SAN DIEGO GAS & ELECTRIC CO, 10-K, 2000-03-29

SAN DIEGO GAS & ELECTRIC CO
10-K, 2000-03-29
ELECTRIC & OTHER SERVICES COMBINED

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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, 1999
-----------------
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
- -------------------------------------------------------------------
(Exact name of registrant as specified in its charter)

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

8326 CENTURY PARK COURT, SAN DIEGO, CALIFORNIA 92123
- -------------------------------------------------------------------
(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 65. Glossary on page 70.

Aggregate market value of the voting preferred stock held by non-
affiliates of the registrant as of February 29, 2000 was
$17.9 million.

Registrant's common stock outstanding as of February 29, 2000 was
wholly owned by Enova Corporation.

DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Information Statement prepared for the May 2000
annual meeting of shareholders are incorporated by reference into
Part III.

TABLE OF CONTENTS

PART I
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . 3
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . 15
Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . . 16
Item 4. Submission of Matters to a Vote of Security Holders. . 16

PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . . 16
Item 6. Selected Financial Data. . . . . . . . . . . . . . . . 16
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . 17
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk . . . . . . . . . . . . . . . . . 29
Item 8. Financial Statements and Supplementary Data. . . . . . 30
Item 9. Changes In and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . 62

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

PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . . 63

Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . 64

Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . 65

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

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

These statements are necessarily based upon various assumptions involving
judgments with respect to the future and other risks, 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;
exchange rates; energy markets, including the timing and extent of changes
in commodity prices; weather conditions; business and regulatory or legal
decisions; the pace of deregulation of retail natural gas and electricity
delivery; and other uncertainties -- all of which are difficult to predict
and many of which are beyond the control of the Company. Readers are
cautioned not to rely unduly on any forward-looking statements and are
urged to review and consider carefully the risks, uncertainties and other
factors which affect the 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) Sempra Energy, a California-based Fortune 500 energy services company,
was formed as a holding company for Enova Corporation (Enova) and Pacific
Enterprises (PE) in connection with a business combination of Enova and PE that
was completed on June 26, 1998 (PE/Enova business combination). Southern
California Gas Company (SoCalGas), the principal subsidiary of PE, is the
nation's largest natural gas distribution utility, serving 5 million meters
throughout most of Southern California and part of central California.
Together, the two utilities serve approximately 7 million meters. 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/or 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 the interstate sale
and transportation of natural gas, the transmission and wholesale sales of
electricity in interstate commerce, transmission access, the uniform systems
of accounts, rates of depreciation and electric rates involving sales for
resale.

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 transmission and distribution of natural gas and electricity. They
require periodic renewal, which results in continuing regulation by the
granting agency.

Other regulatory matters are described throughout this report.

SOURCES OF REVENUE

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.

ELECTRIC OPERATIONS

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

Additional information concerning electric-industry restructuring is provided
in "Management's Discussion and Analysis of Financial Condition and Results
of Operations" and in Notes 11 and 12 of the notes to Consolidated Financial
Statements herein.

Electric Resources
In connection with California's 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 also are obligated to purchase from the PX
the power that they sell. An Independent System Operator (ISO) schedules
power transactions and access to the transmission system. In 1999, SDG&E
completed divestiture of its owned generation other than nuclear. SDG&E
continues to have purchased-power contracts, which it bids into the PX. Based
on generating plants in service and purchased-power contracts currently in
place, at February 29, 2000 the megawatts (mw) of electric power available to
SDG&E to bid into the PX are as follows:

Source Mw
--------------------------------------------------
Nuclear generating plants 430*
Long-term contracts with other utilities 175
Contracts with others 493
-----
Total 1,098
=====
* Net of plants' internal usage

Natural 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. During
the quarter ended June 30, 1999, these sales were completed for total net
proceeds of $466 million. The South Bay Power Plant sale to the San Diego
Unified Port District for $110 million was completed on April 23, 1999. Duke
South Bay, a subsidiary of Duke Energy Power Services, will manage the plant
for the Port District. The sale of Encina Power Plant and 17 combustion-
turbine generators to Dynegy Inc. and NRG Energy Inc. for $356 million was
completed on May 21, 1999. SDG&E will operate and maintain both facilities
for the new owners for the next two years.

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

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. 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. In June 1999, the CPUC granted authority to begin decommissioning Unit
1. That work is now in progress.

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 1999 SDG&E spent $10 million on capital modifications and additions
and expects to spend $6 million in 2000. SDG&E deposits funds in an external
trust to provide for the future dismantling and decontamination of the units.

