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

                  SAN DIEGO GAS & ELECTRIC COMPANY
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      (Exact name of registrant as specified in its charter)

CALIFORNIA                     1-3779               95-1184800
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(State of incorporation        (Commission         (I.R.S. Employer
or organization)               File Number)      Identification No.

8326 CENTURY PARK COURT, SAN DIEGO, CALIFORNIA                92123
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(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 
-------------------                           --------------------- 
Preference Stock (Cumulative)                              American
  Without Par Value (except $1.70 and $1.7625 Series)
Cumulative Preferred Stock, $20 Par Value
     (except 4.60% Series)
 
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 68.  Glossary on page 76.  
 
Aggregate market value of the voting preferred stock held by non-
affiliates of the registrant as of March 26, 1999 was 
$22.9 million.
 
Registrant's common stock outstanding as of March 26, 1999 was 
wholly owned by Enova Corporation.
 
DOCUMENTS INCORPORATED BY REFERENCE: 
Portions of the Information Statement prepared for the May 1999 
annual meeting of shareholders are incorporated by reference into 
Part III. 
 

                        TABLE OF CONTENTS

PART I
Item 1.  Business . . . . . . . . . . . . . . . . . . . . . . .  3
Item 2.  Properties . . . . . . . . . . . . . . . . . . . . . . 18
Item 3.  Legal Proceedings. . . . . . . . . . . . . . . . . . . 18
Item 4.  Submission of Matters to a Vote of Security Holders. . 19
         Executive Officers of the Registrant . . . . . . . . . 19

PART II
Item 5.  Market for Registrant's Common Equity and Related
            Stockholder Matters . . . . . . . . . . . . . . . . 19
Item 6.  Selected Financial Data. . . . . . . . . . . . . . . . 20
Item 7.  Management's Discussion and Analysis of Financial
            Condition and Results of Operations . . . . . . . . 20
Item 7A. Quantitative and Qualitative Disclosures
            About Market Risk . . . . . . . . . . . . . . . . . 34
Item 8.  Financial Statements and Supplementary Data. . . . . . 35
Item 9.  Changes In and Disagreements with Accountants on
            Accounting and Financial Disclosure . . . . . . . . 64

PART III
Item 10. Directors and Executive Officers of the Registrant . . 64
Item 11. Executive Compensation . . . . . . . . . . . . . . . . 64
Item 12. Security Ownership of Certain Beneficial Owners
            and Management. . . . . . . . . . . . . . . . . . . 65
Item 13. Certain Relationships and Related Transactions . . . . 65

PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
            on Form 8-K . . . . . . . . . . . . . . . . . . . . 65

Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . 67

Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . 68

Glossary. . . . . . . . . . . . . . . . . . . . . . . . . . . . 76



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

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

GOVERNMENT REGULATION

Local Regulation
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 
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.

Other regulatory matters are described throughout this report.


SOURCES OF REVENUE

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

   Electric:
       Residential                  $     637  $     684  $     647
       Commercial/Industrial              876        948        886
       Other                              352        137         58
                                    ---------  ---------  ---------
         Total Electric Revenues        1,865      1,769      1,591
                                    ---------  ---------  ---------
   Gas:
       Residential                        258        241        210
       Commercial/Industrial              105        120        101
       Utility Electric Generation         21         37         37
                                    ---------  ---------  ---------
         Total Gas Revenues               384        398        348
                                    ---------  ---------  ---------
   PX/ISO Power                           500         --         --
                                    ---------  ---------  ---------
         Total Utility Revenues     $   2,749  $   2,167  $   1,939
                                    =========  =========  =========

Industry segment information is contained in "Management's Discussion 
and Analysis of Financial Condition and Results of Operations" and in 
Note 13 of the "Notes to Consolidated Financial Statements" herein.

NATURAL GAS OPERATIONS

SDG&E distributes natural gas to 721,000 customers in San Diego and 
southern Orange counties throughout a 4,100-square-mile service 
territory. The Company purchases natural gas for resale to its 
customers and for fuel in its generating plants.

Supplies of Natural Gas 
The Company buys natural gas primarily from various spot-market 
suppliers. It also has natural gas transportation contracts with 
pipeline companies, which expire at various dates through 2023.

Most of the natural gas purchased and delivered by the Company is 
produced outside of California. These supplies originate in New 
Mexico, Oklahoma and Texas and are transported to the SoCalGas 
pipeline at the California border by El Paso Natural Gas Company and 
by Transwestern Pipeline Company. The rates that interstate pipeline 
companies may charge for natural gas and transportation services are 
regulated by the FERC. All natural gas is delivered to SDG&E under a 
transportation and storage agreement with SoCalGas.

SDG&E has four long-term natural gas supply contracts with four 
Canadian suppliers. The Company has been in negotiations and 
litigation with the suppliers concerning the contracts' terms and 
prices. Of the four contracts, three have been settled. Additional 
information regarding natural gas contracts is provided in Note 11 of 
the "Notes to Consolidated Financial Statements" herein. 

During 1998, SDG&E received natural gas from one Canadian supplier 
based on terms of the settlement agreement. Natural gas from Canada 
is transported to SDG&E's system over Alberta Natural Gas, Pacific 
Gas Transmission and Pacific Gas & Electric (PG&E) pipelines. 

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


<TABLE>
<CAPTION>
                                                                Year Ended December 31
                                          -------------------------------------------------------------------
                                            1998           1997          1996           1995           1994
-------------------------------------------------------------------------------------------------------------
<S>                                       <C>            <C>           <C>            <C>            <C>
Gas Purchases (billions of cubic feet)       118            101            97             90             95

Customer-Owned and
  Exchange Receipts                           19             18            17             17             15

Storage Withdrawal
   (Injection) - Net                          (3)             1                            2             (1)

Company Use and
  Unaccounted For                             (2)            (1)           (1)            (1)            (2)
                                          -------        -------       -------        -------        -------
    Net Deliveries                           132            119           113            108            107 
                                          =======        =======       =======        =======        =======


Cost of Gas Purchased 
  (millions of dollars)                    $ 318          $ 311         $ 252          $ 188          $ 246
                                          -------        -------       -------        -------        -------

Average Cost of Gas Purchased
  (Dollars per Thousand Cubic Feet)        $2.69          $3.08         $2.59          $2.08          $2.60
                                          =======        =======       =======        =======        =======

</TABLE>


Market-sensitive natural gas supplies (supplies purchased on the 
spot market as well as under longer-term contracts based on spot 
prices) accounted for nearly 100 percent of total natural gas 
volumes purchased by the Company during the last five years. These 
supplies were generally purchased at prices significantly below 
those of long-term sources of supply.

The Company provided transportation services for the customer-owned 
natural gas. 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 721,000 core customers (694,000 million 
residential and 27,000 small commercial and industrial). Noncore 
customers consist primarily of utility electric generation (UEG), 
wholesale, and large commercial and industrial customers, and total 
113.

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.

For 1998, approximately 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 services is less than for 
natural gas sales, the Company generally earns the same margin 
whether the Company buys the gas and sells it to the customer or 
transports natural gas already owned by the customer.

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 12,000 
new natural gas customers in 1998. This represents a growth rate of 
approximately 1.6 percent. The Company expects its growth for 1999 
will continue at about the 1998 level.

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 113, they accounted for 
approximately 32 percent of the authorized natural gas revenues and 
64 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 the Company's generation plants is also greatly affected by the 
price and availability of electricity.

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 11 of the "Notes to Consolidated Financial 
Statements" herein.

ELECTRIC OPERATIONS

Resource Planning
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 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 11 and 12 of the 
"Notes to Consolidated Financial Statements" herein.

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 distribute. 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 5, 11 and 12 of the "Notes 
to Consolidated Financial Statements" herein.

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 11 of the "Notes to Consolidated Financial Statements" herein.

Power Pools    
In 1964 SDG&E, 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 below) 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" herein.

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 11 of the "Notes to Consolidated Financial Statements" 
herein.

RATES AND REGULATION

SDG&E is regulated by the CPUC, which consists of five 
commissioners appointed by the Governor of California for staggered 
six-year terms. Two of the five commissioner positions are 
currently vacant. It is the responsibility of the CPUC to determine 
that utilities operate within the best interests of their 
customers. The regulatory structure is complex and has a 
substantial impact on the profitability of the Company. Both the 
electric and natural 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 12 of the "Notes to Consolidated Financial Statements" herein.

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 12 of the "Notes to Consolidated Financial 
Statements" herein.

Balancing Accounts
Previously, earnings fluctuations from changes in the costs of 
electric fuel, 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" herein.

Performance-Based Regulation (PBR)
To promote efficient operations and improved productivity and to 
move away from reasonableness reviews and disallowances, the CPUC 
has been directing utilities to use PBR. PBR has replaced the 
general rate case and certain other regulatory proceedings for 
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 12 of the "Notes to Consolidated Financial Statements" herein.

Biennial Cost Allocation Proceeding (BCAP)
Rates to recover the changes in natural gas fuel costs and changes 
in the cost of natural gas transportation services are determined 
in the BCAP. The BCAP adjusts rates to reflect variances in core 
customer demand from estimates previously used in establishing core 
customer rates. The mechanism substantially eliminates the effect 
on core income of variances in core market demand and natural gas 
costs. Additional information on the BCAP is discussed in 
"Management's Discussion and Analysis of Financial Condition and 
Results of Operations" and in Note 12 of the "Notes to Consolidated 
Financial Statements" herein.

