a "Split 
Dollar Life Insurance Agreement" or other comparable agreements between the  
Participant and the Company) and, if the Participant fails to meet the  
conditions set forth in the Split 
Dollar Life Insurance Agreement, the Participant may lose certain rights  
under the Policy.  In the event that a Participant satisfies the conditions  
specified in Section 5 or 6 of the Split 
Dollar Life Insurance Agreement, so that the Participant or his beneficiary  
becomes entitled to benefits under one of those sections, the value of those  
benefits shall constitute an offset to any benefits otherwise payable under  
this Plan.  As the case may be, this offset (the "Offset Value") shall be  
calculated by determining the value of benefits payable under the Split 
Dollar Life Insurance Agreement, that is, the cash surrender value of the  
Policy, or in the case of the Participant's death, the death benefits  
payable to the beneficiary under the Policy.  The Offset Value shall then be  
compared to the Actuarial Equivalent (as defined in Section 8.4) of the  
benefits payable under this Plan (the "Plan Values), and the Plan Value  
shall be reduced by the Offset Value. 
8.2 At the time when the Participant terminates employment for any reason,  
if the Plan Value exceeds the present value (determined using the interest  
rate specified in Section 8.4) of the Offset Value, the excess of the Plan  
Value over the present value of the Offset Value shall be paid to the  
Participant or beneficiary at that time in a lump sum.  Provided that the  
Participant or beneficiary submits evidence satisfactory to the Committee of  
his/her good health.  If the Participant is not in good health, the benefits  
will be paid as an annuity.  The Participant may choose, one year prior to  
the date of termination, to receive the remaining amount as an annuity.   
Such payment shall completely discharge all obligations owed under this Plan  
on account of Participant's participation in this Plan. 
8.3 If the Policy described in Section 8.1 is not on the life of the  
Participant, the insured dies prior to the Participant becoming eligible for  
benefits under the Plan, and the Participant or the Participant's  
beneficiary subsequently becomes eligible for benefits hereunder, the  
Actuarial Equivalent  of the benefits payable hereunder shall be offset by  
the Actuarial Equivalent of the payments previously paid to the Participant  
in the Split 
Dollar Life Insurance Agreement.  Any remaining amount due the Participant  
or the Participant's beneficiary shall thereupon be paid in a cash lump sum,  
provided that the Participant or beneficiary submits evidence satisfactory  
to the Committee of his/her good health.  If the Participant is not in good  
health, the benefits will be paid as an annuity.  The Participant may  
choose, one year prior to the date of termination, to receive the remaining  
amount as an annuity. 
8.4 Notwithstanding anything contained herein to the contrary, in the event  
that a Participant has a benefit under Excess Cash Balance Plan, the Offset  
Value shall first be applied to reduce benefits paid under the Excess Cash  
Balance Plan and any remaining Offset Value shall then be applied to reduce  
the Plan Value under this Plan; provided, however, that for purposes of  
determining the amount of benefits payable under this Plan, any benefits  
payable under the Excess Cash Balance Plan shall be determined without  
regard to such offset. 
8.5 The Committee may offer additional options which are of equivalent  
value. 
APPENDIX A 
EARLY RETIREMENT REDUCTION FACTOR  
                            Age 
                            62 and later   61   60   59   58   57   56   55 
Early Retirement Factor*    100%           97%  94%  90%  86%  82%  78%  74% 
 
*Reduction factors vary by age and months. 
 
 
 
APPENDIX B 
GRANDFATHER BENEFIT 
Current Participants in the Prior Plans are permanently grandfathered under  
the Prior Plan provisions if the benefit is greater. 
SEMPRA ENERGY 
SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN 
Section	Page 
TOC \f \* MERGEFORMAT  
1. Definitions	 
 GOTOBUTTON _Toc416840980   
 PAGEREF _Toc416840980  
2. Eligibility for Benefits	 
 GOTOBUTTON _Toc416840981   
 PAGEREF _Toc416840981  
2.1  Participation	 
 GOTOBUTTON _Toc416840982   
 PAGEREF _Toc416840982  
2.2  Supplemental Retirement Benefit	 
 GOTOBUTTON _Toc416840983   
 PAGEREF _Toc416840983  
2.3  Spouse's Supplemental Retirement Benefit	 
 GOTOBUTTON _Toc416840984   
 PAGEREF _Toc416840984  
2.4  Spouse's Death Benefit	 
 GOTOBUTTON _Toc416840985   
 PAGEREF _Toc416840985  
2.5  Supplemental Disability Benefit	 
 GOTOBUTTON _Toc416840986   
 PAGEREF _Toc416840986  
3.  Retirement Benefits	 
 GOTOBUTTON _Toc416840987   
 PAGEREF _Toc416840987  
3.1  Amount of Supplemental Retirement Benefit	 
 GOTOBUTTON _Toc416840988   
 PAGEREF _Toc416840988  
3.2  Amount of Spouse's Supplemental Retirement Benefit	 
 GOTOBUTTON _Toc416840989   
 PAGEREF _Toc416840989  
3.3  Adjustments	 
 GOTOBUTTON _Toc416840990   
 PAGEREF _Toc416840990  
3.4  Payment	 
 GOTOBUTTON _Toc416840991   
 PAGEREF _Toc416840991  
4.  Supplemental Preretirement Spouse's Death Benefits	 
 GOTOBUTTON _Toc416840992   
 PAGEREF _Toc416840992  
4.1  Benefit	 
 GOTOBUTTON _Toc416840993   
 PAGEREF _Toc416840993  
4.2  Form of Benefit	 
 GOTOBUTTON _Toc416840994   
 PAGEREF _Toc416840994  
5.  Supplemental Disability Benefits	 
 GOTOBUTTON _Toc416840995   
 PAGEREF _Toc416840995  
5.1  Amount	 
 GOTOBUTTON _Toc416840996   
 PAGEREF _Toc416840996  
5.2  Payment	 
 GOTOBUTTON _Toc416840997   
 PAGEREF _Toc416840997  
6.  Administration	 
 GOTOBUTTON _Toc416840998   
 PAGEREF _Toc416840998  
6.1  Authority of Committee	 
 GOTOBUTTON _Toc416840999   
 PAGEREF _Toc416840999  
6.2  Calculation of Benefits	 
 GOTOBUTTON _Toc416841000   
 PAGEREF _Toc416841000  
7.  Miscellaneous	 
 GOTOBUTTON _Toc416841001   
 PAGEREF _Toc416841001  
7.1  Amendment, Termination or Removal of Participant	 
 GOTOBUTTON _Toc416841002   
 PAGEREF _Toc416841002  
7.2  No Employment Right	 
 GOTOBUTTON _Toc416841003   
 PAGEREF _Toc416841003  
7.3  Funding	 
 GOTOBUTTON _Toc416841004   
 PAGEREF _Toc416841004  
7.4  Allocation of Costs	 
 GOTOBUTTON _Toc416841005   
 PAGEREF _Toc416841005  
7.5  Nonassignment	 
 GOTOBUTTON _Toc416841006   
 PAGEREF _Toc416841006  
7.6  Governing Law	 
 GOTOBUTTON _Toc416841007   
 PAGEREF _Toc416841007  
8.  Offset for Certain Benefits Payable Under Split-Dollar Life  
    Insurance	 
 GOTOBUTTON _Toc416841008   
 PAGEREF _Toc416841008  
APPENDIX A 
APPENDIX B 


Exhibit 10.10
SEMPRA ENERGY 
DEFERRED COMPENSATION PLAN FOR DIRECTORS 
I. Purpose 
The purpose of this Plan is to enhance the ability of Sempra Energy to attract  
and retain outstanding members to serve on its Board of Directors. 