Additional Information: Additional information concerning the SONGS units,
nuclear decommissioning and industry restructuring (including SDG&E's
divestiture of its electric generation assets) is provided below and in
"Environmental Matters," "Electric Properties," "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:
Expiration Megawatt
Supplier Date Commitment Source
- -------------------------------------------------------------------
Long-Term Contracts with Other Utilities:

Portland General
Electric (PGE) December 2013 75 Coal

Public Service
Company of
New Mexico (PNM) April 2001 100 System supply
-----
Total 175
=====
Others Contracts:

PacifiCorp December 2001 100 System Supply

Avista Supply December 2001 150 System Supply

Applied Energy December 2019 102 Cogeneration

Yuma Cogeneration June 2024 50 Cogeneration

Goal Line Limited
Partnership December 2025 50 Cogeneration

Other (89) Various 41 Cogeneration
------
Total 493
======

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 and Avista are
for firm energy only and are based on the amount of energy received. The
prices under these contracts are at the 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 below, and in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and Note 11 of the notes to Consolidated
Financial Statements herein.

Power Pools
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 200
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.

Transmission Arrangements
Pacific Intertie: The Pacific Intertie, consisting of AC and DC transmission
lines, connects the Northwest with SDG&E, Pacific Gas & Electric (PG&E),
Edison and others under an agreement that expires in July 2007. SDG&E's share
of the intertie was 266 mw.

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. 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.

Due to electric-industry restructuring (see "Transmission Access" below), the
operating rights of SDG&E on these lines have been transferred to the ISO.

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 provided 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
- -------------------------------------------------------------------
1999 1998 1997 1999 1998 1997
----- ----- ----- ---- ---- ----
Natural gas 6.5% 17.3% 19.8% 3.0 3.0 3.3
Nuclear fuel 12.6 11.5 11.8 0.5 0.6 0.6
Fuel oil 0.1 2.4
----- ----- -----
Total generation 19.1 28.8 31.7
Purchased power
and ISO/PX 80.9 71.2 68.3 3.7 3.5 2.8
----- ----- -----
Total 100.0% 100.0% 100.0%
====== ====== ======

As described previously, SDG&E sold its South Bay and Encina power plants and
17 combustion turbines during the quarter ended June 30, 1999. Since the
primary fuel source of these plants is natural gas, the percentage of Kwhr
for natural gas in the above table decreased compared to 1998.

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
under contract through 2003, including mining and milling of uranium
concentrate, conversion of uranium concentrate to uranium hexafluoride,
enrichment services and enriched uranium hexafluoride, and fabrication of
fuel assemblies.

Spent fuel is being stored at SONGS, where storage capacity will be adequate
at least through 2005. 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 provided in Note 11
of the notes to Consolidated Financial Statements herein.

NATURAL GAS OPERATIONS

SDG&E distributes natural gas to 0.7 million 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, until their
sales, also purchased natural gas for fuel in its generating plants.

Supplies of Natural Gas
The Company buys natural gas under several short-term and long-term contracts.
Short-term purchases are based on monthly spot-market prices. The Company 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 are delivered to the SoCalGas pipeline
at the California border by interstate pipeline companies, primarily El Paso
Natural Gas Company and Transwestern Pipeline Company. These interstate
companies provide transportation services for supplies purchased from other
sources by the Company or its transportation customers. The rates that
interstate pipeline companies may charge for natural gas and transportation
services are regulated by the FERC. 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. SDG&E has settled with
the four suppliers, terminating three of the contracts and continuing to
purchase natural gas from one of the suppliers under terms of the settlement
agreement. Additional information regarding natural gas contracts is provided
in Note 11 of the notes to Consolidated Financial Statements herein.

The following table shows the sources of natural gas deliveries from 1995
through 1999.

<TABLE>
<CAPTION>
Year Ended December 31
-------------------------------------------------------------------
1999 1998 1997 1996 1995
- ---------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Gas Purchases (billions of cubic feet) 75 118 101 97 90

Customer-Owned and
Exchange Receipts 47 19 18 17 17

Storage Withdrawal
(Injection) - Net 4 (3) 1 -- 2

Company Use and
Unaccounted For -- (2) (1) (1) (1)
------- ------- ------- ------- -------
Net Deliveries 126 132 119 113 108
======= ======= ======= ======= =======

Cost of Gas Purchased*
(millions of dollars) $ 205 $ 327 $ 313 $ 252 $ 188
------- ------- ------- ------- -------

Average Cost of Purchases
(Dollars per Thousand Cubic Feet) $2.73 $2.77 $3.10 $2.59 $2.08
======= ======= ======= ======= =======

* Includes interstate pipeline demand charges
</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 fixed-price 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 749,000
core customers (721,000 residential and 28,000 small commercial and
industrial). Noncore customers consist primarily of utility electric
generation (UEG), wholesale, and large commercial and industrial customers,
and total 150.

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 1999, 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 throughput is less than for natural gas
sales, the Company generally earns the same margin whether the Company buys
the gas and sells it to the customer or transports natural gas already owned
by the customer.

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
27,000 and 12,000 new natural gas customer meters in 1999 and 1998,
respectively, representing a growth rate of approximately 3.7 percent and 1.6
percent, respectively. The Company expects its growth for 2000 will be about
two percent.