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 12 of 
the "Notes to Consolidated Financial Statements" herein.

Cost of Capital
Under PBR, annual Cost of Capital proceedings have been replaced by 
an automatic adjustment mechanism if changes in certain indices 
exceed established tolerances. 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 a rate of return on common equity of 11.6 percent and a rate 
of return on rate base of 9.35 percent. Additional information on 
the utility's cost of capital is discussed in "Management's 
Discussion and Analysis of Financial Condition and Results of 
Operations" and in Note 12 of the "Notes to Consolidated Financial 
Statements" herein.

ENVIRONMENTAL MATTERS

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

Hazardous Substances
The utility lawfully disposed of wastes at facilities owned and 
operated by other entities. Operations at these facilities may 
result in actual or threatened risks to the environment or public 
health. Under California law, redevelopment agencies are authorized 
to require landowners to cleanup property within their jurisdiction 
or, where the landowner or operator of such a facility fails to 
complete any corrective action required, applicable environmental 
laws may impose an obligation to undertake corrective actions on 
the utility and others who disposed of hazardous wastes at the 
facility.

The Redevelopment Agency for the City of San Diego has exerted this 
authority affecting the Company's Station A facility and adjacent 
properties to accommodate a major league ballpark and ancillary 
development proposed by the City. During the early 1900s, SDG&E and 
its predecessors manufactured gas from coal and oil at the 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. A risk assessment 
has been completed for Station A and demolition was performed 
during 1997 at a cost of $1 million. Initial cleanup actions 
commenced in 1998, and are expected to be completed in 1999, at an 
estimated cost of $5 million. SDG&E is negotiating with the 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 agency will 
retain its rights to enforce the cleanup in the event SDG&E does 
not complete it. Contaminants resulting from the gas-manufacturing 
process by-products were assessed at the 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, 
SDG&E 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.  

SDG&E is in the process of selling its electric-generating assets. 
As a part of its environmental due diligence, the utility 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 SDG&E's other transition costs.

SDG&E has been named as a potential responsible party (PRP) for an 
industrial waste disposal site as described below.

SDG&E and 10 other entities have been named PRPs by the California 
Department of Toxic Substances Control (DTSC) as liable for any 
required corrective action regarding contamination at a site in 
Pico Rivera, California. DTSC has taken this action because the 
utility and others sold used electrical transformers to the site's 
owner. The DTSC considers SDG&E 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 utility's estimated remaining 
investigation and remediation liability related to hazardous waste 
sites (non-PRP sites) was $15 million, of which 90 percent is 
authorized to be recovered through the Hazardous Waste 
Collaborative mechanism. SDG&E 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 the 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 Rule 69 
compliance costs to increase.
	
Wastewater discharge permits issued by the Regional Water Quality 
Control Board (RWQCB) for the utility'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, SDG&E 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 
offshore 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 
utility for the South Bay power plant. SDG&E filed an appeal to the 
State Water Resources Control Board (SWRCB) of various provisions, 
which the utility 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 SDG&E thereafter appealed to the San Diego County 
Superior Court. These latter issues were subsequently settled 
through negotiations between SDG&E and the RWQCB. All of the 
settled issues have been incorporated into the November 1996 
National Pollutant Discharge Elimination System 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. SDG&E cannot predict the cost of 
such cleanup.

In May 1987 the RWQCB issued SDG&E a cleanup and abatement order 
for gasoline contamination originating from an underground storage 
tank located at the utility'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. SDG&E 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" herein.

Research, Development and Demonstration (RD&D)
As a result of electric-industry restructuring, SDG&E has 
significantly reduced its electric RD&D program. Effective January 
1, 1998, the CEC began administering the electric public purpose 
RD&D programs to which SDG&E contributes $3.9 million annually. In 
December 1998, the CPUC approved SDG&E's $1.2 million request to 
fund natural gas RD&D programs. SDG&E will use these revenues to 
fund gas projects that add value to the utility and its customers. 
Annual RD&D costs have averaged $5.2 million over the past three 
years.

Employees of Registrant
As of December 31, 1998, SDG&E had 2,982 employees, compared to 
3,576 at December 31, 1997. This decrease is related to synergies 
resulting from the PE/Enova Business Combination and the shifting 
of certain functions to Sempra Energy.

Certain employees at SDG&E are represented by the International 
Brotherhood of Electrical Workers, Local 465, with two labor 
agreements. The generation contract runs through February 28, 2001 
and negotiations for the utility contract (transmission and 
distribution) are ongoing.

ITEM 2. PROPERTIES

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

SDG&E'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
SDG&E's natural gas facilities are located in San Diego and 
Riverside counties and consist of the Moreno and Rainbow compressor 
stations, 167 miles of high pressure transmission pipelines, 6,858 
miles of high and low pressure distribution mains, and 5,695 miles 
of service lines.

Other Properties
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.

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

ITEM 3. LEGAL PROCEEDINGS

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


ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
        None

ITEM 4. EXECUTIVE OFFICERS OF THE REGISTRANT

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

Edwin A. Guiles           49     President and Chief Financial 
                                 Officer

Gary D. Cotton            58     Senior Vice President - Fuels & 
                                 Power Operations

Steven D. Davis           42     Vice President and Corporate
                                 Secretary

Pamela J. Fair            40     Vice President - Marketing &
                                 Customer Services

*  As of December 31, 1998.

Each Executive Officer has been an officer of Sempra Energy or one 
of its subsidiaries for more than five years.



                             PART II

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

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

Dividend Restrictions
The CPUC regulates SDG&E's capital structure, limiting the 
dividends it may pay.  At December 31, 1998, $183 million of 
retained earnings was available for future dividends.


ITEM 6. SELECTED FINANCIAL DATA


<TABLE>
(Dollars in millions)
<CAPTION>
                                      At December 31, or for the years then ended
                                    ------------------------------------------------
                                       1998      1997      1996      1995      1994 
                                    --------   -------   -------   -------   -------
<S>                                 <C>        <C>       <C>       <C>       <C>    
Income Statement Data:
   Operating Revenues                 $2,749    $2,167    $1,939    $1,814    $1,857
   Operating Income                   $  286    $  317    $  309    $  315    $  303
   Dividends on Preferred Stock       $    6    $    6    $    6    $    8    $    8
   Earnings Applicable to 
      Common Shares                   $  185    $  232    $  216    $  226    $  136

Balance Sheet Data:
   Total Assets                       $4,257    $4,654    $4,161    $4,473    $4,353
   Long-Term Debt                     $1,548    $1,788    $1,285    $1,217    $1,214
   Short-Term Debt (a)                $   72    $   73    $   34    $  124    $  182
   Shareholders' Equity               $1,227    $1,490    $1,508    $1,639    $1,593


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

Since San Diego Gas & Electric Company is a wholly owned subsidiary of Enova 
Corporation, per share data has been omitted.

This data should be read in conjunction with the consolidated financial statements 
and notes to consolidated financial statements contained herein.

</TABLE>


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

Introduction
This section includes management's analysis of operating results 
from 1996 through 1998, and is intended to provide additional 
information about the capital resources, liquidity and financial 
performance of San Diego Gas & Electric (SDG&E or the Company). 
This section also focuses on the major factors expected to 
influence future operating results and discusses investment and 
financing plans. It should be read in conjunction with the 
Consolidated Financial statements included in this Annual Report.
     The Company is an operating public utility engaged in the 
electric and natural gas businesses. It generates and purchases 
electric energy and distributes it to 1.2 million customers in San 
Diego County and an adjacent portion of Orange County, California.   
It also purchases and distributes natural gas to 721,000 customers 
in San Diego County and transports electricity and gas for others.  
SDG&E's only subsidiary is described below under "Electric Rates."  

Business Combinations
Sempra Energy (Sempra) was formed to serve as a holding company for 
SDG&E's parent, Enova Corporation (Enova), and Pacific Enterprises 
(PE), the parent company of Southern California Gas Company 
(SoCalGas) in connection with a business combination that became 
effective on June 26, 1998 (the PE/Enova Business Combination).  
Expenses incurred by SDG&E in connection with the business 
combination are $35 million, aftertax, and $11 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 Enova and PE each became holders of 
Sempra Energy common stock. PE's common shareholders received 
1.5038 shares of Sempra Energy's common stock for each share of PE 
common stock, and Enova's common shareholders received one share of 
Sempra Energy's common stock for each share of Enova common stock. 
The combination was approved by the shareholders of both companies 
on March 11, 1997 and was a tax-free transaction.

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

Sources and (Uses) of Cash
                                         Year Ended December 31, 
(Dollars in millions)                   1998        1997      1996
-------------------------------------------------------------------
Operating activities                   $ 535       $ 381     $ 529 
                                 ----------------------------------
Investing activities: 
  Capital expenditures                  (227)       (197)     (209)
  Other - net                            (50)        (17)      (25)
                                 ----------------------------------
      Total investing activities        (277)       (214)     (234)
                                 ----------------------------------
Financing activities:
  Dividends paid                        (269)       (256)     (189)
  Long-term debt - net                  (241)        544       (31)
  Redemption of preferred stock           --          --       (15)
                                 ----------------------------------
      Total financing activities        (510)        288      (235)
                                 ----------------------------------
Increase (decrease) in cash  
      and cash equivalents             $(252)      $ 455     $  60 
-------------------------------------------------------------------

Cash Flows from Operating Activities
The increase in cash flows from operating activities in 1998 was 
primarily due to the acceleration of depreciation of electric-
generating assets, partially offset by recovery of stranded costs 
via the competition transition charge and the 10-percent rate 
reduction reflected in customers' bills. The increase was also 
partially offset by expenses incurred in connection with the 
PE/Enova Business Combination.
     The decrease in cash flows from operating activities in 1997 
was primarily due to increased working capital requirements.