II. Definitions 
A. "Account" means each separate unfunded booking account established for a  
Participant under Paragraph A of Article V. 
B. "Beneficiary" means the person or persons or entity or entities designated  
by a Participant to receive the benefits payable to a Beneficiary in  
accordance with Article IX of the Plan after the Participant's death. 
C. "Committee" means the Compensation Committee of the Company's Board of  
Directors. 
D. "Company" means Sempra Energy. 
E. "Compensation" means all compensation earned for services as a Director,  
including retainer payments and meeting and other fees.  
F. "Eligible Director" means each member of the Company's Board of Directors  
who is not an employee of the Company.  
G. "Fixed Account" means the investment option that provides a fixed rate of  
return tied to the Moody's Rate. 
H. "Investment Return" means the actual earnings or loss under any of the  
investment options, other than the fixed return option, made available to the  
Participant. 
I. "Moody's Plus Rate" means the Moody's Rate as defined below plus the  
greater of (1) 10% of the Moody's Rate or (2) one percentage point per annum.   
Moody's Rate is the Moody's Corporate Bond Yield Average - Monthly Average  
Corporates as published by Moody's Investors Service, Inc. (or any successor  
thereto).  The Moody's Rate for the month of June, as used in this Plan, means  
the average of the daily Moody's Rates for June. 
J. "Participant" means an Eligible Director who has elected to defer  
compensation pursuant to Article III. 
K. "Plan" means this Deferred Compensation Plan for Directors. 
L. "Plan Year" means a payroll calendar year except that the first Plan Year  
shall be from July 1, 1998 through December 31, 1998. 
M. "Surviving Spouse" means a Participant's spouse married to the Participant  
on the Participant's date of death and still living on the date benefits are  
payable to a Surviving Spouse under Paragraph B of Article IX of the Plan. 
N. The masculine pronoun whenever used shall include the feminine pronoun, and  
the singular shall include the plural, as the context requires. 
III. Participation 
Election to Participate 
Each Eligible Director shall become a Participant in the Plan by electing to  
defer all or any portion of his Compensation in accordance with Article IV of  
this Plan.  Each Eligible Director shall remain a Participant in the Plan,  
whether or not eligible to continue deferring Compensation until all amounts  
credited to his Account have been distributed or until his death, if earlier. 
IV. Deferral 
A. Amount of Deferral  
An Eligible Director may elect to defer 100% or any smaller percentage of his  
Compensation payable during a Plan Year.  The amount of Compensation deferred  
shall be withheld on the date or dates it otherwise would be payable to the  
Participant. 
B. Election to Defer 
An election to defer shall be made before the beginning of the Plan Year  
during which Compensation is to be earned.  Election shall be in writing,  
shall be modified only by  adjustments permitted under the Plan, shall be made  
at the time and in the form prescribed by the Company, and shall be effective  
only upon delivery to the Company.  The election shall specify the amount  
deferred, the deferral period, the payment method and any other matter  
required to be specified by the Company.  
C. Adjustments and Special Deferral Elections  
Notwithstanding the above, in the event an individual first becomes an  
Eligible Director during any Plan Year for which the Company permits deferrals  
of Compensation, the Eligible Director may elect to defer Compensation  
thereafter payable, as permitted by the Company in its sole and absolute  
discretion.  Such an election must be made by the date specified by the  
Company, and for Compensation payable during the Plan Year of initial  
eligibility, within 30 days of the date the individual first becomes an  
Eligible Director, and for Compensation payable during any subsequent Plan  
Year, before the start of the Plan Year. 
A Participant may modify his/her deferral election in the event that there is  
a change in a Participant's marital status or number of Dependents or there is  
a termination or commencement of employment of the Participant's spouse.  A  
Participant shall be entitled to change his deferral election in a manner that  
is consistent with such change in marital, dependent, or employment status, by  
providing written notice thereof to the Company, in a form acceptable to the  
Company.  Any such change shall be effective on the first day of the calendar  
month next coincident to the month in which written notice is received by the  
Company. 
V. Accounts 
A. Participants' Accounts 
For deferrals permitted by the Company and elected by a Participant a  
separate Account or Accounts shall be established as specified by the Company  
for each Plan Year.  Each Account shall be treated separately for purposes of  
payment of benefits under the Plan.  Compensation shall be credited to each  
Account as of the date they otherwise would have been paid to the  
Participant.  The deferral shall be invested in the Fixed Account or as  
permitted by the Company, to purchase Company stock, or other equity  
securities.  All such purchases must be made through an investment tracking  
device, a Rabbi Trust, or other similar instrument that causes the deferred  
amount not to become taxable to the Participant.  All such purchases must be  
made in accordance with applicable Company procedures as they may be amended  
from time to time.  The Company may permit funds in one investment option to  
be transferred to other investment options. 
B. Interest Credited on Deferrals 
Interest shall be credited to each Account invested in the Fixed Account  
during each Plan Year at a rate equal to the Moody's Plus Rate for the month  
of June immediately prior to the Plan Year in which such interest rate is to  
be credited. The interest rate credited to Participants' Accounts may  
fluctuate from Plan Year to Plan Year.  However, when distribution is to begin  
as to a Participant's Account, and the Participant has elected installment  
payments, the rate shall be fixed on the date installment payments are to  
begin.  The fixed rate shall be the average of the Moody's Plus Rates for the  
June of the five prior calendar years, and that rate thereafter shall be  
credited to the Participant's Account from which the installment payments are  
to be made.  Interest on each Account balance shall be credited monthly at  
one-twelfth the appropriate rate, compounded monthly. 
C. Investment Return Credited on Deferral in  Other Investment Option  
The investment return credited to each Account during each Plan Year shall be  
the actual return earned or lost on the investment option. 
VI. Length of Deferral 
A. Basic Deferral Period 
At the time of electing deferral, a Participant shall select the period of  
deferral from the deferral periods specified by the Company on its prescribed  
election form.  The period of deferral shall end, and distribution from the  
Participant's Account shall begin at the earliest of the Participant's death,  
retirement, or other separation from the Company's Board of Directors, unless  
the Company offers and the Participant selects some other deferral period 
B. In-Service Distributions 
1. Fixed Term Election  
A Participant may elect to receive an in service distribution on such date and  
upon such other terms as the Company specifies at the time of the  
Participant's deferral election provided that no fixed term election shall be  
for a period of less than five years.  Each in service distribution shall  
equal the amount in the account for the Plan Year for which the in service  
distribution is elected  Amounts remaining in the Participant's Account  
thereafter shall continue to accrue interest or Investment Return as the case  
may be. 
2. Unplanned Early Distribution 
Notwithstanding any other provisions of the Plan, by a written request filed  
with the Committee, a Participant, may elect to receive an immediate lump sum  
payment equal to the amount or a percentage of the amount deferred, or the  
actual amount in the Account reduced by a penalty, which shall be forfeited to  
the Plan, equal to ten percent (10%) of the deferrals withdrawn in lieu of  
payments in accordance with the form previously elected by the Participant.   
The Amount remaining in the Participant's Account shall continue to earn  
credited interest or Investment Return.  A participant electing such an early  
in service distribution shall be ineligible to make deferrals for the two  
succeeding Plan Years. 
C. Hardship Withdrawal 
If a Participant suffers an extreme financial hardship, the Committee, in its  
sole and absolute discretion and upon the Participant's written application,  
will determine whether to permit withdrawal from the Participant's Account or  
Accounts.  Any withdrawal that is permitted shall not exceed the amount of  
Compensation deferred by the Participant exclusive of credited interest or the  
actual amount in the Account, if less.  Requests for withdrawals are expected  
to be unusual, and the Committee will make all determinations regarding  
extreme financial hardship in a uniform, nondiscriminatory manner. 