During 1999, 91 percent of residential energy customers in the Company's
service area used natural gas for water heating, 73 percent for space
heating, 52 percent for cooking and 35 percent for clothes drying.

Demand for natural gas by noncore customers is very sensitive to the price of
competing fuels. Although the number of noncore customers in 1999 was only
150, they accounted for approximately 11 percent of the authorized natural
gas revenues and 43 percent of total natural gas volumes. External factors
such as weather, electric deregulation, the use of hydro-electric power,
competing pipeline bypass and general economic conditions can result in
significant shifts in this market. The demand for natural gas by large UEG
customers is also greatly affected by the price and availability of
electricity.

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

Other
Additional information concerning customer demand and other aspects of
natural gas operations is provided under "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and in Notes 11
and 12 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. 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.

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 provided
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 proceeding to assess the
current market and regulatory framework for California's natural gas
industry. Additional information on natural gas industry restructuring is
provided 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
In general, earnings fluctuations from changes in the costs of natural gas
and consumption levels for the majority of natural gas are eliminated by
balancing accounts authorized by the CPUC. 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 certain costs and consumption levels now can affect earnings from electric
operations. Additional information on balancing accounts is provided 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. Additional information on PBR is
provided 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 the cost of natural gas transportation
services are determined in the BCAP. The BCAP adjusts rates to reflect
variances in customer demand from estimates previously used in establishing
customer natural gas transportation rates. The mechanism substantially
eliminates the effect on income of variances in market demand and natural gas
transportation costs. The BCAP will continue under PBR. Additional
information on the BCAP is provided 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 IOUs conduct business with
their affiliates. Information on affiliate transactions is provided 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. Additional information on the utility's cost of
capital is provided 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 additional information should be read in conjunction
with those discussions.

Hazardous Substances
SDG&E lawfully disposed of hazardous wastes at off-site 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
and other responsible parties to cleanup property within the agency's
jurisdiction. Where the landowner or other responsible party fails to
complete the required corrective action, the redevelopment agency can
complete the work and obtain reimbursement from such parties.

The Redevelopment Agency for the City of San Diego has exerted its authority
affecting SDG&E'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. 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 was completed for Station A and partial demolition was performed
in 1997. Initial cleanup actions commenced in 1998, and most of the
remediation was completed in 1999, at a cost of approximately $8.7 million.
Cleanup of Station A will be completed in 2000 at an estimated cost of
$700,000. Contaminants resulting from the gas-manufacturing process by-
products were also assessed at SDG&E's Escondido and Oceanside sites.
Remediation at the Escondido site was completed in 1998 and a site-closure
letter received. Remediation at the Oceanside facility is scheduled for 2000
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.
Asbestos and lead-based paint were used in the construction of the power
plant. Activities to dismantle and decommission the facility required the
removal of the asbestos and lead-based paint in a manner complying with all
applicable environmental, health and safety laws. This work also included the
removal or cleanup of small amounts of PCBs, fuel oil and other substances.
These activities were completed in 1999 at a cost of $6 million. The sale of
Station B was completed in December 1999.

SDG&E sold its fossil-fuel power plants and combustion turbines in 1999. As a
part of its due diligence for the sale, SDG&E conducted a thorough
environmental assessment of the South Bay and Encina power plants and 17
combustion turbine sites. Pursuant to the sale agreements for such
facilities, SDG&E 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 some instances of significant contamination,
principally resulting from hydrocarbon releases, for which SDG&E has a
cleanup obligation under the agreement. Estimated costs to perform the
necessary remediation are $7 million 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 were offset against the sales price for
the facilities, together with other appropriate costs, and the remaining net
proceeds were offset against SDG&E's other transition costs.

SDG&E and 10 other entities have been named potentially responsible parties
(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 SDG&E 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. SDG&E and the other PRPs have entered into a cost-
sharing agreement to provide funding for the implementation of a consent
order between DTSC and the site owner for the development of a cleanup plan.
SDG&E's interim share under the agreement is 10.1%, subject to adjustment
based on ultimate responsibility allocations. 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, 1999, SDG&E's estimated remaining investigation and
remediation liability related to hazardous waste sites was $6 million, of
which 90 percent is authorized to be recovered through the Hazardous Waste
Collaborative mechanism. Any costs not ultimately recovered through rates,
insurance or other means will not have a material adverse effect on SDG&E's
consolidated results of operations or financial position.

Estimated liabilities for environmental remediation are recorded when amounts
are probable and estimable. Amounts authorized to be recovered in rates under
the Hazardous Substance Cost Recovery Account are recorded as a regulatory
asset.

Electric and Magnetic Fields (EMFs)
Although scientists continue to research the possibility that exposure to
EMFs causes adverse health effects, science, has not demonstrated a cause-
and-effect relationship between adverse health effects and exposure to the
type of EMFs emitted by 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
California's air quality standards are more restrictive than federal
standards. However, as a result of the sale of the Company's fossil-fuel
power plants and combustion turbines, the Company's primary air-quality
issue, compliance with these standards is less significant.