Cash Flows from Investing Activities
Capital expenditures were $30 million higher in 1998 than in 1997 
due to increased spending for system integrity and reliability 
projects, restoration of service and mandated programs.
    Capital expenditures were $12 million lower in 1997 than in 
1996 due to changes in scope and timing of several major capital 
projects.
    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, the 
Company and the other SONGS owners have requested the CPUC for 
authority to begin decommissioning Unit 1 on January 1, 2000. See 
Note 5 of the notes to 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 generating facilities.  In December 1998, 
SDG&E entered into agreements to accomplish that. Completion is 
pending regulatory approval and is expected during the first half 
of 1999. See "Electric-Generation Assets" below for further 
discussion.  Anticipated proceeds from these plant assets, net of 
the assets' book value, the costs of sales and certain 
environmental cleanup costs, will be applied for accounting 
purposes directly to the recovery of the Company'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 are estimated to be $240 million in 1999. 
They will be financed primarily by internally generated funds and 
will largely represent investment in rate base.  The level of 
capital expenditures in the next few years will depend heavily on 
the impacts of electric-industry restructuring and the timing and 
extent of expenditures to comply with environmental requirements.

Cash Flows from Financing Activities
Net cash used in financing activities increased in 1998 due to the 
issuance of Rate Reduction Bonds in 1997 (see "Long-Term Debt" 
below) and greater long-term debt repayments in 1998. 
     Net cash provided by financing activities increased in 1997 
primarily due to issuance of the Rate Reduction Bonds partially 
offset by higher dividends paid.

Long-Term Debt
In December 1997, $658 million of Rate Reduction Bonds were issued 
on the Company's behalf at an average interest rate of 6.26 
percent.  A portion of the bond proceeds was used to retire 
variable-rate, taxable IDBs. Additional information concerning the 
Rate Reduction Bonds is provided below under "Electric Industry 
Restructuring." In 1998, cash was used for the repayment of $147 
million of first mortgage bonds and $66 million of rate reduction 
bonds. 
    In 1997, cash was used for the repayment of $127 million of 
first mortgage bonds. This was more than offset by the issuance of 
$25 million in Medium-Term Notes and $658 million of Rate Reduction 
Bonds.
    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 consist 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.

Dividends
Common stock dividends amounted to $269 million, $256 million and 
$189 million in 1998, 1997 and 1996, respectively.  
    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 57 percent at year-end 1998, 
above the 56 percent ratio in 1997. The increase was primarily due 
to the declaration of dividends to Enova. The debt-to-
capitalization ratio increase to 56 percent in 1997 from 48 percent 
in 1996 was primarily due to the issuance of Rate Reduction Bonds.

Cash and Temporary Investments
Cash and temporary investments were $284 million at December 31, 
1998. The Company anticipates that cash required in 1999 for 
capital expenditures, dividends and debt payments will be provided 
by cash generated from operating activities and existing cash 
balances.
     In addition to cash from ongoing operations, the Company has 
multi-year credit agreements that permit term borrowing of up to 
$295 million.  At December 31, 1998 all bank lines of credit were 
unused.  For further discussion, see Note 3 of the notes to 
Consolidated Financial statements.

Ratemaking Procedures

To understand the operations and financial results of the Company 
it is important to understand the ratemaking procedures that the 
Company follows.
    The Company is regulated by the CPUC. It is the responsibility 
of the CPUC to determine that utilities operate in the best 
interest of their customers and have the opportunity to earn a 
reasonable return on investment.  In response to utility-industry 
restructuring, SDG&E received approval from the CPUC for 
performance-based regulation (PBR).
    PBR replaced the general rate case (GRC) procedure and certain 
other regulatory proceedings.  Under ratemaking procedures in 
effect prior to PBR, the Company typically filed a GRC with the 
CPUC every three years. In a GRC, the CPUC establishes a base 
margin, which is the amount of revenue to be collected from 
customers to recover authorized operating expenses (other than the 
cost of 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 and electric-
industry restructuring in Note 12 of the notes to Consolidated 
Financial Statements.


Results of Operations 
1998 Compared to 1997
Net income for 1998 decreased 20 percent to $191 million in 1998, 
compared to net income of $238 million in 1997. The decrease in net 
income was primarily due to higher PE/Enova Business Combination 
costs, lower incentive awards for performance-based ratemaking, and 
changes in regulatory mechanisms for recording revenues due to 
electric industry restructuring. Included in the calculation of 
pretax income are PE/Enova Business Combination costs of $35 
million, aftertax, in 1998 and $11 million, aftertax, in 1997. 
These nonrecurring expenses consist primarily of employee-related 
costs, and investment banking, legal, regulatory and consulting 
fees. 
    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 startup of operations of the Power Exchange (PX) 
and the Independent System Operator (ISO). These factors were 
partially offset by a decrease in retail revenues 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 startup of the PX. The 10-percent rate 
reduction and the PX are described under "Factors Influencing 
Future Performance" and in Note 12 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. 
    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 86 percent in 
1998 due to the recovery of stranded costs via the CTC. The 
financial impact of the increase is offset by CTC revenue (see 
above).
    Operating expenses increased 32 percent in 1998 primarily due 
to the higher PE/Enova Business Combination costs and higher 
electric-distribution maintenance costs primarily related to the 
Company's tree-trimming program.

1997 Compared to 1996
Net income for 1997 increased 7 percent to $238 million compared to 
net income of $222 million in 1996.  The increase in earnings was 
primarily due to higher incentive awards for performance-based 
ratemaking and demand-side management, partially offset by the 
PE/Enova Business Combination costs.   
    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.
    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. 

The table below summarizes the components of electric
volumes and revenues by customer class for 1998, 1997 and 1996. 


<TABLE>
Electric Distribution
(Dollars in millions, volumes in millions of Kwhrs)
<CAPTION>
                                   1998              1997               1996
                        ----------------------------------------------------------
                             Volumes  Revenue  Volumes  Revenue   Volumes  Revenue
                        ----------------------------------------------------------
<S>                         <C>       <C>      <C>      <C>        <C>      <C>
  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
                        ----------------------------------------------------------
</TABLE>


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

KN Energy Acquisition.  On February 22, 1999, Sempra Energy 
announced a definitive agreement to acquire KN Energy, Inc., 
subject to approval by the shareholders of both companies and by 
various regulatory agencies. See Note 14 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 12 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 
cost-of-service regulation.
     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 the Company'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 12 of the notes to Consolidated 
Financial Statements for additional information.

Electric Generation Assets. In November 1997, the Company 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. The 
plan included the divestiture of the Company'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).
     In March 1998, the CPUC's decision approving the PE/Enova 
Business Combination required, among other things, the divestiture 
by the Company of its fossil-fueled generation units.  On December 
11, 1998, the Company entered into agreements for the sale of the 
Company's South Bay and Encina Power Plants 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 
12 of the notes to Consolidated Financial Statements for additional 
information.

Electric Rates. AB 1890 provides for a 10-percent reduction of 
residential and small commercial customers effective January 1998, 
and provided for the issuance of rate-reduction bonds by an agency 
of the State of California to enable the 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 the Company'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 the Company 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 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, the Company sold to SDG&E Funding LLC all of its rights 
to the revenue streams. Consequently, the revenue streams are not 
the property of the Company and are not available to creditors of 
the Company.
     AB 1890 also included a rate freeze for all customers. Until 
the earlier of March 31, 2002, or when transition cost recovery is 
complete, the Company's average system rate will be frozen at 9.64 
cents per kilowatt-hour (kwh), 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. The Company'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, the Company 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 12 of 
the notes to Consolidated Financial Statements.

Regulatory Accounting Standards.  The Company is accounting for the 
economic effects of regulation on its 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 
ratemaking process, the utility will recover the asset from 
customers. Regulatory liabilities represent future reductions in 
revenues for amounts due to customers.  See Notes 2 and 12 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, effective January 1, 
1998, is to ensure that the Company's 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 the 
Company 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 12 of the notes to Consolidated Financial 
Statements for additional information.

Allowed Rate of Return. For 1998, 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 12 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 capital  
investment within the amounts authorized to be collected in rates.
It is the intent of management to control operating expenses and 
capital investments within the amounts authorized to be collected 
in rates in the PBR decision. The Company intends to make the 
efficiency improvements, changes in operations and cost reductions 
necessary to achieve this objective and earn its authorized rate of 
return. However, in view of the earnings-sharing mechanism and 
other elements of the PBR, it is more difficult to achieve returns 
at least at or in excess of authorized returns at levels 
experienced in past years. See additional discussion of PBR in Note 
12 of the notes to Consolidated Financial Statements.

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, $4 million in 1997 and $6 
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 the Company's divestiture of its 
electric generating assets is discussed above under "Electric 
Generation Assets" and in Note 12 of the notes to Consolidated 
Financial Statements.
 