The term "extreme financial hardship" shall mean a severe financial hardship  
to the Participant resulting from a sudden and unexpected illness or accident  
of the Participant or of a dependent (as defined in Section 152(A) of the  
Internal Revenue Code) of the Participant, loss of the Participant's property  
due to casualty, or other similar extraordinary and unforeseeable  
circumstances arising as a result of events beyond the control of the  
Participant.  The circumstances that will constitute an extreme financial  
hardship will depend upon the facts of each case, but, in any case, payment  
may not be made to the extent that such hardship is or may be relieved  
(1) through reimbursement or compensation by insurance or otherwise, (2) by  
liquidation of the Participant's assets, to the extent the liquidation of such  
assets would not itself cause severe financial hardship, or (3) by cessation  
of deferrals under the Plan.  Examples of what are not considered to be  
extreme financial hardships include the need to send a Participant's child to  
college or the desire to purchase a home. 
VII. Method of Distribution 
General Distribution Election Definitions 
Any amount a Participant elects to receive as an in service distribution shall  
be paid to the Participant in a single lump sum, or in such other optional  
form of payment as the Company may offer and the Participant may elect at the  
time of his deferral election.  Distribution of all other amounts credited to  
each Account of a Participant shall be made, as specified by the Participant  
at the time of electing deferral of the Compensation credited to the Account.  
The distribution election may be modified if, and only if, a written change of  
distribution election form is received by the Company no less than 12 months  
prior to the Participant's retirement or other separation from service on the  
Board of Directors. As elected by the Participant, distribution shall be in  
fifteen, ten or five approximately equal annual installments  or in lump sum,  
or in such other payment form as offered by the Company and elected by the  
Participant at the time of electing deferral, except as otherwise provided in  
Article VIII and Article IX.  In the case of installment payments, all  
Participant account balances will be transferred to the Fixed Account.  
Interest at the fixed rate specified in Paragraph B of Article V shall be  
credited on all amounts remaining in the Participant's Account from which the  
installment payments are to be made. 
Notwithstanding anything in this Plan to the contrary, any payment made to a  
Participant or to his Beneficiary shall be according to the Participant's  
election after the distribution event that entitles the Participant or  
Beneficiary to such payment. 
 
 
VIII. Benefits on Death 
Distribution of benefits from each Account of a Participant shall begin as  
soon as practicable following the Participant's death in accordance with  
Paragraph A or B below, depending on whether the Participant dies before or  
after beginning to receive benefits from the Account.  Each Account of a  
Participant shall be treated separately. 
A. Before Payments Have Begun 
If a Participant dies before payment from an Account has begun, other than  
any in service distributions made under Paragraph B(2) of Article VI, the  
Participant's Beneficiary will receive payment of the Participant's Account  
as soon as practicable after the Participant's death, as if the Participant  
had started to receive payment from the Account one day prior to his death.   
Payment to the Beneficiary shall be made in the same payment method as  
elected by the Participant, whether over fifteen, ten or five years, or in  
lump sum, or as otherwise permitted by the Company and elected by the  
Participant at the time of his deferral election or by subsequent election as  
permitted by the Plan.  
B. After Payments Have Begun 
If a Participant dies after beginning to receive payment from an Account,  
other than any in service distributions made under Paragraph B(2) of Article  
VI, the Participant's Beneficiary shall receive the remaining payments to be  
made from the Account if any.  
C. Designation of Beneficiary 
A Participant shall, as a condition of the right to make deferrals, designate  
a Beneficiary to receive the distributions described in Paragraph A or B  
above, whichever is applicable, following his death.  Beneficiary  
designations shall be on the form prescribed by the Company for this purpose  
and shall only be effective upon delivery to the Company before the  
Participant's death.  If a Participant designates a Beneficiary other than  
his spouse, his spouse's written consent to such designation must be obtained  
on the prescribed Beneficiary designation form.  A Participant may change his  
Beneficiary from time to time by delivering a new designation form to the  
Company.  If there is no designated beneficiary living at the time of a  
Participant's death, the estate of the deceased Participant shall be the  
Beneficiary. 
After a Participant's death, a designated Beneficiary who is to receive  
installment payments (not the Participant's estate) may designate a secondary  
beneficiary to receive any amounts due under this Plan to the Beneficiary in  
the event of the death of the Participant's designated Beneficiary prior to  
full payment to the Beneficiary.  If there is no designated secondary  
beneficiary living at the time of death of the Participant's designated  
Beneficiary and installment payments remain to be paid to the Participant's  
Beneficiary, the estate of the Participant's designated Beneficiary shall be  
the beneficiary of any distributions due to the Participant's designated  
Beneficiary under the Plan. 
D. Cash Out of Small Amounts 
Following a Participant's death, the Company shall distribute all amounts  
remaining in the Participant's Account if less than $10,000, but such cash-out  
shall not affect the timing or the amount of benefits payable under Paragraph  
B above. 
E. Modification of Payment Method 
Notwithstanding any other provisions of the Plan, by a written request filed  
with the Committee, a retired Participant, or Beneficiary of a deceased  
Participant receiving benefits from the decedents Deferral Account(s), may  
elect to receive an immediate lump sum payment of the balance of his Deferral  
Account(s), reduced by a penalty, which shall be forfeited to the Plan, equal  
to ten percent (10%) of the balance of such Account(s), in lieu of payments in  
accordance with the form previously elected by the Participant. 
IX. Administration 
This Plan shall be administered by the Committee.  Subject to the express  
provisions of this Plan, the Committee shall have full and final authority to  
interpret the Plan, to prescribe, amend and rescind rules, regulations and  
guidelines relating to the Plan, and to make any other determinations it  
believes necessary or advisable for the administration of the Plan.  All  
decisions and determinations by the Committee shall be final and binding upon  
all parties.  No member of the Committee who is also a Participant in this  
Plan shall decide or vote on any matter that would affect such Participant in  
a manner materially different from other Participants. 
The Company's Senior  Human Resources Officer shall have discretionary  
authority with respect to administrative matters relating to this Plan, except  
when exercise of such authority would materially affect the cost of the Plan  
to the Employer or materially increase benefits to Participants. 
X. Amendment or Termination of the Plan 
The Committee may, in its sole discretion, suspend, amend or terminate this  
Plan at any time, in whole or in part.  However, such action shall be  
prospective only and shall not adversely affect the rights of any Participant,  
Beneficiary or Surviving Spouse to any amounts previously credited to a  
Participant's Account or Accounts under the Plan.  The Committee may increase  
or decrease the interest rate credited to Participants' Fixed Accounts   
including Compensation previously deferred, but the rate shall not be  
decreased for periods prior to such action.  Any termination of the Plan shall  
not result in automatic payment of Accounts, and Participants' Accounts shall  
be paid under the terms of the Plan as in effect prior to termination.   
However, in the event a final determination is made by a court of competent  
jurisdiction, or by the relevant tax authorities, and no appeal is taken  
therefrom, that amounts deferred under this Plan are taxable income to a  
Participant prior to the time they otherwise would be distributed under the  
Plan, the Committee may terminate the Plan as to such Participant and  
immediately pay to him, or on his death to his Beneficiary, all amounts that  
are so taxable. 
XI. Miscellaneous 
A. Insurance 
As a condition of participation in this Plan, each Participant shall, if  
requested by the Company, undergo such examination and provide such  
information as may be required by the Company with respect to any insurance  
contracts on the Participant's life, and shall authorize the Company to  
purchase life insurance on his life, payable to the Company. 