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.

In connection with the issuance of operating permits, SDG&E and the other
owners of SONGS reached agreement with the California Coastal Commission to
mitigate the environmental damage to the marine environment attributed to the
cooling-water discharge from SONGS Units 2 and 3. This mitigation program
includes an enhanced fish-protection system, a 150-acre artificial reef and
restoration of 150 acres of coastal wetlands. In addition, the owners must
deposit $3.6 million with the state for the enhancement of fish hatchery
programs and pay for monitoring and oversight of the mitigation projects.
SDG&E's share of the cost is estimated to be $24 million. The pricing
structure contained in the CPUC's decision regarding accelerated recovery of
SONGS Units 2 and 3 is expected to accommodate these added mitigation costs.

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 Regional Water Quality Control Board (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 received a site-
closure letter from the RWQCB.

OTHER MATTERS

Year 2000
Sempra Energy established an overall company-wide Year 2000 readiness effort
that included SDG&E. There were only a few, very minor year 2000
interruptions to the Company's automated systems and applications with
suppliers and customers. Sempra Energy incurred expenses of $48 million
(including $7.6 million in 1999) for its Year 2000 readiness effort and
expects to incur no additional costs.

Research, Development and Demonstration (RD&D)
As a result of electric-industry restructuring, SDG&E has significantly
reduced its electric RD&D program. For 1999, the CPUC authorized SDG&E to
fund $1.2 million and $4 million in its natural gas and electric RD&D
programs, respectively, which includes $3.9 million to the CEC's electric
public purpose RD&D program. Annual RD&D costs have averaged $4.7 million
over the past three years.

Employees of Registrant
As of December 31, 1999, SDG&E had 3,071 employees, compared to 2,982 at
December 31, 1998.

Wages
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 the transmission and distribution
contract runs through August 31, 2001.

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, 6,971 miles of high and low pressure
distribution mains, and 5,791 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 equipment necessary in the conduct of business.

ITEM 3. LEGAL PROCEEDINGS

Neither the Company nor its affiliates are party to, nor is their property
the subject of, any material pending legal proceedings other than routine
litigation incidental to their businesses.

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

PART II

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

All of the issued and outstanding common stock of 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, 1999, $401 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
------------------------------------------------
1999 1998 1997 1996 1995
-------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
Income Statement Data:
Operating Revenues $2,207 $2,249 $2,167 $1,939 $1,814
Operating Income $ 281 $ 286 $ 317 $ 309 $ 315
Dividends on Preferred Stock $ 6 $ 6 $ 6 $ 6 $ 8
Earnings Applicable to
Common Shares $ 193 $ 185 $ 232 $ 216 $ 226

Balance Sheet Data:
Total Assets $4,366 $4,257 $4,654 $4,161 $4,473
Long-Term Debt $1,418 $1,548 $1,788 $1,285 $1,217
Short-Term Debt (a) $ 66 $ 72 $ 73 $ 34 $ 124
Shareholders' Equity $1,393 $1,203 $1,465 $1,483 $1,614

(a) Includes 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 the 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 discussion and analysis of operating
results from 1997 through 1999, and provides 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 0.7 million customers in San Diego County and transports
electricity and gas for others. The Company is the principal subsidiary of
Enova Corporation (Enova or the Parent), which is wholly owned by Sempra
Energy. SDG&E's only subsidiary is SDG&E Funding LLC, which is described
below under "Electric Rates."

Business Combinations
Sempra Energy was formed to serve as a holding company for Pacific
Enterprises (PE, the parent corporation of the Southern California Gas
Company) and Enova in connection with a business combination that became
effective on June 26, 1998 (the PE/Enova business combination). In connection
with the PE/Enova business combination, the holders of common stock of PE and
Enova became the holders of Sempra Energy's common stock. The preferred stock
of SDG&E remained outstanding. The combination was a tax-free transaction.
Expenses incurred in connection with the business combination were $35
million, after tax, in 1998. There were no business combination costs in
1999. These costs consist primarily of employee-related costs, and investment
banking, legal, regulatory and consulting fees. See Note 1 of the notes to
the Consolidated Financial Statements for additional information.

Capital Resources And Liquidity
The Company's operations continue to be a major source of liquidity. In
addition, working capital requirements are met primarily through the issuance
of short-term and long-term debt. Cash requirements primarily include capital
investments in plant.