Hazardous Substances.  In 1994, the CPUC approved the Hazardous 
Waste Collaborative, a mechanism which allows the Company 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 CTC recovery process described above.   
     During the early 1900s, the Company and its predecessors 
manufactured gas from coal or oil, the sites of which have often 
become contaminated with the hazardous residual by-products of the 
process. The Company 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.  Ninety percent of the Company's 
costs to clean up the gas plants and to meet their PRP obligations, 
a total estimated to be $15 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), the Company retained 
limited remediation obligations for contamination existing on these 
sites upon the closing of the sales. The Company'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, the 
Company 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. The Company'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 costs 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 operations. 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.

Other Income, Interest Expense and Income Taxes 
Other Income
Other income, which primarily consists of interest income from 
short-term investments and regulatory accounts receivable balances, 
increased in 1998 to $21 million from $7 million in 1997.  The 
increase was primarily due to interest earned on temporary 
investment balances, which were higher in 1998 than in 1997 due to 
cash received from the issuance of the rate-reduction bonds in 
December 1997.  Other income increased slightly in 1997 to $7 
million from $4 million in 1996.

Interest Expense 
Interest expense for 1998 increased to $116 million from $86 
million in 1997 primarily due to the issuance of rate-reduction 
bonds in December 1997. Interest expense for 1997 decreased to $86 
million from $91 million in 1996 as a result of lower long-term 
debt balances throughout most of 1997.

Income Taxes 
Income tax expense was $142 million, $219 million and $198 million 
in 1998, 1997 and 1996, respectively.  These represent effective 
tax rates of 43 percent, 48 percent and 47 percent for the same 
periods.  The decrease in the effective tax rate in 1998 is 
primarily due to tax issues related to the recovery of CTC.

Derivative Financial Instruments
The Company's policy is to use derivative financial instruments to 
manage exposure to fluctuations in interest rates, foreign currency 
exchange rates and energy prices. Transactions involving these 
financial instruments are with reputable firms and major exchanges. 
The use of these instruments may expose the Company to market and 
credit risks. At times, credit risk may be concentrated with 
certain counterparties, although counterparty nonperformance is not 
anticipated. 
    The Company 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 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 and 1997, the notional amount of swap transactions totaled $45 
million. See Note 9 of the notes to Consolidated Financial 
Statements for further information regarding these swap 
transactions.
    The Company uses energy derivatives to manage natural gas price 
risk associated with servicing its load requirements. These 
instruments include forward contracts, futures, swaps, options and 
other contracts, with maturities ranging from 30 days to 12 months. 
In the case of price-risk management activities, the use of 
derivative financial instruments by the Company is subject to 
certain limitations imposed by established Company policy and 
regulatory requirements. See Note 9 of the notes to Consolidated 
Financial Statements and the "Market Risk Management Activities" 
section below for further information regarding the use of energy 
derivatives by the Company.
 
Market Risk Management Activities
Market risk is the risk of erosion of the Company's cash flows, net 
income and asset values due to adverse changes in interest and 
foreign-currency rates, and in prices for energy. The Company has 
adopted corporate-wide policies governing its market-risk 
management activities.  An Energy Risk Management Oversight 
Committee, consisting of senior corporate officers, oversees 
Company-wide energy-price risk-management activities to ensure 
compliance with the Company's stated energy risk-management 
policies.
    Along with other tools, the Company uses Value at Risk (VaR) to 
measure its exposure to market risk. VaR is an estimate of the 
potential loss on a position or portfolio of positions over a 
specified holding period, based on normal market conditions and 
within a given statistical confidence level. The Company has 
adopted the variance/covariance methodology in its calculation of 
VaR, and uses a 95 percent confidence level. Holding periods are 
specific to the types of positions being measured, and are 
determined based on the size of the position or portfolios, market 
liquidity, tenor and other factors. Historical volatilities and 
correlations between instruments and positions are used in the 
calculation.
    The following is a discussion of the Company's primary market-
risk exposures as of December 31, 1998, including a discussion of 
how these exposures are managed.

Interest Rate Risk
The Company is exposed to fluctuations in interest rates primarily 
as a result of its fixed-rate long-term debt. The Company has 
historically funded its operations through long-term bond issues 
with fixed interest rates. With the restructuring of the regulatory 
process, greater flexibility has been permitted within the debt-
management process. As a result, recent debt offerings have been 
selected with short-term maturities to take advantage of yield 
curves or used a combination of fixed- and floating-rate debt. 
Interest rate swaps, subject to regulatory constraints, may be used 
to adjust interest-rate exposures when appropriate, based upon 
market conditions.
    The VaR on the Company's fixed rate long-term debt is estimated 
at approximately $129 million as of December 31, 1998, assuming a 
one-year holding period.

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 is 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. 

Market Risk
The Company 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 framework. As of 
December 31, 1998 the total VaR of the Company'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 12 of the notes 
to Consolidated Financial Statements and the discussion under the 
"Factors Influencing Future Performance" section for further 
information regarding the electricity rate cap. 

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 
issue impacts 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 
Sempra Energy's overall Year 2000 readiness effort. Sempra Energy 
has established a central Year 2000 Program Office which reports to 
the its Chief Information Technology Officer and reports 
periodically to the audit committee of the Board of Directors.

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


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

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

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

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

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information required by Item 7A is set forth under "Item 7. 
Management's Discussion and Analysis of Financial Condition and 
Results of Operations - Market Risk Management Activities."


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEPENDENT AUDITORS' REPORT

To the Board of Directors and Shareholders of San Diego Gas & 
Electric Company:

     We have audited the accompanying consolidated balance sheets 
of San Diego Gas & Electric Company and subsidiary 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 San 
Diego Gas & Electric Company and subsidiary 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 14 as to which the date is
February 22, 1999



<TABLE> 
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED INCOME 
Dollars in millions
<CAPTION> 
                                                      
For the years ended December 31                           1998     1997     1996   
                                                       -------   -------   ------- 
<S>                                                    <C>       <C>       <C>     
Operating Revenues   
  Electric                                              $1,865    $1,769    $1,591  
  PX / ISO power                                           500        --        --  
  Gas                                                      384       398       348  
                                                        -------   -------   ------- 
   Total                                                 2,749     2,167     1,939  
                                                        -------   -------   ------- 
Expenses   
  Electric fuel                                            177       164       134  
  Purchased power                                          292       441       311  
  PX / ISO power                                           468        --        --  
  Gas purchased for resale                                 166       183       152  
  Maintenance                                              106        87        58  
  Depreciation and decommissioning                         603       324       314  
  Property and other taxes                                  42        43        45  
  General and administrative                               290       213       248  
  Other                                                    186       178       166  
  Income taxes                                             133       217       202  
                                                        -------   -------   ------- 
   Total                                                 2,463     1,850     1,630  
                                                        -------   -------   ------- 
Operating Income                                           286       317       309  
                                                        -------   -------   ------- 
Other Income and (Deductions) 
  Allowance for equity funds used                                                   
    during construction                                      5         5         5  
  Taxes on nonoperating income                              (9)       (2)        4  
  Other - net                                               25         4        (5) 
                                                        -------   -------   ------- 
   Total                                                    21         7         4  
                                                        -------   -------   ------- 
Income Before Interest Charges                             307       324       313  
                                                        -------   -------   ------- 
Interest Charges                                                                    
 Long-term debt                                             96        69        76  
 Short-term debt and other                                  14        14        13  
 Amortization of debt discount and
   expense, less premium                                     8         5         5  
 Allowance for borrowed funds                                                       
   used during construction                                 (2)       (2)       (3) 
                                                        -------   -------   ------- 
   Total                                                   116        86        91  
                                                        -------   -------   ------- 
Net Income                                                 191       238       222  
Preferred Dividend Requirements                              6         6         6  
                                                        -------   -------   ------- 
Earnings Applicable to Common Shares                    $  185    $  232    $  216  
                                                        =======   =======   ======= 

See notes to Consolidated Financial Statements. 
</TABLE>

<TABLE> 
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS    
Dollars in millions
<CAPTION> 
Balance at December 31                                       1998         1997 
                                                           -------      -------
<S>                                                       <C>           <C>    
ASSETS 
Utility plant - at original cost                            $4,903       $4,750 
Accumulated depreciation and decommissioning                (2,603)      (2,391)
                                                            ------       ------ 
   Utility plant - net                                       2,300        2,359 
                                                            ------       ------ 
Nuclear decommissioning trust                                  494          399 
                                                            ------       ------ 
Current assets                                                                  
   Cash and temporary investments                              284          536 
   Accounts receivable                                         199          229 
   Due from affiliates                                         110          126 
   Inventories                                                  77           65 
   Regulatory balancing accounts undercollected - net            9           -- 
   Other                                                        17           52 
                                                            ------       ------ 
     Total current assets                                      696        1,008 
                                                            ------       ------ 
Deferred taxes recoverable in rates                            194          185 
Regulatory assets                                              435          608 
Deferred charges and other assets                              138           95 
                                                            ------       ------ 
     Total                                                  $4,257       $4,654 
                                                            ======       ====== 
CAPITALIZATION AND LIABILITIES 
Capitalization
   Common equity                                            $1,124       $1,387 
   Preferred stock not subject to mandatory redemption          78           78 
   Preferred stock subject to mandatory redemption              25           25 
   Long-term debt                                            1,548        1,788 
                                                            ------       ------ 
     Total capitalization                                    2,775        3,278 
                                                            -------      ------ 
Current liabilities 
   Current portion of long-term debt                            72           73 
   Accounts payable                                            165          161 
   Dividends payable                                           102           46 
   Interest accrued                                              9           11 
   Regulatory balancing accounts overcollected - net            --           58 
   Other                                                       185          114 
                                                            ------       ------ 
     Total current liabilities                                 533          463 
                                                            ------       ------ 
Customer advances for construction                              41           38 
Deferred income taxes - net                                    397          440 
Deferred investment tax credits                                 89           94 
Deferred credits and other liabilities                         422          341 
Contingencies and commitments (Note 11)                         --           -- 
                                                            ------       ------ 
     Total                                                  $4,257       $4,654 
                                                            ======       ====== 
See notes to Consolidated Financial Statements. 
</TABLE>