If an insurance policy is invalidated because a Participant commits suicide  
during the two-year period beginning on the first day of the first Plan Year  
of such Participant's participation in the Plan, or if the Participant makes  
any material misstatement of information or nondisclosure of medical history,  
then no benefits will be payable hereunder to such Participant, his  
Beneficiary or his Surviving Spouse, other than payment of the amount of  
deferrals of Compensation then credited to the Participant's Accounts, without  
any interest, including interest theretofore credited under this Plan. 
B. Source of Payment 
This Plan is unfunded, and distributions shall be made solely on a current  
disbursement basis.  Each Participant, his Beneficiary and his Surviving  
Spouse shall be no more than unsecured general creditors of the Company, and  
nothing contained in this Plan shall be deemed to create a trust of any kind,  
for the benefit of any Participant, Beneficiary or Surviving Spouse, or create  
any fiduciary relationship between the Company and any Participant,  
Beneficiary, or Surviving Spouse with respect to any assets of the Company,  
including, but not limited to, any insurance policies which the Company may  
purchase on the life of the Participant. 
The Company, however, retains the right to establish reserves for the  
obligations hereunder including, but not limited to corporate owned life  
insurance, and assets held in a "Rabbi Trust."  Provided that in the event  
that the Chief Executive Officer determines that a change in control as  
defined in the Sempra Energy Long Term Incentive Plan, is imminent then assets  
shall be placed in the Key Employee and Director Deferred Compensation Trust  
Agreement which when combined with any assets then in the trust shall equal  
the full accrued liability under this Plan as determined by Towers and Perrin,  
or a successor actuarial firm.  
C. Withholding 
Each Participant, Beneficiary and Surviving Spouse to whom distribution is  
made shall make appropriate arrangements for the satisfaction of any federal,  
state, or local income tax withholding requirements, any social security or  
other employment tax requirements applicable to the payment of benefits under  
this Plan, and any payments the Participant agreed to make to the Company or  
to his Employer.  If no other arrangements are made, the Company may provide,  
at its discretion, for such withholding and tax payments as may be required. 
D. Nonassignment 
To the maximum extent permitted by law, no benefit under this Plan shall be  
assignable or subject in any manner to alienation, sale, transfer, claims of  
creditors, pledge, attachment or encumbrances of any kind. 
E. Governing Law 
This Plan is established under and will be construed according to the laws of  
the State of California to the extent that such laws are not preempted by the  
Employee Retirement Income Security Act of 1974, as amended. 
F. Effective Date 
This Plan is effective June 1, 1998 
SEMPRA ENERGY 
DEFERRED COMPENSATION PLAN FOR DIRECTORS 
(Effective June 1, 1998) 
Contents 
I. Purpose 1 
II. Definitions 1 
III. Participation 3 
IV. Deferral 3 
A. Amount of Deferral 3 
B. Election to Defer 3 
C. Adjustments and Special 
 Deferred Elections 4 
V. Accounts 5 
A. Participants' Accounts 5 
B. Interest Credited on Deferrals 6 
C. Investment Return Credited on 
Deferral in Other Investment Option 6 
VI. Length of Deferral 7 
A. Basic Deferral Period 7 
B. In-Service Distributions 7 
1. Fixed Term Election 7 
2. Unplanned Early Distribution 8 
C. Hardship Withdrawal 8 
VII. Method of Distribution 9 
General Distribution Election Definitions 9 
VIII. Benefits on Death 11 
A. Before Payments Have Begun 11 
B. After Payments Have Begun 11 
C. Designation of Beneficiary 12 
D. Cash Out of Small Amounts 13 
E. Modification of Payment Method 13 
IX. Administration 13 
X. Amendment or Termination of the Plan 14 
XI. Miscellaneous 15 
A. No Employment Right 15 
B. Insurance 16 
C. Source of Payment 17 
D. Withholding 17 
E. Nonassignment 17 
F. Governing Law 17 
G. Effective Date 17 
 
- -ii-  
 
vi 
 


Exhibit 10.11
SEMPRA ENERGY 
EXECUTIVE INCENTIVE PLAN 
 
1. Purpose 
The purpose of this Plan, which is an unfunded plan, is to foster attainment  
of the financial and strategic objectives of Sempra Energy (the "Company") by  
providing incentive to senior officers  who contribute to the attainment of  
these objectives. 
2. Administration 
The Plan shall be administered jointly by the Compensation Committee of the  
Company's Board of Directors and as to any employee of a Subsidiary, the  
Compensation Committee, if any, of the board of directors of such Subsidiary  
(collectively referred to as the "Committee").  Subject to the provisions of  
the Plan, the Committee shall have full and final authority to select  
participants, to designate the award potential of each participant, to  
determine performance objectives and to determine the amount and form of  
awards.  The Committee shall also have, subject to the provisions of the  
Plan, full and final authority to interpret the Plan, to establish and revise  
rules, regulations and guides relating to the Plan, and to make any other  
determinations that it believes necessary or advisable for the administration  
of the Plan.  The Committee may delegate its responsibilities, (other than  
the responsibility to select the participants, establish performance goals,  
determine incentive periods, establish award potentials for each participant,  
certify whether the performance goals are met), to the Chief Executive  
Officer of the Company ("Chief Executive Officer") or to any other officer of  
the Company. 
All decisions and determinations by the Committee shall be final and binding  
upon all parties, including shareholders, participants and other employees. 
The Committee shall have sole discretion as to whether to suspend operation  
of the Plan for any period of time. 
3. Participation 
Senior Officers of the Company or any of its Subsidiaries as designated who,  
through their position and performance, have the opportunity to contribute  
substantially to the attainment of the financial objectives of the Company  
are eligible for selection to participate in this Plan.  A Subsidiary for  
this purpose is any corporation of which 50 percent or more of the issued and  
outstanding stock having ordinary voting rights is owned directly or  
indirectly by the Company, or any other business entity or association of  
which 50 percent or more of the outstanding equity interest is so owned. 
Members of the Board of Directors of the Company or any Subsidiary, who are  
not officers of the Company or its Subsidiaries, are ineligible to  
participate in the Plan. No member of the Committee shall be eligible to  
participate. 
4. INCENTIVE AWARDS 
a. Annual Awards 
If the Committee determines that participants shall be eligible to earn  
awards over a fiscal year ("award period"), it shall, no later than 90 days  
after the commencement of that award period select from the eligible  
participant group those participants who are eligible to receive awards for  
that award period and approve in writing threshold, target and maximum  
performance  goals for that year for the Company, any Subsidiary employing a  
selected participant and/or any Business Unit for which a selected  
participant has substantial duties and responsibilities.  For this purpose, a  
Business Unit means a division, department or other business segment which is  
part of the Company or of a Subsidiary.  The Committee may also select an  
award period of 12 months other than a fiscal year or an award period either  
longer or shorter than 12 months in duration but only one award period may be  
in operation at any time in respect to any particular employee. In the event  
that an award period of less than 12 months is selected, the Committee shall  
select the participants and the financial goals before the expiration of 25%  
of such award period. 
Performance goals shall be limited to one or more of the following: (i) net  
revenue; (ii) net earnings; (iii) operating earnings or income; (iv) absolute  
and/or relative return on equity or assets; (v) earnings per share; (vi) cash  
flow; (vii) pretax profits; (viii) earnings growth; (ix) revenue growth; (x)  
book value per share; (xi) stock price; (xii) economic value added; (xiii)  
total shareholder return; (xiv) operating goals (including, but not limited  
to, safety, reliability, maintenance expenses, capital expenses, customer  
satisfaction and employee satisfaction); and (xv) performance relative to  
peer companies, each of which may be established on a corporate-wide basis or  
established with respect to one or more operating units, divisions, acquired  
businesses, minority investments, partnerships or joint ventures. 