Additional information on sources and uses of cash during the last three
years is summarized in the following condensed statement of consolidated cash
flows:

- ------------------------------------------------------------
SOURCES AND (USES) OF CASH
Year Ended December 31
(Dollars in millions) 1999 1998 1997
- ------------------------------------------------------------
Operating Activities $ 520 $ 535 $ 381
-------------------------
Investing Activities:
Net proceeds from sale of assets 466 -- --
Loan to parent (422) -- --
Capital expenditures (245) (227) (197)
Other (24) (50) (17)
-------------------------
Total Investing Activities (225) (277) (214)
-------------------------
Financing Activities:
Dividends paid (106) (269) (256)
Long-term debt - net (136) (241) 544
-------------------------
Total Financing Activities (242) (510) 288
-------------------------
Increase (decrease) in cash
and cash equivalents $ 53 $(252) $ 455
- ------------------------------------------------------------

Cash Flows From Operating Activities
The decrease in cash flows from operating activities in 1999 was primarily
due to the completion of the recovery of SDG&E's stranded costs and to
reduced revenues - both the result of the sale of SDG&E's fossil power plants
and combustion turbines in the second quarter of 1999. See additional
discussion on the sale of the power plants in Note 14 of notes to
Consolidated Financial Statements for additional information. This decrease
was partially offset by lower expenses incurred in connection with the
PE/Enova business combination. See Note 1 of the notes to the Consolidated
Financial Statements for additional information.
The increase in cash flows from operating activities in 1998 was
primarily due to increased revenue 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 business combination.

Cash Flows From Investing Activities
Cash flows from investing activities in 1999 included the proceeds from the
sale of assets offset by loans to the Parent and capital expenditures. The
South Bay Power Plant was sold to the San Diego Unified Port District for
$110 million. The Encina Power Plant and 17 combustion-turbine generators
were sold to Dynegy, Inc. and NRG Energy, Inc. for $356 million. See
additional discussion in Note 12 of the notes to Consolidated Financial
Statements.

Capital Expenditures
Capital expenditures were $18 million higher in 1999 compared to 1998
primarily due to a natural gas system expansion and additional improvements
to the electric distribution system.
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 are estimated to be $310 million in 2000. They will
be financed primarily by internally generated funds.

Cash Flows From Financing Activities
Net cash used in financing activities decreased in 1999 primarily due to
lower dividends to the Parent and lower long-term debt repayments in 1999.
Net cash used by 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.

Long-Term Debt

In 1999, cash was used for the repayment of $28 million of first-mortgage
bonds, and $66 million of rate-reduction bonds
In 1998, cash was used for the repayment of $147 million of first-
mortgage bonds, and $66 million of rate-reduction bonds.
In December 1997, $658 million of Rate Reduction Bonds were issued on
SDG&E's behalf at an average interest rate of 6.26 percent. A portion of the
bond proceeds was used to retire variable-rate, taxable Industrial
Development Bonds (IDBs). Additional information concerning the Rate
Reduction Bonds is provided below under "Electric Industry Restructuring."
SDG&E has $58 million of temporary investments that will be maintained
into the future to offset, for regulatory purposes, a like amount of long-
term debt since this was more cost-effective than redeeming low-rate debt.
The specific debt series being offset consists of variable-rate IDBs. The
California Public Utility Commission (CPUC) has approved specific ratemaking
treatment that 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 $58 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 $58 million and the level of IDBs
being offset will be reduced by the same amount.

Dividends

Dividends paid to parent amounted to $100 million in 1999, compared to $263
million in 1998 and $250 million in 1997.
The payment of future dividends and the amount thereof are within the
discretion of the board of directors.

Capitalization
Total capitalization at December 31, 1999 was $2.9 billion. The debt to
capitalization ratio was 51 percent, 57 percent and 56 percent at December
31, 1999, 1998 and 1997, respectively. The decrease in the debt-to-capital
ratio in 1999 is primarily due to 1999's income and because no dividends were
declared to the parent in 1999 . In addition, there was lower long-term debt
outstanding in 1999 compared to 1998. The increase for 1998 was primarily due
to the declaration of dividends to Enova.

Cash And Cash Equivalents
Cash and cash equivalents were $337 million at December 31, 1999.
The Company anticipates that operating cash required in 2000 for capital
expenditures, common stock dividends and debt payments will be provided by
cash generated from operating activities and existing cash balances.
In addition to cash from ongoing operations, the Company has
multi-year credit agreements that permit term borrowings of up to
$205 million. At December 31,1999 all bank lines of credit were unused. For
further discussion, see Notes 3 and 4 of the notes to Consolidated Financial
Statements.

Management believes that the sources of funding described above are
sufficient to meet short-term and long-term liquidity needs.

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 interests 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).
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 plant in a market where a utility already has a
highly developed infrastructure. See additional discussion of PBR in Note 12
of the notes to Consolidated Financial Statements.
In September 1996, California enacted a law restructuring California's
electric-utility industry (AB 1890). The legislation adopted the December
1995 CPUC policy decision restructuring the industry to stimulate competition
and reduce rates. Beginning on March 31, 1998, customers were able to buy
their electricity through the California Power Exchange (PX), which obtains
power from qualifying facilities, from nuclear units and lastly, from the
lowest-bidding suppliers. The PX serves as a wholesale power pool, allowing
all energy producers to participate competitively. An Independent System
Operator(ISO) schedules power transactions and access to the transmission
system.
The natural gas industry experienced an initial phase of restructuring
during the 1980s by deregulating natural gas sales to noncore customers. The
CPUC is studying the issue of restructuring for sales to noncore customers..
See additional discussion of electric-industry and natural gas-industry
restructuring below in "Industry Restructuring" and Note 12 of the notes to
Consolidated Financial Statements.