<TABLE>
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED CASH FLOWS 
<CAPTION> 
 
Dollars in millions
For the years ended December 31                            1998      1997      1996
                                                        --------  --------  --------
<S>                                                     <C>       <C>      <C>      
Cash Flows from Operating Activities                                                
  Net income                                          $     191    $  238   $   222 
  Adjustments to reconcile net income                                               
    to net cash provided by operating activities                                    
      Depreciation and decommissioning                      603       324       314 
      Allowance for equity funds used during construction    (5)       (5)       (5)
      Deferred income taxes and investment tax credits     (132)       10       (16)
      Application of balancing accounts to stranded costs   (86)       --        -- 
      Other - net                                           (64)       21        28 
      Changes in working capital components                                         
        Accounts receivable                                  30       (41)       18 
        Inventories                                         (12)       (2)        5 
        Other current assets                                 51        (4)      (14)
        Interest and taxes accrued                           39       (40)      (25)
        Accounts payable and other current liabilities      (66)     (143)       50 
        Regulatory balancing accounts                       (14)       23       (37)
  Cash used by discontinued operations                       --        --       (11)
                                                        -------   -------   ------- 
        Net cash provided by operating activities           535       381       529 
                                                        -------   -------   ------- 
Cash Flows from Investing Activities              
  Utility construction expenditures                        (227)     (197)     (209)
  Contributions to decommissioning funds                    (22)      (22)      (22)
  Other - net                                               (28)        5        (3)
                                                        -------   -------   ------- 
        Net cash used by investing activities              (277)     (214)     (234)
                                                        -------   -------   ------- 
Cash Flows from Financing Activities                                                
  Dividends paid                                           (269)     (256)     (189)
  Issuances of long-term debt                                --       677       227 
  Repayment of long-term debt                              (241)     (133)     (258)
  Redemption of preferred stock                              --        --       (15)
                                                        -------   -------   ------- 
        Net cash provided (used) by financing activities   (510)      288      (235)
                                                        -------   -------   ------- 
Net increase (decrease)                                    (252)      455        60 
Cash and temporary investments, January 1                   536        81        21 
                                                        -------   -------   ------- 
Cash and temporary investments, December 31              $  284    $  536   $    81 
                                                        =======   =======   ======= 
See notes to Consolidated Financial Statements. 
</TABLE>

<TABLE>
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED CASH FLOWS (continued)
<CAPTION> 

Dollars in millions
For the years ended December 31                            1998      1997      1996
                                                        --------  --------  --------
<S>                                                     <C>       <C>      <C>      
Supplemental Disclosure of Cash Flow Information
Cash paid during the year for:
   Income tax payments, net of refunds                  $   207    $  217   $   245
                                                        =======   =======   =======
   Interest payments, net of amounts capitalized        $   118    $   89   $    94
                                                        =======   =======   =======

Supplemental Schedule of Non-Cash Transactions
   Net assets of affiliates transferred to parent       $    --    $   --   $   150
                                                        =======   =======   =======
   Dividend to parent of intercompany receivable        $   100    $   --   $    --
                                                        =======   =======   =======
   Property dividend to parent                          $    29    $   --   $    --
                                                        =======   =======   =======

See notes to Consolidated Financial Statements. 
</TABLE>

<TABLE> 
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY 
For the years ended December 31, 1998, 1997, 1996 
(Dollars in millions)
<CAPTION> 

                                     Preferred Stock     
                                 ------------------------
                                 Not Subject   Subject to             
                                 to Mandatory  Mandatory   Common    Retained
                                 Redemption    Redemption  Stock     Earnings
------------------------------------------------------------------------------
<S>                              <C>           <C>         <C>        <C> 
Balance at December 31, 1995     $    93       $   25      $  857     $   662
Net income                                                                222 
Transfer to Enova Corporation                                            (150)
Preferred stock retired              (15)  
Preferred stock dividends declared                                         (6)
Common stock dividends declared                                          (182)
------------------------------------------------------------------------------ 
Balance at December 31, 1996          78           25         857         546
Net income                                                                238
Special dividend to Enova Corporation                                     (70)
Preferred stock dividends declared                                         (6)
Common stock dividends declared                                          (178)
------------------------------------------------------------------------------
Balance at December 31, 1997          78           25         857         530
Net income                                                                191
Special dividends to Sempra Energy                                       (129)
Preferred dividends declared                                               (6)
Common stock dividends declared                                          (319)
------------------------------------------------------------------------------
Balance at December 31, 1998     $    78       $   25      $  857     $   267
==============================================================================
 
See notes to Consolidated Financial Statements. 
</TABLE>


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1: BUSINESS COMBINATION

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

As required by the March 1998 decision of the California Public 
Utilities Commission (CPUC) approving the business combination, 
SDG&E has entered into agreements to sell its fossil-fueled 
generation units. The sales are subject to regulatory approvals and 
are expected to close during the first half of 1999. Additional 
information concerning the sale of SDG&E's power plants is provided 
in Note 12. In addition, SoCalGas has sold its options to purchase 
the California portions of the Kern River and Mojave Pipeline 
natural gas transmission facilities. The Federal Energy Regulatory 
Commission's (FERC) approval of the combination includes conditions 
that the combined company will not unfairly use any potential 
market power regarding natural gas transportation to fossil-fueled 
generation plants. The FERC also specifically noted that the 
divestiture of SDG&E's fossil-fueled generation plants would 
eliminate any concerns about vertical market power arising from 
transactions between SDG&E and SoCalGas.

NOTE 2: SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The Consolidated Financial Statements include the accounts of SDG&E 
and its sole subsidiary, SDG&E Funding LLC. All material 
intercompany accounts and transactions have been eliminated.

Property, Plant and Equipment
  
This primarily represents the buildings, equipment and other 
facilities used by the Company 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 12.  Utility plant balances by major functional categories 
at December 31, 1998, are: electric distribution $2.4 billion, 
natural gas operations $0.9 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 $0.4 billion and $2.2 billion, respectively, and at 
December 31, 1997, were $0.4 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 4.01, 4.03, 4.07, 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 12 for 
additional discussion of generation facilities and industry 
restructuring.

Allowance for Funds Used During Construction (AFUDC)

The allowance represents the cost of funds used to finance the 
construction of utility plant and is added to the cost of utility 
plant. AFUDC also increases income, as an offset to interest 
charges shown in the Statements of Consolidated Income, although it 
is not a current source of cash. 

Inventories
  
Materials and supplies are $48 million and $43 million at December 
31, 1998 and 1997, respectively.  Fuel oil inventory is $29 million 
and $22 million at December 31, 1998 and 1997, respectively.  
Materials and supplies are generally valued at the lower of average 
cost or market; fuel oil is valued by the last-in first-out method.

Effects of Regulation
  
SDG&E accounting policies conform with generally accepted 
accounting principles for regulated enterprises and reflect the 
policies of the CPUC and the FERC. 
     SDG&E has been preparing its financial statements in 
accordance with the provisions of Statement of Financial Accounting 
Standards (SFAS) No. 71, "Accounting for the Effects of Certain 
Types of Regulation," under which a regulated utility may record a 
regulatory asset if it is probable that, through the ratemaking 
process, the utility will recover that asset from customers. 
Regulatory liabilities represent future reductions in rates for 
amounts due to customers. 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 12, 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 12.

Revenues and Regulatory Balancing Accounts
  
Revenues from utility customers consist of deliveries to customers 
and the changes in regulatory 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 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 12.

Regulatory Assets
  
Regulatory assets include San Onofre Nuclear Generating Station 
(SONGS), post-retirement benefit costs, deferred income taxes 
recoverable in rates and other regulatory-related expenditures that 
the Company expects to recover in future rates. See Note 12 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 the Company's SONGS Unit 1, 
which was permanently shut down in 1992. Additional information on 
SONGS Unit 1 decommissioning costs is included in Note 5. 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.

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
  
Temporary investments 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 to conform to the 
current year's presentation.

New Accounting Standard

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

NOTE 3: SHORT-TERM BORROWINGS

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.