At the same time that the Committee approves the performance goals, the  
Committee shall approve in writing a threshold, target and maximum award for  
each participant.  Each participant's award shall be based upon the  
responsibility of the participant's position and its prospective contribution  
to the Company's or Subsidiary's, attainment of performance objectives.  If  
the performance is somewhere between the threshold and target, or target and  
maximum performance goals, a participant's award shall be mathematically  
interpolated on a linear basis between threshold award and target award or  
between target award and maximum award. 
b. Incentive periods of less duration than the award period. 
During an award period, the Committee may select additional employees for  
participation, as it deems appropriate, who have been first employed or had a  
change in employment responsibilities since the beginning of the award period  
provided that the outcome of the selected performance goal for that award  
period for the Company, Subsidiary or Business Unit employing such employee  
remains substantially uncertain at that time.  In this event, the incentive  
period shall begin with the first day of employment or change in employment  
responsibilities and end with the close of that award period.  If the  
employee was already a participant in this plan prior to the change in  
employment responsibilities, the employee's award potential for the period of  
service prior to the change in employment responsibilities shall be prorated  
based on the ratio that the prior period of service bears to the applicable  
award period. 
Prior to the expiration of 25% of the applicable period of service for that  
incentive period and while the outcome of the selected performance goal is  
still substantially uncertain, the Committee shall approve in writing a  
threshold, target and maximum award for that participant depending on whether  
the threshold, target or maximum performance goal for the award period is  
achieved and a maximum dollar amount (which may not exceed $3,000,000 for the  
purpose of qualifying under 162(m) provisions) that can be paid to each  
participant under this plan for the incentive period.  In the event that no  
performance goal has been previously selected for that award period for the  
Company, Subsidiary or Business Unit employing the participant, the Committee  
shall also establish in writing threshold, target and maximum performance  
goals for that year for that entity from the factors listed in section 4a of  
this plan.  The outcome of the goals selected must be substantially  
uncertain. 
If the performance is somewhere between the threshold and target, or target  
and maximum performance goals, a participant's award shall be mathematically  
interpolated on a linear basis between the threshold and target award or  
between the target and maximum award. 
c. Certification and Payments of Award 
As soon as practicable after the end of an award period or incentive period  
the Committee shall certify in writing the extent to which the performance  
goals have been met and determine the amount, if any, of each participant's  
award before payment of the award.   
All awards under the plan are contingent upon the material terms of the  
performance goals being submitted to and approved by the shareholders. 
5. Award Payment or Deferral 
As soon as practicable after the Committee has approved the award amounts for  
an award period or incentive period, payment shall be made to each  
participant in cash or  in stock or in a combination of cash and stock,  
unless the participant has elected to defer the receipt of his award. Any  
deferral by a participant of an annual incentive award otherwise payable in  
cash under this Plan shall be pursuant to the Sempra Energy Corporation  
Executive Deferred Compensation Plan .  Provided however, that if the maximum  
deductible compensation limits of IRS Code Section 162(m) are exceeded then  
such deferral as may be necessary to avoid such limitation, shall be  
mandatory for the participants at the discretion of the Compensation  
Committee. 
6. Termination 
If the employment of a participant by the Company and its subsidiaries is  
terminated by the participant's death, long term disability or retirement  
under the pension plan of the Company or a subsidiary, the Committee shall  
prorate an award for the award period or incentive period in which the  
employee was participating prior to such termination, and the Company shall  
pay the prorated award at the same time as for other participants. In the  
case of a participant's death, payment of all amounts due under this Plan  
shall be made to the estate. 
A participant who has been determined to be eligible for supplemental  
disability payments under the terms of the Supplemental Executive Retirement  
Plan, and who has received at least 6 months of payments, shall be deemed to  
be terminated due to such disability for purposes of this Plan.   
If termination occurs because of unsatisfactory performance or for cause, as  
determined in the sole discretion of the Committee then there will be no  
award for the year of termination. 
If the employment of a participant is terminated for any other reason, the  
participant may receive a prorated award for any award period or incentive  
periods in which the participant was participating at the time of  
termination, as determined by the Committee in its sole discretion. 
If a participant does not work during an award period or incentive period for  
any period of time and for any reason and yet is entitled to an award under  
this Plan for participation during such award period or incentive period, the  
Committee may reduce or eliminate the participant's award because of the  
inactive period in such manner as it, in its sole discretion, deems just and  
reasonable. 
The Committee also retains the discretion to terminate the participation of  
any participant during an award period or incentive period if the Committee  
determines, in the Committee's sole discretion, that the participant is not  
contributing substantially to the attainment of the performance objectives of  
the Company and that such termination of participation is just and reasonable  
under the circumstances. In the event of such termination, the participant  
will be entitled to no award for that award period or incentive period. 
7. Miscellaneous Provisions 
a. No Employment Right 
Neither this Plan nor any action taken hereunder shall be construed as giving  
any employee any right to be retained in the employ of the Company or any of  
its subsidiaries or interfere in any way with the right of the Company or any  
of its subsidiaries to determine a participant's compensation or any other  
term of employment. 
b. Non-transferability 
A participant's rights and interests under this Plan may not be assigned,  
transferred, attached or hypothecated. 
c. Withholding 
The participant's employer shall have the right to deduct from any payment  
any sums required to be withheld by federal, state, or local tax law. 
There is no obligation hereunder that any participants or other person be  
advised in advance of the existence of the tax or the amount so required to  
be withheld. 
8. Amendment and Termination 
The Board of Directors of the Company may at any time, suspend, amend, modify  
or terminate this Plan provided that no such suspension, amendment,  
modification or termination shall alter or impair any rights or obligations  
to any award made previously under this Plan.  The Committee may, in its sole  
discretion, terminate an award period and any associated incentive periods at  
any time.  In this event, any potential awards for that award period or  
incentive period shall be prorated to the time of termination. 
9. Effective Date 
This Plan shall be effective as of June 1, 1998. 


Exhibit 10.12
SEMPRA ENERGY 
EXECUTIVE DEFERRED COMPENSATION PLAN  
I. Purpose 
The purpose of this Plan is to provide the opportunity to defer the receipt  
of compensation to a select group of executives upon whose judgment,  
initiative and efforts the continued success of the Sempra Energy Companies  
is dependent. 
II. Definitions 
A. "Account" means each separate unfunded booking account established for a  
Participant under Paragraph A of Article V. 
B. "Beneficiary" means the person or persons or entity or entities designated  
by a Participant to receive the benefits payable to a Beneficiary in  
accordance with Article IX of the Plan after the Participant's death. 
C. "Committee" means the Compensation Committee of the Company's Board of  
Directors. 
D. "Company" means Sempra Energy. 
E. "Disability" means any disability for which a Participant is entitled to  
benefits under the Sempra Energy Benefit Plan, the Southern California Gas  
Company Disability Benefit Plan, the San Diego Gas & Electric Long Term  
Disability Plan, the Sempra Energy Supplemental Executive Retirement Plan, or  
any other long-term disability plan of an Employer, and any continuation of  
such disability, while a Participant is not covered by such plans, which  
prevents a Participant from engaging in the principal duties of his  
employment, as verified to the Committee's satisfaction. 
F. "Employer" means the Company and any of its subsidiaries (any corporation  
of which 50% or more of the issued and outstanding stock having ordinary  
voting rights is owned directly or indirectly by the Company or any other  
business entity or association of which 50% or more of the outstanding equity  
interest is so owned) which adopt this Plan, or as the context requires, a  
Participant's particular employer. 