Results Of Operations

1999 Compared to 1998

Net income for 1999 increased 4 percent to $199 million, compared to net
income of $191 million in 1998. The increase is primarily due to $35 million,
after-tax, of PE/Enova business combination expense in 1998 (none in 1999)
partially offset by lower income from electric operations. Net income
decreased 28 percent to $36 million for the three months ended December 31,
1999, compared to net income of $50 million for the corresponding period in
1998. The decrease is due to lower income from electric operations in 1999
and higher interest on the portion of the rate-reduction bond liability which
is expected to be refunded to customers.

Electric revenues decreased 3 percent in 1999 compared to 1998,
primarily due to the decrease in base electric rates from the elimination of
the rate freeze effective July 1, 1999.
Revenues from gas operations increased 1 percent in 1999 primarily due
to higher residential and utility electric generation (UEG) revenues. The
increased residential revenues are due to slightly higher volumes sold in
1999 compared to 1998. The increase in UEG revenues was primarily due to the
1999 sale of SDG&E's fossil fuel generating plants, since 1999 revenue now
includes the selling price of natural gas instead of just the margin.
The Company's gas purchased for resale increased 1 percent in 1999,
largely due to greater sales to residential and commercial and industrial
customers.
As discussed in Note 12 of the notes to the Consolidated Financial
Statements, PX/Independent System Operator (ISO) power revenues have been
netted against purchased-power expense, including purchases from the PX/ISO.
The PX/ISO began operations on March 31, 1998.
Depreciation and decommissioning expense decreased 7 percent in 1999,
primarily due to the mid-year completion of the accelerated recovery of
generation assets.
Operating expenses decreased 11 percent in 1999, primarily due to the
lower business-combination costs, previously discussed.

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 regulation, and changes in regulatory mechanisms for
recording revenues due to electric industry restructuring. Included in the
calculation of net income are business combination costs of $35 million,
after tax, in 1998 and $11 million, after tax, in 1997. Net income decreased
34 percent to $50 million for the three months ended December 31, 1998,
compared to net income of $76 million for corresponding period in 1997. The
decrease is primarily due to lower incentive awards for performance-based
regulation and other programs, and changes in regulatory mechanisms for
recording revenues due to electric industry restructuring in 1998.

Electric revenues increased 5 percent in 1998 compared to 1997,
primarily due to the recovery of stranded costs via the competition
transition charge (CTC), and to alternate costs incurred (including fuel and
purchased power) due to the delay from January 1 to March 31, 1998, in the
start-up of operations of the PX/ISO. These factors were partially offset by
a decrease in retail revenue as a result of the 10-percent small customer
rate reduction, which became effective in January 1998, and by a decrease in
sales to other utilities, due to the start-up of the PX. The 10-percent rate
reduction and PX are described further under "Factors Influencing Future
Performance" and in Note 12 of the notes to Consolidated Financial
Statements.
Natural gas revenues decreased 4 percent in 1998 compared to 1997.
Residential sales increased primarily due to greater volumes sold. The
decrease in balancing accounts and other is primarily due to greater
overcollections in 1998 versus 1997.
As previously discussed, PX/ISO power revenues have been netted against
purchased-power expense, including purchases from the PX/ISO. Results for
1998 have been reclassified to effect this change.
Gas purchased for resale decreased 9 percent in 1998 compared to 1997
due to a decrease in the average price of natural gas.
Depreciation and amortization expense increased 86 percent in
1998, primarily due to the recovery of stranded costs via the CTC.
The earnings impact of the increase is offset by CTC revenue (see above).
Operating expenses increased 22 percent in 1998, primarily due to the
higher business-combination costs ($57 million, pretax, in 1998 compared to
$11 million, pretax, in 1997) and higher electric-distribution maintenance
costs primarily related to the Company's tree-trimming program.

The table below summarizes the components of utility electric and natural gas
volumes and revenues by customer class for 1999, 1998 and 1997.