NOTE 4:  LONG-TERM DEBT

-------------------------------------------------------------------
                                                 December 31,
(Dollars in millions)                         1998         1997
-------------------------------------------------------------------
First Mortgage Bonds
  7.625% June 15, 2002                      $   28       $   80
  6.800% June 1, 2015                           14           14
  5.900% June 1, 2018                           71           71
  5.900% September 1, 2018                      93           93
  6.100% September 1, 2018                      40           40
  6.400% September 1, 2018                      43           43
  6.100% September 1, 2019                      35           35
  9.625% April 15, 2020                         10           54
  Variable rates September 1, 2020              58           75
  5.850% June 1, 2021                           60           60
  8.500% April 1, 2022                          10           44
  5.420% December 1, 2027                       45           45
  6.400% December 1, 2027                       75           75
  Variable rates December 1, 2027              130          130
                                           ------------------------
                                               712          859
                                           ------------------------
Unsecured Bonds
  5.900% June 1, 2014                          130          130
  Variable % July 1, 2021                       39           39
  Variable % December 1, 2021                   60           60
  Variable % March 1, 2023                      25           25
                                           ------------------------
                                               254          254
                                           ------------------------
Rate-reduction bonds                           592          658
Capital leases                                  63           95
Other long-term debt                            --            1
                                           ------------------------
    Total                                    1,621        1,867

Less:
  Long term debt due within one year            72           73
  Unamortized debt discount less premium         1            6
                                           ------------------------
Total                                       $1,548       $1,788
-------------------------------------------------------------------

First-Mortgage Bonds
First-mortgage bonds are secured by a lien on substantially all of 
SDG&E's utility plant. SDG&E may issue additional first-mortgage 
bonds upon compliance with the provisions of their bond indentures, 
which provide for, among other things, the issuance of an additional 
$712 million of first-mortgage bonds at December 31, 1998.
     SDG&E retired $147 million of first-mortgage bonds prior to 
scheduled maturity. Certain first-mortgage bonds may be called at 
SDG&E's option. SDG&E has $188 million of variable-interest-rate 
provisions that are callable at various dates within one year. 

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 12 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.

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.

NOTE 5:  FACILITIES UNDER JOINT OWNERSHIP

SONGS and the Southwest Powerlink transmission line are owned jointly 
with other utilities. SDG&E'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 facilities 
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 are 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 11 
and 12.

NOTE 6:  INCOME TAXES
 
The reconciliation of the statutory federal income tax rate to the 
effective income tax rate is as follows:
------------------------------------------------------------- 
                                     1998     1997     1996 
------------------------------------------------------------- 
Statutory federal income tax rate    35.0%    35.0%    35.0% 
Depreciation                          0.1      7.1      5.7 
State income taxes - net of 
  federal income tax benefit          5.6      5.7      6.1 
Tax credits                          (1.7)    (1.3)    (2.1) 
Other - net                           3.6      1.4      2.3 
                                  --------------------------- 
    Effective income tax rate        42.6%    47.9%    47.0% 
------------------------------------------------------------- 

The components of deferred income taxes at December 31 are as 
follows:
------------------------------------------------------------- 
(Dollars in millions)                     1998         1997 
------------------------------------------------------------- 
Deferred tax liabilities 
  Differences in financial and 
    tax bases of utility plant         $   440      $   568  
  Regulatory balancing accounts             74           - 
  Loss on reacquired debt                   34           31 
  Other                                     71           33 
                                  --------------------------- 
  Total deferred tax liabilities           619          632 
                                  --------------------------- 
Deferred tax assets 
  Unamortized investment tax credits        63           65
  Regulatory balancing accounts              -           28
  Unbilled revenue                          22           22
  Other                                    100           90 
                                  --------------------------- 
  Total deferred tax assets                185          205 
                                  --------------------------- 
Net deferred income tax liability          434          427 
Current portion - net 
  asset (liability)                        (37)          13 
                                  --------------------------- 
Non-current portion - net liability    $   397      $   440 
------------------------------------------------------------- 

The components of income tax expense are as follows:

------------------------------------------------------------- 
(Dollars in millions)            1998       1997      1996 
-------------------------------------------------------------
Current 
  Federal                        $  150    $  164   $  169 
  State                              41        44       45 
                                  --------------------------- 
    Total current taxes             191       208      214
                                  --------------------------- 
Deferred 
  Federal                           (30)       13       (9) 
  State                             (16)        2       (1) 
                                  --------------------------- 
    Total deferred taxes            (46)       15      (10) 
                                  --------------------------- 
Deferred investment 
  tax credits - net                  (3)       (4)      (6) 
                                  --------------------------- 
Total income tax expense         $  142    $  219   $  198 
-------------------------------------------------------------

Federal and state income taxes are allocated between operating 
income and other income.

NOTE 7:  EMPLOYEE BENEFIT PLANS

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

Pension and Other Postretirement Benefits

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


<TABLE>
<CAPTION>
-------------------------------------------------------------------------------
                                                                 Other          
                                   Pension Benefits      Postretirement Benefits
                                -----------------------------------------------
(Dollars in millions)                1998      1997           1998        1997  
--------------------------------------------------------------------------------
<S>                                <C>       <C>            <C>         <C>
Weighted-Average Assumptions 
  as of December 31:
Discount rate                        6.75%     7.25%          6.75%       7.25%
Expected return on plan assets       8.50%     8.50%          8.50%       4.50%
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                        $  605    $  546          $  43        $  41
Service cost                           19        18              1            1
Interest cost                          43        40              3            3
Plan amendments                        (3)        -              -            -
Actuarial (gain) loss                 (17)       19              5            1
Transfer of liability (3)            (112)        -              -            - 
Special termination benefits            9         -              -            -
Gross benefits paid                   (50)      (18)            (4)          (3)
                                  -----------------------------------------------
Net benefit obligation at 
  December 31                         494       605             48           43
                                  -----------------------------------------------

Change in Plan Assets:
Fair value of plan assets 
  at January 1                        699       598             14           12
Actual return on plan assets          103       118              1            1
Employer contributions                  1         1              6            4
Transfer of assets (3)               (166)        -              -            -
Gross benefits paid                   (50)      (18)            (4)          (3)
                                  -----------------------------------------------
Fair value of plan assets 
  at December 31                      587       699             17           14
                                  -----------------------------------------------
Funded status at December 31           93        94            (31)         (29)
Unrecognized net actuarial
  (gain) loss                        (196)     (200)             1           (2)
Unrecognized prior service cost        23        29              -            -
                                  -----------------------------------------------
Net liability at December 31 (4)    $ (80)    $ (77)         $ (30)       $ (31)
---------------------------------------------------------------------------------
(1) Decreasing to ultimate trend of 6.50% in 2004.
(2) Decreasing to ultimate trend of 6.50% in 1998.
(3) To reflect transfer of plan assets and liability to Sempra Energy 
    plan for Company employees transferred to Sempra Energy.
(4) Approximates amounts recognized in the Consolidated Balance Sheets at 
    December 31. Prior year amounts include non-qualified plans to be
    consistent with the current year presentation.
</TABLE>

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

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------
                                                                  Other
                                     Pension Benefits     Postretirement Benefits
                                  -----------------------------------------------
(Dollars in millions)               1998   1997   1996     1998     1997     1996
                                  -----------------------------------------------
<S>                                <C>     <C>    <C>      <C>      <C>      <C>
Service cost                        $ 19   $ 18   $ 19     $  1     $  1     $  1
Interest cost                         43     40     39        3        3        3
Expected return on assets            (60)   (50)   (45)      (1)       -        -
Amortization of:
  Transition obligation                -      -      -        2        2        2
  Prior service cost                   3      3      3        -        -        -
  Actuarial gain                     (11)    (9)    (5)       -        -        -
Special termination benefit            9      -      -        -        -        -
Regulatory adjustment                  -      -    (15)       -       (1)      (1)
                                  -----------------------------------------------
Total net periodic benefit cost     $  3   $  2   $ (4)     $ 5      $ 5      $ 5
---------------------------------------------------------------------------------
</TABLE>

     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                         --             --

Effect on the health care component of the 
  accumulated postretirement benefit obligation  $  2           $ (1)
------------------------------------------------------------------------

The projected benefit obligation and accumulated benefit obligation 
of the pension plan were $15 million and $14 million, respectively, 
as of December 31, 1998, and $16 million and $10 million, as of 
December 31, 1997. 
     Other postretirement benefits include medical benefits for 
retirees and their spouses and retiree life insurance.

Savings Plans  

SDG&E offers a savings plan, administered by plan trustees, to all 
eligible employees. Eligibility to participate in the plan begins 
after one month of service. Employees may contribute, subject to 
plan provisions, from 1 percent to 15 percent of their regular 
earnings. The employees' contributions, at the direction of the 
employees, are primarily invested in Sempra Energy common stock or 
mutual funds.  Employer contributions, after one year of service, 
are made in shares of Sempra Energy common stock. Employer 
contributions are equal to 50 percent of the first 6 percent of 
eligible base salary contributed by employees. During 1998, SDG&E's 
plan contribution was age-based for represented employees. Annual 
expense for the savings plans was $5 million in 1998, $3 million in 
1997 and $2 million in 1996.

NOTE 8:  STOCK-BASED COMPENSATION

Sempra Energy has stock-based compensation plans that align 
employee and shareholder objectives related to Sempra Energy's 
long-term growth. The long-term incentive stock compensation plan 
provides for aggregate awards of Sempra Energy non-qualified stock 
options, incentive stock options, restricted stock, stock 
appreciation rights, performance awards, stock payments or dividend 
equivalents to eligible employees of Sempra Energy and its 
subsidiaries.
     In 1995, Statement of Financial Accounting Standards (SFAS) 
No. 123, "Accounting for Stock-Based compensation," was issued. It 
encourages a fair-value-based method of accounting for stock-based 
compensation. As permitted by SFAS No. 123, Sempra Energy and its 
subsidiaries adopted the statement's disclosure-only requirements 
and continue to account for stock-based compensation in accordance 
with the provisions of accounting Principles Board Opinion No. 25, 
"Accounting for Stock Issued to Employees."
     To the extent that subsidiary employees participate in the 
plans or that subsidiaries are allocated a portion of Sempra 
Energy's costs of the plans, the subsidiaries record an expense for 
the plans. SDG&E recorded expenses of $2 million in 1998, $1 
million in 1997 and $1 million in 1996.  