G. "Fixed Account" means the investment option that provides a fixed rate of  
return tied to the Moody's Rate. 
H. "Incentive Compensation" means the annual incentive award earned by a  
Participant under the Sempra Energy Executive Incentive Plan, and any other  
incentive compensation as specified by the Committee. 
I. "Investment Return" means the actual earnings or loss under any of the  
investment options, other than the fixed return option, made available to the  
Participant. 
J. "Moody's Plus Rate" means the Moody's Rate as defined below plus the  
greater of (1) 10% of the Moody's Rate or (2) one percentage point per annum.   
Moody's Rate is the Moody's Corporate Bond Yield Average - Monthly Average  
Corporates as published by Moody's Investors Service, Inc. (or any successor  
thereto).  The Moody's Rate for the month of June, as used in this Plan,  
means the average of the daily Moody's Rates for June. 
K. "Participant" means an eligible employee who has elected to defer  
compensation pursuant to Article III. 
L. "Plan" means this Executive Deferred Compensation Plan. 
M. "Plan Year" means a payroll calendar year except that the first Plan Year  
shall be from July 1, 1998 through December 31, 1998. 
N. "Salary" means base salary. 
O. "Surviving Spouse" means a Participant's spouse married to the Participant  
on the Participant's date of death and still living on the date benefits are  
payable to a Surviving Spouse under Paragraph B of Article IX of the Plan. 
P. The masculine pronoun whenever used shall include the feminine pronoun,  
and the singular shall include the plural, as the context requires. 
III. Participation 
A. Eligibility to Participate 
Executive Officers of the Company as designated shall be eligible to  
participate in this Plan.  The Committee may designate additional officers  
and key employees of the Employer who shall participate in this Plan and the  
effective date of such participation, subject to agreement by the Board of  
Directors of the executive's Employer (if not the Company) that such  
executive participate and that such Employer pay the costs of this Plan for  
the executive and his Surviving Spouse. 
B. Election to Participate 
Each eligible employee shall become a Participant in the Plan by electing to  
defer Salary, dividend equivalents, Incentive Compensation or all in  
accordance with Article IV of this Plan.  Each eligible employee shall remain  
a Participant in the Plan, whether or not eligible to continue deferring  
Salary and Incentive Compensation, until all amounts credited to his Account  
have been distributed or until his death, if earlier. 
IV. Deferral 
A. Amount of Deferral 
An eligible employee may elect to defer 100% or any smaller percentage of his  
Salary payable during a Plan Year, subject to a $10,000 minimum amount. An  
eligible employee may elect to defer 100% or any smaller percentage of his  
Incentive Compensation and dividend equivalents earned during a Plan Year,  
whether or not he elects to defer Salary payable during the Plan Year, as  
permitted by the Company.  The amount of Salary and Incentive Compensation  
deferred shall be withheld on the date or dates they otherwise would be  
payable to the Participant. 
B. Election to Defer 
An election to defer shall be made before the beginning of the Plan Year  
during which Salary is to be paid and Incentive Compensation is to be earned.   
Election shall be in writing, shall be modified only by  adjustments  
permitted under the Plan, shall be made at the time and in the form  
prescribed by the Company, and shall be effective only upon delivery to the  
Company.  The election shall specify the amount deferred, the deferral  
period, the payment method and any other matter required to be specified by  
the Company.  
C. Adjustments and Special Deferred Elections  
A mid-year election to make deferrals of Salary and or Bonus under the plan  
shall be permitted within 30 days of the commencement of employment or of any  
other event resulting in new eligibility. 
A Participant may modify his/her deferral election in the event that there is  
a change in a Participant's marital status or number of Dependents or there  
is a termination or commencement of employment of the Participant's spouse.   
A Participant shall be entitled to change his deferral election in a manner  
that is consistent with such change in marital, dependent, or employment  
status, by providing written notice thereof to the Company, in a form  
acceptable to the Company.  Any such change shall be effective on the first  
day of the calendar month next coincident to the month in which written  
notice is received by the Company. 
V. Accounts 
A. Participants' Accounts  
For deferrals permitted by the Company and elected by a Participant a  
separate Account or Accounts shall be established as specified by the Company  
for each Plan Year.  Each Account shall be treated separately for purposes of  
payment of benefits under the Plan.  Salary, Incentive Compensation and  
dividend equivalents shall be credited to each Account as of the date they  
otherwise would have been paid to the Participant.  The deferral shall be  
invested in the Fixed Account or as permitted by the Company, to purchase  
Company stock, or other equity securities.  All such purchases must be made  
through an investment tracking device, a Rabbi Trust, or other similar  
instrument that causes the deferred amount not to become taxable to the  
Participant.  All such purchases must be made in accordance with applicable  
Company procedures as they may be amended from time to time.  The Company may  
permit funds in one investment option to be transferred to other investment  
options. 
B. Interest Credited on Deferrals Invested in the Fixed Account  
Interest shall be credited to each Account invested in the Fixed Account  
during each Plan Year at a rate equal to the Moody's Plus Rate for the month  
of June immediately prior to the Plan Year in which such interest rate is to  
be credited. The interest rate credited to Participants' Accounts may  
fluctuate from Plan Year to Plan Year.  However, when distribution is to  
begin as to a Participant's Account, and the Participant has elected  
installment payments, the rate shall be fixed on the date installment  
payments are to begin.  The fixed rate shall be the average of the Moody's  
Plus Rates for the June of the five prior calendar years, and that rate  
thereafter shall be credited to the Participant's Account from which the  
installment payments are to be made.  Interest on each Account balance shall  
be credited monthly at one-twelfth the appropriate rate, compounded monthly. 
C. Investment Return Credited on Deferral in Other Investment Option 
The investment return credited to each Account during each Plan Year shall be  
the actual return earned or lost in the investment option. 
VI. Length of Deferral  
A. Basic Deferral Period 
At the time of electing deferral, a Participant shall select the period of  
deferral from the deferral periods specified by the Company on its prescribed  
election form.  The period of deferral shall end, and distribution from the  
Participant's Account shall begin at the earliest of the Participant's death,  
retirement, or separation of service for any other reason unless the Company  
offers and the Participant selects some other deferral period. 
B. In-Service Distributions 
1. Fixed Term Election 
A Participant may elect to receive an in-service distribution on such date  
and upon such other terms as the Company specifies at the time of the  
Participant's deferral election provided that no fixed term election shall be  
for a deferral period of less than five years.  Each in-service distribution  
shall equal the amount in the account for the Plan Year for which the in- 
service distribution is elected.  Amounts remaining in the Participant's  
Account thereafter shall continue to accrue interest or Investment Return as  
the case may be. 
2. Unplanned Early Distribution 
Notwithstanding any other provisions of the Plan, by a written request filed  
with the Committee, a Participant, may elect to receive an immediate lump sum  
payment equal to the amount or a percentage of the amount deferred, or the  
actual amount in the Account, reduced by a penalty, which shall be forfeited  
to the Plan, equal to ten percent (10%) of the deferrals withdrawn in lieu of  
payments in accordance with the form previously elected by the Participant.   
The Amount remaining in the Participant's Account shall continue to earn  
credited interest, or Investment Return.  A participant electing such an  
early in service distribution shall be ineligible to make deferrals for the  
two succeeding Plan Years. 
C. Hardship Withdrawal 
If a Participant suffers an extreme financial hardship, the Committee, in its  
sole and absolute discretion and upon the Participant's written application,  
will determine whether to permit withdrawal from the Participant's Account or  
Accounts.  Any withdrawal that is permitted shall not exceed the amount of  
Salary, Incentive Compensation and dividend equivalents deferred by the  
Participant exclusive of credited interest or the actual amount in the  
Account, if less.  Requests for withdrawals are expected to be unusual, and  
the Committee will make all determinations regarding extreme financial  
hardship in a uniform, nondiscriminatory manner. 