<TABLE>
ELECTRIC DISTRIBUTION
(Dollars in millions, volumes in millions of Kwhrs)
<CAPTION>
1999 1998 1997
-----------------------------------------------------------------------
Volumes Revenue Volumes Revenue Volumes Revenue
-----------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Residential 6,327 $663 6,282 $637 6,125 $684
Commercial 6,284 592 6,821 643 6,940 680
Industrial 2,034 154 3,097 233 3,607 268
Direct access 3,212 118 964 44 - -
Street and highway lighting 73 7 85 8 76 7
Off-system sales 383 10 706 15 4,919 116
-----------------------------------------------------------------------
18,313 1,544 17,955 1,580 21,667 1,755
Balancing and other 274 285 14
-----------------------------------------------------------------------
Total 18,313 $1,818 17,955 $1,865 21,667 $1,769
-----------------------------------------------------------------------
GAS SALES, TRANSPORTATION & EXCHANGE
(Dollars in millions, volumes in billion cubic feet)

Gas Sales Transportation & Exchange Total
----------------------------------------------------------------------
Throughput Revenue Throughput Revenue Throughput Revenue
----------------------------------------------------------------------
1999:
Residential 38 $ 270 - - 38 $ 270
Commercial and Industrial 22 111 18 $15 40 126
Utility Electric Generation* 18 7 30 6 48 13
-----------------------------------------------------------------------
78 $ 388 48 $21 126 409
Balancing accounts and other (20)
---------
Total $ 389
- ---------------------------------------------------------------------------------------------
1998:
Residential 35 $ 258 - - 35 $ 258
Commercial and Industrial 21 105 19 $16 40 121
Utility Electric Generation* 57 9 - - 57 9
-----------------------------------------------------------------------
113 $ 372 19 $16 132 388
Balancing accounts and other (4)
---------
Total $ 384
- ---------------------------------------------------------------------------------------------
1997:
Residential 31 $ 231 - - 31 $ 231
Commercial and Industrial 22 115 17 $18 39 133
Utility Electric Generation* 49 14 - - 49 14
----------------------------------------------------------------------
102 $ 360 17 $18 119 378
Balancing accounts and other 20
---------
Total $ 398
- ---------------------------------------------------------------------------------------------
* Prior to the sale of SDG&E's power plants in 1999, the portion representing SDG&E's
sales for electric generation includes margin only.

</TABLE>

Other Income, Interest Expense, and Income Taxes

Other Income

Other income increased to $38 million in 1999 from $11 million in 1998,
primarily due to higher interest earned on a loan to Sempra Energy. Other
income increased to $11 million in 1998 from a loss of $5 million in 1997
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.

Interest Expense

Interest expense for 1999 increased to $120 million from $106 million in 1998
primarily due to interest of $28 million on the portion of the rate-reduction
bond liability which is expected to be refunded to customers, partially
offset by lower interest expense on long-term debt as a result of lower long-
term debt balances during 1999. Interest expense for 1998 increased to $106
million from $74 million primarily due to the issuance of rate-reduction
bonds in December 1997. See additional discussion of rate reduction bonds in
Note 4 of the notes to Consolidated Financial Statements.

Income Taxes

Income tax expense was $126 million, $142 million and $219 million for the
years ended December 31, 1999, 1998 and 1997, respectively. The effective
income tax rates were 39 percent, 43 percent and 48 percent for the same
periods. The decrease in income taxes for 1999 is primarily due to the
charitable contribution to the San Diego Unified Port District in connection
with the sale of the South Bay generating plant. The decrease in income taxes
for 1998 is due to lower income before income taxes and to tax issues related
to the recovery of CTC.

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 and other factors
are summarized below.

Industry Restructuring

In September 1996, California enacted a law restructuring California's
electric-utility industry (AB 1890). Consumers now have the opportunity 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. The PX serves as a wholesale power
pool allowing all energy producers to participate competitively.
Thus far, electric-industry deregulation has been confined to
generation. Transmission and distribution have remained subject to
traditional cost-of-service and performance-based ratemaking regulation.
However, the CPUC is exploring the possibility of opening up electric
distribution to competition. During 2000, the CPUC will consider whether any
changes should be made in electric distribution regulation. A CPUC staff
report will be submitted on this issue to the CPUC in the second quarter of
2000. SDG&E will actively participate in this effort. See Note 14 of the
notes to Consolidated Financial Statements for additional information.
On December 20, 1999 the FERC issued "Order 2000" concerning the
formation of Regional Transmission Organizations (RTOs). The rule generally
requires all public utilities that own, operate or control interstate
transmission to file by October 15, 2000, a proposal for an RTO. Public
utilities that are members of an existing, FERC-approved regional entity must
file by January 15, 2001. The rule states that RTOs will be operational by
December 15, 2001 and will address many issues to improve the transmission of
energy. See additional discussion in Note 12 of the notes to the Consolidated
Financial Statements.
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 proceeding 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's natural gas consumers.
In August 1998, California enacted a law prohibiting the CPUC from
enacting any natural gas industry restructuring decision for core
(residential and small commercial) customers prior to January 1, 2000. During
the implementation moratorium, the CPUC held hearings throughout the state
and intends to give the legislature a draft ruling before adopting a final
market-structure policy. SDG&E has been actively participating in this effort
and has argued in support of competition intended to maximize benefits to
customers rather than to protect competitors.
In October 1999, the State of California enacted a law (AB1421) which
requires that gas utilities provide "bundled basic gas service" (including
transmission, storage, distribution, purchasing, revenue-cycle services and
after-meter services) to all core customers, unless the customer chooses to
purchase gas from a non-utility provider. The law prohibits the CPUC from
unbundling distribution-related gas services (including meter reading and
billing) and after-meter services (including leak investigation, inspecting
customer piping and appliances, pilot relighting and carbon monoxide
investigation) for most customers. The objective is to preserve both customer
safety and customer choice.