NOTE 9:  FINANCIAL INSTRUMENTS

Fair Value
   
The fair values of the Company's financial instruments are not 
materially different from the carrying amounts, except for long-
term debt. The carrying amounts and fair values of long-term debt 
are $1.5 billion and $1.6 billion, respectively, at December 31, 
1998, and $1.8 billion each at December 31, 1997. The fair values 
of the first-mortgage and other bonds are estimated based on quoted 
market prices for them or for similar issues. Included in long-term 
debt are the Company's rate-reduction bonds. The carrying amounts 
and fair values of the rate-reduction bonds are $592 million and 
$607 million, respectively, at December 31, 1998, and $658 million 
each at December 31, 1997. 

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.

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, the Company 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 4.

Energy Derivatives  

The Company uses energy derivatives for price-risk management 
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.
     For the years ended December 31, 1998, 1997, and 1996, gains 
and losses from these activities are not material to SDG&E's 
financial statements.

NOTE 10:  SHAREHOLDERS' EQUITY

--------------------------------------------------------------
                                             December 31,  
(Dollars in millions)                      1998      1997 
--------------------------------------------------------------
COMMON EQUITY                        
Common stock, without par value, 
  authorized 255,000,000 shares          $   857   $   857
Retained earnings                            267       530
                                        ----------------------
    Total common equity                  $ 1,124   $ 1,387  
--------------------------------------------------------------
All shares of SDG&E common stock are wholly owned by Enova 
Corporation.

Dividend Restrictions
The CPUC regulates SDG&E's capital structure, limiting the 
dividends it may pay.  At December 31, 1998, $183 million of 
retained earnings was available for future dividends.



---------------------------------------------------------------
                                          Call     December 31,
(Dollars in millions except call price)   Price    1998   1997
---------------------------------------------------------------
PREFERRED STOCK
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     6      6
      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                         $78    $78
                                                 --------------
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.

NOTE 11:  CONTINGENCIES AND COMMITMENTS

Natural Gas Contracts  

SDG&E buys natural gas primarily from various spot-market suppliers. 
It also 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. 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 
natural 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                                            $12              $18
2000                                             11               20
2001                                              9               22
2002                                              9               22
2003                                              9               23
Thereafter                                      128                -
                                            ------------------------
Total minimum payments                         $178             $105
---------------------------------------------------------------------

Total payments under the short-term and long-term contracts were 
$103 million in 1998, $125 million in 1997, and $100 million in 
1996. All of SDG&E's natural 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 12, 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 12.

Leases

SDG&E has capital and operating leases on real and personal 
property expiring at various dates from 1999 to 2030. SDG&E 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. SDG&E also has office facilities, computer equipment 
and vehicles under operating leases. Certain leases on office 
facilities contain escalation clauses requiring annual increases in 
rent ranging from 2 percent to 7 percent.
     The minimum rental commitments payable in future years under 
all noncancellable leases are:
---------------------------------------------------------------------
                                Operating                 Capitalized
(Dollars in millions)              Leases                     Leases*
---------------------------------------------------------------------
1999                                  $15                        $27
2000                                   13                         10 
2001                                   12                         10
2002                                    8                         10
2003                                    7                         10 
Thereafter                             34                          5
                                -------------------------------------
Total future rental commitment        $89                         72
Imputed interest (6% to 9%)                                      (10)
                                                              -------
Net commitment                                                   $62
---------------------------------------------------------------------

* These amounts are reduced by a total of $55 million upon SDG&E's 
divestiture of its fossil fuel generating facilities.

     Rent expense totaled $50 million in 1998, $43 million in 1997, 
and $46 million in 1996.

Environmental Issues

SDG&E 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. SDG&E incurs significant costs to operate its 
facilities in compliance with these laws and regulations.  The 
costs of compliance with environmental laws and regulations 
generally have been recovered in customer rates.
     In 1994, the CPUC approved the Hazardous Waste Collaborative 
Memorandum account allowing utilities to recover their hazardous 
waste costs, including those related to Superfund sites or similar 
sites requiring cleanup. Recovery of 90 percent of cleanup costs 
and related third-party litigation costs and 70 percent of the 
related insurance-litigation expenses is permitted. Environmental 
liabilities that may arise are recorded when remedial efforts are 
probable and the costs can be estimated.
     At December 31, 1998, the utility's estimated remaining 
investigation and remediation liability related to hazardous waste 
sites was $15 million, of which 90 percent is authorized to be 
recovered through the Hazardous Waste Collaborative mechanism. 
SDG&E 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 the financial 
position.
     SDG&E's capital expenditures to comply with environmental laws 
and regulations were $1 million in 1998, $4 million in 1997, and $6 
million in 1996, and are not expected to be significant over the 
next five years. These expenditures primarily include the estimated 
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. SDG&E has been associated with 
various sites which may require remediation under federal, state or 
local environmental laws. SDG&E is unable to fully determine the 
extent of its responsibility for remediation of these sites until 
assessments are completed. Furthermore, the number of others that 
also may be responsible, and their ability to share in the cost of 
the cleanup, is not known. SDG&E does not anticipate that such 
costs, net of the portion recoverable in rates, will be 
significant.
     As discussed in Note 12, restructuring of the California 
electric-utility industry will change the way utility rates are set 
and costs are recovered. SDG&E has 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

SDG&E 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 SDG&E'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 and 1997, and $15 
million in 1996.

Concentration of Credit Risk

SDG&E 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 grants credit to its utility customers, substantially 
all of whom are located in SDG&E's service territory, which covers 
all of San Diego County and an adjacent portion of Orange County. 

NOTE 12:  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 (discussed 
below), 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.
     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 
provided 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 expected to be 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.

Natural Gas Industry Restructuring  

The natural gas industry experienced an initial phase of 
restructuring during the 1980s by deregulating natural gas sales to 
noncore customers. On January 21, 1998, the CPUC released a staff 
report initiating a project to assess the current market and 
regulatory framework for California's natural gas industry. The 
general goals of the plan are to consider reforms to the current 
regulatory framework emphasizing market-oriented policies 
benefiting California natural gas consumers.
     On August 25, 1998, California adopted a law prohibiting the 
CPUC from enacting any natural gas industry restructuring decision 
for customers prior to January 1, 2000. During the 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 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 
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.
     SDG&E participates 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 rather than the rate-indexing mechanism proposed by 
SDG&E. Revenue or base margin per customer is indexed based on 
inflation less an estimated productivity factor. In addition, the 
proposed decision recommends much tighter earnings sharing bands. 
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. 

Biennial Cost Allocation Proceeding (BCAP)  

In October 1998, SDG&E filed its 1999 BCAP application requesting 
that new rates become effective August 1, 1999 and remain in effect 
through December 31, 2002. The proposed end date aligns with the 
expiration of SDG&E's PBR. The application seeks overall decreases 
in natural gas revenues of $9 million.

Cost of Capital  

Under PBR, annual Cost of Capital proceedings were replaced by an 
automatic adjustment mechanism if changes in certain indices exceed 
established tolerances. Electric-industry restructuring is changing 
the method of calculating SDG&E's annual cost of capital. In May 
1998, the utility 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 rate of return on common equity (ROE), which would 
produce an overall return on rate base (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 natural 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 PE/Enova Business Combination 
(see Note 1).

NOTE 13:  SEGMENT INFORMATION

The Company has three separately managed reportable segments: 
electric transmission and distribution, electric generation, and 
natural gas service. The accounting policies of the segments are 
the same as those described in Note 2 and segment performance is 
evaluated by management based on reported operating income. 
Intersegment transactions are generally recorded the same as sales 
or transactions with third parties. Interest expense and income tax 
expense are not allocated to the reportable segments. Interest 
revenue ($40 million, $9 million and $7 million for the years ended 
December 31, 1998, 1997 and 1996, respectively) is included in 
other income on the Statements of Consolidated Income herein. It is 
not allocated to the reportable segments and, therefore, is not 
presented in the tables below.

-----------------------------------------------------------------------
                                       For the year ended December 31,
(Dollars in millions)                  1998          1997         1996
-----------------------------------------------------------------------
Revenues:
  Transmission & distribution      $   1,555     $   1,202    $   1,095
  Electric Generation                    810           567          496
  Natural Gas                            384           398          348
                                  -------------------------------------
    Total                          $   2,749     $   2,167    $   1,939
                                  -------------------------------------
Depreciation and amortization:
  Transmission & distribution      $     134     $     128    $     122
  Electric Generation                    430           159          157
  Natural Gas                             39            37           35
                                  -------------------------------------
    Total                          $     603     $     324    $     314
                                  -------------------------------------
Segment Income:
  Transmission & distribution      $     302     $     349    $     358
  Electric Generation                     54           106           95
  Natural Gas                             63            79           58
                                  -------------------------------------
    Total segment income                 419           534          511
                                  -------------------------------------
  Interest expense                      (116)          (86)         (91)
  Income tax expense                    (142)         (219)        (198)
  Nonoperating income                     30             9           --
                                  -------------------------------------
    Net income                     $     191     $     238    $     222
                                  -------------------------------------
Capital Expenditures:
  Transmission & distribution      $     173     $     147    $     155
  Electric Generation                     18            14           12
  Natural Gas                             36            36           42
                                  -------------------------------------
    Total                          $     227     $     197    $     209
                                  -------------------------------------