The term "extreme financial hardship" shall mean a severe financial hardship  
to the Participant resulting from a sudden and unexpected illness or accident  
of the Participant or of a dependent (as defined in Section 152(A) of the  
Internal Revenue Code) of the Participant, loss of the Participant's property  
due to casualty, or other similar extraordinary and unforeseeable  
circumstances arising as a result of events beyond the control of the  
Participant.  The circumstances that will constitute an extreme financial  
hardship will depend upon the facts of each case, but, in any case, payment  
may not be made to the extent that such hardship is or may be relieved  
(1) through reimbursement or compensation by insurance or otherwise, (2) by  
liquidation of the Participant's assets, to the extent the liquidation of  
such assets would not itself cause severe financial hardship, or (3) by  
cessation of deferrals under the Plan.  Examples of what are not considered  
to be extreme financial hardships include the need to send a Participant's  
child to college or the desire to purchase a home. 
VII. Method of Distribution 
General Distribution Election Definitions 
Any amount a Participant elects to receive as an in service distribution  
shall be paid to the Participant in a single lump sum, or in such other  
optional form of payment as the Company may offer and the Participant may  
elect at the time of his deferral election.  Distribution of all other  
amounts credited to each Account of a Participant shall be made, as specified  
by the Participant at the time of electing deferral of the Salary, Incentive  
Compensation and dividend equivalents credited to the Account. The  
distribution election may be modified if, and only if, a written change of  
distribution election form is received by the Company no less than 12 months  
prior to the Participant's retirement or termination. As elected by the  
Participant, distribution shall be in fifteen, ten or five approximately  
equal annual installments  or in lump sum, or in such other payment form as  
offered by the Company and elected by the Participant at the time of electing  
deferral, except as otherwise provided in Article VIII and Article IX.  In  
the case of installment payments, all Participant account balances will be  
transferred to the Fixed Account at the value on the date of the first  
distribution. Interest at the fixed rate specified in Paragraph B of Article  
V shall be credited on all amounts remaining in the Participant's Account  
from which the installment payments are to be made.  
Notwithstanding anything in this Plan to the contrary, any payment made to a  
Participant or to his Beneficiary shall be paid according to the  
Participant's election after the distribution event that entitles the  
Participant or Beneficiary to such payment. 
VIII. Termination of Employment 
A. Accelerated Payment of Benefits 
If a Participant's employment with his Employer is terminated for any reason  
whatsoever all of the Participant's Accounts shall be paid to him in lump sum  
as soon as practicable thereafter, unless at least one year prior to  
termination, the Participant made a supplemental election of a termination  
distribution in either 5, 10, or 15 approximately equal annual installments   
as provided in Article VII, Paragraph B.  A Participant who has transferred  
to work for the Company or any of its subsidiaries, shall not be considered  
to have terminated employment with his Employer for purposes of this Article.   
However, any salary received from a subsidiary of the Company which is not an  
Employer under the Plan, shall not be deferred, despite any previous deferral  
election. Incentive Compensation paid by the prior Employer that the  
Participant elected to defer prior to the transfer will be deferred. 
B. Earnings 
The interest rate which shall apply to the Participant's Fixed Accounts shall  
be the Moody's Plus Rate specified in Paragraph B of Article V.  The earnings  
credited to the funds in other investment options shall be done in accordance  
with Section V(C).   
C. Disability 
A Participant who is unable to work due to Disability shall not be considered  
to have terminated employment for purposes of this Plan.  Any deferral  
election made by the Participant shall remain in effect to the extent that  
the Participant thereafter receives Salary or Incentive Compensation.   
Disability income received on account of Disability shall not be treated as  
Salary unless the Committee determines otherwise, taking into consideration  
the best interests of the Company. 
IX. Benefits on Death 
Distribution of benefits from each Account of a Participant shall begin as  
soon as practicable following the Participant's death in accordance with  
Paragraph A or B below, depending on whether the Participant dies before or  
after receiving benefits.  Each Account of a Participant shall be treated  
separately. 
A. Before Payments Have Begun 
If a Participant dies before payment from an Account has begun, other than  
any in service distributions made under Paragraph B(2) of Article VI, the  
Participant's Beneficiary will receive payment of the Participant's Account  
as soon as practicable after the Participant's death, as if the Participant  
had started to receive payment from the Account one day prior to his death.   
Payment to the Beneficiary shall be made in the same payment method as  
elected by the Participant, whether over fifteen, ten or five years, or in  
lump sum, or as otherwise permitted by the Company and elected by the  
Participant at the time of his deferral election or by subsequent election as  
permitted by the Plan.  
B. After Payments Have Begun 
If a Participant dies after beginning to receive payment from an Account,  
other than any in service distributions made under Paragraph B(2) of Article  
VI, the Participant's Beneficiary shall receive the remaining payments to be  
made from the Account if any.  
C. Designation of Beneficiary 
A Participant shall, as a condition of the right to make deferrals, designate  
a Beneficiary to receive the distributions described in Paragraph A or B  
above, whichever is applicable, following his death.  Beneficiary  
designations shall be on the form prescribed by the Company for this purpose  
and shall only be effective upon delivery to the Company before the  
Participant's death.  If a Participant designates a Beneficiary other than  
his spouse, his spouse's written consent to such designation must be obtained  
on the prescribed Beneficiary designation form.  A Participant may change his  
Beneficiary from time to time by delivering a new designation form to the  
Company.  If there is no designated beneficiary living at the time of a  
Participant's death, the estate of the deceased Participant shall be the  
Beneficiary. 
After a Participant's death, a designated Beneficiary who is to receive  
installment payments (not the Participant's estate) may designate a secondary  
beneficiary to receive any amounts due under this Plan to the Beneficiary in  
the event of the death of the Participant's designated Beneficiary prior to  
full payment to the Beneficiary.  If there is no designated secondary  
beneficiary living at the time of death of the Participant's designated  
Beneficiary and installment payments remain to be paid to the Participant's  
Beneficiary, the estate of the Participant's designated Beneficiary shall be  
the beneficiary of any distributions due to the Participant's designated  
Beneficiary under the Plan. 
D. Cash Out of Small Amounts 
Following a Participant's death, the Company shall distribute all amounts  
remaining in the Participant's Account if less than $10,000, but such cash- 
out shall not affect the timing or the amount of benefits payable under  
Paragraph B above. 
E. Modification of Payment Method 
Notwithstanding any other provisions of the Plan, by a written request filed  
with the Committee, a retired Participant, or Beneficiary of a deceased  
Participant receiving benefits from the decedents Deferral Account(s), may  
elect to receive an immediate lump sum payment of the balance of his Deferral  
Account(s), reduced by a penalty, which shall be forfeited to the Plan, equal  
to ten percent (10%) of the balance of such Account(s), in lieu of payments  
in accordance with the form previously elected by the Participant. 
X. Administration 
This Plan shall be administered by the Committee.  Subject to the express  
provisions of this Plan, the Committee shall have full and final authority to  
interpret the Plan, to prescribe, amend and rescind rules, regulations and  
guidelines relating to the Plan, and to make any other determinations it  
believes necessary or advisable for the administration of the Plan.  All  
decisions and determinations by the Committee shall be final and binding upon  
all parties.  No member of the Committee who is also a Participant in this  
Plan shall decide or vote on any matter that would affect such Participant in  
a manner materially different from other Participants. 
The Company's Senior  Human Resources Officer shall have discretionary  
authority with respect to administrative matters relating to this Plan,  
except when exercise of such authority would materially affect the cost of  
the Plan to the Employer, materially increase benefits to Participants, or  
affect such Senior Officer in a manner materially different from other  
Participants. 
XI. Amendment or Termination of the Plan 
The Committee may, in its sole discretion, suspend, amend or terminate this  
Plan at any time, in whole or in part.  However, such action shall be  
prospective only and shall not adversely affect the rights of any  
Participant, Beneficiary or Surviving Spouse to any amounts previously  
credited to a Participant's Account or Accounts under the Plan.  The  
Committee may increase or decrease the interest rate credited to  
Participants' Fixed Accounts, including Salary, Incentive Compensation and  
dividend equivalents previously deferred, but the rate shall not be decreased  
for periods prior to such action.  Any termination of the Plan shall not  
result in automatic payment of Accounts, and Participants' Accounts shall be  
paid under the terms of the Plan as in effect prior to termination.  However,  
in the event a final determination is made by a court of competent  
jurisdiction, or by the relevant tax authorities, and no appeal is taken  
therefrom, that amounts deferred under this Plan are taxable income to a  
Participant prior to the time they otherwise would be distributed under the  
Plan, the Committee may terminate the Plan as to such Participant and  
immediately pay to him, or on his death to his Beneficiary, all amounts that  
are so taxable. 
XII. Miscellaneous 
A. No Employment Right 
Nothing contained herein shall confer upon any Participant the right to be  
retained in employment by his Employer, nor will it interfere with the right  
of his Employer to discharge or otherwise deal with the Participant without  
regard to the existence of this Plan. 
B. Insurance 
As a condition of participation in this Plan, each Participant shall, if  
requested by the Company, undergo such examination and provide such  
information as may be required by the Company with respect to any insurance  
contracts on the Participant's life, and shall authorize the Company to  
purchase life insurance on his life, payable to the Company. 
If an insurance policy is invalidated because a Participant commits suicide  
during the two-year period beginning on the first day of the first Plan Year  
of such Participant's participation in the Plan, or if the Participant makes  
any material misstatement of information or nondisclosure of medical history,  
then no benefits will be payable hereunder to such Participant, his  
Beneficiary or his Surviving Spouse, other than payment of the amount of  
deferrals of Salary, Incentive Compensation and dividend equivalents then  
credited to the Participant's Accounts, without any interest, including  
interest theretofore credited under this Plan. 
C. Source of Payment 
This Plan is unfunded, and distributions shall be made solely on a current  
disbursement basis.  Each Participant, his Beneficiary and his Surviving  
Spouse shall be no more than unsecured general creditors of the Company, and  
nothing contained in this Plan shall be deemed to create a trust of any kind,  
for the benefit of any Participant, Beneficiary or Surviving Spouse, or  
create any fiduciary relationship between the Company and any Participant,  
Beneficiary, or Surviving Spouse with respect to any assets of the Company,  
including, but not limited to, any insurance policies which the Company may  
purchase on the life of the Participant. 
The Company, however, retains the right to establish reserves for the  
obligations hereunder including, but not limited to corporate owned life  
insurance, and assets held in a "Rabbi Trust."  Provided that in the event  
that the Chief Executive Officer determines that a change in control as  
defined in the Sempra Energy Long Term Incentive Plan, is imminent then  
assets shall be placed in the Deferred Compensation Trust which when combined  
with any assets then in the trust shall equal the full accrued liability  
under this Plan as determined by Towers and Perrin, or a successor actuarial  
firm.  
D. Withholding 
Each Participant, Beneficiary and Surviving Spouse to whom distribution is  
made shall make appropriate arrangements for the satisfaction of any federal,  
state, or local income tax withholding requirements, any social security or  
other employment tax requirements applicable to the payment of benefits under  
this Plan, and any payments the Participant agreed to make to the Company or  
to his Employer.  If no other arrangements are made, the Company may provide,  
at its discretion, for such withholding and tax payments as may be required. 
E. Nonassignment 
To the maximum extent permitted by law, no benefit under this Plan shall be  
assignable or subject in any manner to alienation, sale, transfer, claims of  
creditors, pledge, attachment or encumbrances of any kind. 
F. Governing Law 
This Plan is established under and will be construed according to the laws of  
the State of California to the extent that such laws are not preempted by the  
Employee Retirement Income Security Act of 1974, as amended. 
G. Effective Date 
This Plan is effective June 1, 1998. 
 


Exhibit 10.13
SEMPRA ENERGY 
RETIREMENT PLAN FOR DIRECTORS 
Effective June 1, 1998 
 
 
1. Purpose 
The purpose of this unfunded plan is to retain outstanding directors for  
Sempra Energy. 
2. Eligibility 
Members of the Sempra Energy Board of Directors who participated in a  
Director Retirement Plan maintained by Pacific Enterprises, Enova  
corporation or San Diego Gas & Electric ("Prior Plan") shall be eligible  
to participate in this Plan which is a successor to the Prior Plan. 
Directors shall retire no later than the Annual Meeting of the company  
held on or after the director's 72nd birthday. 
3. Benefit Amount 
Each eligible director is entitled to an annual retirement benefit equal  
to the sum of (a) the then-current year's annual base retainer  
(exclusive of any amount paid for committee service); and (b) the then- 
current fee for attending a regularly scheduled meeting of the full  
Board in California, multiplied by 10, subject to upward adjustments if  
the retainer and/or meeting fee increases subsequent to retirement.  In  
the event that an increase occurs, the directors' retirement benefit  
will be adjusted effective with the next scheduled payment.  Retirement  
benefits payable to directors who retired under a Prior Plan, are  
governed by that plan as in effect at the time of retirement. 
The amount of the annual retirement benefit will not be affected by a  
director's deferral of compensation under the Deferred Compensation Plan  
for Directors. 
4. Benefit Duration 
Benefit payments will start on the first day of the calendar quarter on  
or after the date an eligible director leaves the Board, provided the  
director is at least age 65.  An eligible director who leaves the Board  
prior to age 65 will start receiving benefit payments on the first day  
of the calendar quarter in which the director turns 65.  Benefits will  
be paid on the first day of each quarter thereafter, and will be paid  
for a period equal to the length of the director's service as an outside  
director under the Prior Plan plus the director's service as an outside  
director under this plan to a maximum of the greater of five years or  
ten years less the years of Participation under the Prior Plan or until  
death, whichever occurs first. Each quarterly payment will be one-fourth  
the annual retirement benefit.  There are no death benefits payable  
under this plan except as provided in paragraph 5. 
5. Survivor Benefits 
If a married eligible director dies after the start of benefit payments,  
his/her surviving spouse shall receive the remaining payments, if any,  
to which the eligible director would have been entitled but for his/her  
death.  Such benefits will cease upon the surviving spouse's death.  If  
an eligible married director dies prior to the start of benefit  
payments, his/her surviving spouse will start receiving benefits  
calculated pursuant to paragraph 3, on the first day of the calendar  
quarter next following the eligible director's death.  Benefits will be  
paid for a period equal to the length of the eligible director's service  
as an outside director or until the surviving spouse's death, whichever  
occurs first. 
6. Administration 
The Company's Compensation Committee shall have full and final authority  
to interpret this plan and to make determinations that it believes  
advisable for the administration of the plan.  All decisions and  
determinations by the Compensation Committee shall be final and binding  
upon all parties. 
7. Grandfather Benefit 
In the event that the retirement benefit calculated under the terms of a  
Prior Plan is greater than the benefit amount under paragraph 3 herein,  
the eligible director shall receive a benefit equal to such Prior Plan  
retirement benefit subject to the maximum provided in 4 above.