-----------------------------------------------------------------------
                                         At December 31, or for
                                          the year then ended
(Dollars in millions)                 1998           1997        1996
-----------------------------------------------------------------------
Assets:
  Transmission & distribution      $   2,518     $   2,257    $   2,318
  Electric Generation                    685         1,051        1,052
  Natural Gas                            553           592          626
  All other                              501           754          165
                                  -------------------------------------
    Total                          $   4,257     $   4,654    $   4,161
                                  -------------------------------------
Geographic Information:
  Long-lived assets
    United States                  $   2,300      $  2,359    $   2,409
                                  -------------------------------------
  Operating Revenues:
    United States                  $   2,749      $  2,159    $   1,933
    Mexico                                --             8            6
                                  -------------------------------------
      Total                        $   2,749      $  2,167    $   1,939
-----------------------------------------------------------------------

NOTE 14:  SUBSEQUENT EVENT

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


NOTE 15:  QUARTERLY FINANCIAL DATA (UNAUDITED)

<TABLE>
<CAPTION>
                                                 Quarter ended
                             -----------------------------------------------------
Dollars in millions           March 31     June 30     September 30  December 31
----------------------------------------------------------------------------------
<S>                         <C>         <C>             <C>           <C>
1998
Operating revenues            $    606    $    683       $    815      $    645
Operating expenses                 529         638            727           569
                               ---------------------------------------------------
Operating income              $     77    $     45       $     88      $     76
                               ---------------------------------------------------
Net income                    $     50    $     27       $     64      $     50
Dividends on preferred stock         1           2              2             1
                               ---------------------------------------------------
Net income applicable
  to common shares            $     49    $     25       $     62      $     49
                               ===================================================

1997
Operating revenues            $    495    $     492      $    566      $    614
Operating expenses                 432          414           480           524
                               ---------------------------------------------------
Operating income              $     63    $      78      $     86      $     90
                               ---------------------------------------------------
Net income                    $     42    $      55      $     65      $     76
Dividends on preferred stock         2            1             2             1
                               ---------------------------------------------------
Net income applicable
  to common shares            $     40    $      54      $     63      $     75
                               ===================================================
</TABLE>

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

None.

                             PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

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

ITEM 11. EXECUTIVE COMPENSATION

The information required by Item 11 is incorporated by reference 
from "Election of Directors" and "Executive Compensation" in the 
Information Statement prepared for the May 1999 annual meeting of 
shareholders.



ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND 
MANAGEMENT

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

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

None.


                           PART IV

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

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

1. Financial statements
                                                     Page in
                                                   This Report

Independent Auditors' Report . . . . . . . . . . . . . . 35

Statements of Consolidated Income for the years
  ended December 31, 1998, 1997 and 1996 . . . . . . . . 36

Consolidated Balance Sheets at December 31, 
  1998 and 1997. . . . . . . . . . . . . . . . . . . . . 37

Statements of Consolidated Cash Flows for the
  years ended December 31, 1998, 1997 and 1996 . . . . . 38

Statements of Consolidated Changes in
  Shareholders' Equity for the years ended
  December 31, 1998, 1997 and 1996 . . . . . . . . . . . 40

Notes to Consolidated Financial Statements . . . . . . . 41

Quarterly Financial Data (Unaudited) . . . . . . . . . . 64

2. Financial statement schedules

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


3. Exhibits

See Exhibit Index on page 68 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.




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. 

                                 SAN DIEGO GAS & ELECTRIC COMPANY

                             By: 
                                   /s/ Edwin A. Guiles               
                                 ---------------------------------
                                 Edwin A. Guiles
                                 President and Chief Financial 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:
Edwin A. Guiles
President, 
Chief Financial Officer        /s/ Edwin A. Guiles            March 2, 1999

Principal Financial Officer:
Edwin A. Guiles
President,
Chief Financial Officer        /s/ Edwin A. Guiles            March 2, 1999

Principal Accounting Officer:
Edwin A. Guiles
President,
Chief Financial Officer        /s/ Edwin A. Guiles            March 2, 1999

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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


EXHIBIT INDEX

The Forms 8-K, 10-K and 10-Q referred to herein were  filed under 
Commission File Number 1-3779 (SDG&E), Commission File  Number 1-
11439 (Enova Corporation, Commission File Number 1-14201  (Sempra 
Energy) and/or Commission File Number 333-30761  (SDG&E Funding 
LLC).

Exhibit 1 -- Underwriting Agreements

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 3 -- Bylaws and Articles of Incorporation

Bylaws

3.01  Restated Bylaws of San Diego Gas & Electric as of September 1, 1998.

Articles of Incorporation

3.02  Amended and Restated Articles of Incorporation of San Diego Gas &
      Electric Company (Incorporated by reference from the SDG&E Form 10-Q
      for the three months ended March 31, 1994.(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.

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.)


Exhibit 10 -- Material Contracts 

10.01  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.)

10.02  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.)

Compensation

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

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

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

10.06  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).

10.07  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).

10.08  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).

10.09  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).

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

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

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

10.13  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).

10.14  Agreement for Officers #3 (1997 Enova Form 10-K 
       Exhibit 10.12).


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

10.16  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).

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

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

10.19  Compensation Agreement for Nonemployee Directors (1996
       compensation)(1995 SDG&E Form 10-K Exhibit 10.5).

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

10.22  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).

10.23  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).

10.24  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).

10.25  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).

10.26  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).

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

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

10.29  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).

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

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

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

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

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

Financing

10.35  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).

10.36  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).

10.37  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).

10.38  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).

10.39  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).

10.40  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).

10.41  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).

10.42  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).

10.43  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).


10.44  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).

10.45  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).

10.46  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).

Nuclear 

10.47  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).

10.48  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).

10.49  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).

10.50  Amendment No. 1 to the Qualified CPUC Decommissioning Master
       Trust Agreement dated September 22, 1994 (see Exhibit 10.49
       herein)(1994 SDG&E Form 10-K Exhibit 10.56).

10.51  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 10.49 herein)(1994 SDG&E Form 10-K Exhibit 10.57).

10.52  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 10.49 herein)(1996 Form 10-K Exhibit 10.59).

10.53  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 10.49 herein)(1996 Form 10-K Exhibit 10.60).

10.54  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).


10.55  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 10.54 herein)(1996 Form 10-K Exhibit 10.62).

10.56  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 10.54 herein)(1996 Form 10-K Exhibit 10.63).

10.57  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).

10.58  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

10.59  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).

10.60  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).

Natural Gas Commodity, Transportation and Storage

10.61  Master Services Contract, Schedule J, Transaction Based Storage 
       Service Agreement dated April 1, 1999 and expiring March 31, 2000 
       between San Diego Gas & Electric Company and Southern California Gas 
       Company.

10.62  Master Services Contract, Schedule J, Transaction Based Storage  
       Service Agreement dated April 1, 1998 and expiring March 31, 1999
       Between San Diego Gas & Electric Company and Southern   
       California Gas Company.

10.63  Master Services Contract (Intrastate Transportation-utility electric
       generation), dated July 1,1998 and expiring July 1, 2000 between San
       Diego Gas & Electric Company and Southern California Gas Company.

10.64  Master Services Contract (Intrastate Transportation),dated July 1,
       1998 and expiring July 1, 2000 between San Diego Gas & Electric
       Company and Southern California Gas Company.

10.65  Long-term Natural Gas Storage Service Agreement dated 
       January 12, 1994 between Southern California Gas Company 
       and SDG&E (1994 SDG&E Form 10-K Exhibit 10.42).


10.66  Amendment to San Diego Gas & Electric Company and Southern
       California Gas Company Restated Long-Term Wholesale Natural
       Gas Service Contract dated March 26, 1993 (1993 SDG&E Form 
       10-K Exhibit 10.53).

10.67  San Diego Gas & Electric Company and Southern California
       Gas Company Restated Long-Term Wholesale Natural Gas Service
       Contract, dated September 1, 1990 (1990 SDG&E Form 10-K
       Exhibit 10.9).

10.68  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).

10.69  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).

10.70  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).

10.71  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).

10.72  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).

10.73  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).

10.74  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).

10.75  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).

10.76  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).

10.77  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).

10.78  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).


Other

10.79  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).

10.80  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).

10.81  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).

10.82  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 10.81 herein)(1994 SDG&E Form
       10-K Exhibit 10.72).

10.83  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). 

10.84  Assignment of Lease agreement dated as of November 19, 1993
       to Shapery Developers as lessor by New England Mutual
       Life Insurance Company (See Exhibit 10.83 herein)(1994 SDG&E 
       Form 10-K Exhibit 10.74).
       
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 21 - Subsidiaries - SDG&E Funding LLC, a wholly owned subsidiary
             of SDG&E

Exhibit 23 - Consents of Experts and Counsel

23.01  Independent Auditors' Consent.

Exhibit 27 - Financial Data Schedule

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








GLOSSARY


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                     Billion Cubic Feet (of natural gas) 

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, the Company's parent

FASB                    Financial Accounting Standards Board

FERC                    Federal Energy Regulatory Commission

GRC                     General Rate Case

IDBs                    Industrial Development Bonds

IOUs                    Investor-Owned Utilities

ISO                     Independent System Operator

IT                      Information Technology

Kv                      Kilovolt

Kwhr                    Kilowatt Hour

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

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

PRP                     Potential Responsible Party

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

SFAS                    Statement of Financial Accounting Standards

SoCalGas                Southern California Gas Company, an 
                        affiliate of the 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




                                  

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