Transition Costs

AB 1890 allows utilities, within certain limits, the opportunity to recover
their stranded costs incurred for certain above-market CPUC-approved
facilities, contracts and obligations through the establishment of the CTC.
Utilities are allowed a reasonable opportunity to recover their stranded
costs through December 31, 2001. Stranded costs include sunk costs, as well
as ongoing costs the CPUC finds reasonable and necessary to maintain
generation facilities through December 31, 2001. These costs also include
other items SDG&E has accrued under traditional cost-of-service regulation.
In June 1999, SDG&E completed the recovery of a majority of its stranded
costs. The recovery was effected by, among other things, the sale of SDG&E's
fossil power plants and combustion turbines during the quarter ended June 30,
1999. Costs related to the above-market portion of qualifying facilities and
other purchased-power contracts that were in effect at December 31, 1995, and
the San Onofre Nuclear Generating Station (SONGS) will continue to be
recovered in rates. See Note 12 of the notes to Consolidated Financial
Statements for additional information.

Electric Rates

AB 1890 provides for a 10-percent reduction in rates for residential and
small commercial customers beginning in January 1998, and provided for the
issuance of rate-reduction bonds by an agency of the State of California to
enable its investor-owned utilities (IOUs) to achieve this rate reduction. In
December 1997, $658 million of rate-reduction bonds were issued on behalf of
SDG&E at an average interest rate of 6.26 percent. These bonds are being
repaid over 10 years by SDG&E's residential and small commercial customers
via a non-bypassable charge on their electricity bills. SDG&E formed a
subsidiary, SDG&E Funding LLC, to facilitate the issuance of the rate-
reduction bonds. In exchange for the bond proceeds, SDG&E sold to SDG&E
Funding LLC all of its rights to the revenue streams. Consequently, the
revenue streams are not the property of SDG&E and are not available to
creditors of SDG&E.
The sizes of the rate-reduction bond issuances were set so as to make
the IOUs neutral as to the 10-percent rate reduction, and were based on a
four-year period to recover stranded costs. Because SDG&E recovered its
stranded costs in only 18 months (due to the greater-than-anticipated plant-
sale proceeds), the bond proceeds were greater than needed. Accordingly,
SDG&E will return to its customers over $400 million that it has collected or
will collect from its customers. The timing of the return will differ from
the timing of the collection, but the specific timing of the repayment and
the interest rate thereon are the subject of a CPUC proceeding and are
expected to be resolved in the second quarter of 2000. This refund will not
affect SDG&E's net income, except to the extent that the interest cost
associated with the refund (12.63 percent if not reduced as a result of the
CPUC proceeding) differs from the return earned by the Company on the funds.
The bonds and their repayment schedule are unaffected by this refund.
AB 1890 also includes a rate freeze for all IOU customers during the CTC
period. Beginning in 1998, SDG&E's system-average rates were fixed at 9.43
cents per kwh. The rate freeze would have stayed in place until January 1,
2002. However, in connection with completion of its stranded cost recovery
(described below), SDG&E filed with the CPUC for a mechanism to structure
electric rates after the end of the rate freeze. SDG&E received approval to
reduce base rates (the non-commodity portion of rates) to all electric
customers effective July 1, 1999. The portion of the electric rate
representing the commodity cost is simply passed through to customers and
will fluctuate with the price of electricity from the PX. Except for the
interim protection mechanism described below, customers will no longer be
protected from commodity price fluctuations.
In April 1999, SDG&E filed an all-party settlement (including energy
service providers, the CPUC's Office of Ratepayer Advocates (ORA), and the
Utility Consumers Action Network (UCAN)) detailing proposed implementation
plans for lifting the rate freeze. Included in the settlement is an interim
customer-protection mechanism for residential and small commercial customers
that capped rates between July 1999 and September 1999, regardless of how
high the PX price had moved during the period. The resulting undercollection
(which amounted to less than $1 million) is being recovered through a
balancing account mechanism. The interim rate-freeze period runs until the
CPUC issues its decision on the pending legal and policy issues for ending
the rate freeze. This decision is expected during the second quarter of 2000.

Performance-Based Regulation (PBR)

Accounting Standards

Except for electric generation SDG&E accounts for the economic effects of
regulation 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, which became effective
January 1, 1998, is to ensure that the utilities' energy affiliates do not
gain an unfair advantage over other competitors in the marketplace and that
utility customers do not subsidize affiliate activities.
The CPUC excluded utility-to-utility transactions between the Company
and SoCalGas from the affiliate-transaction rules in its March 1998 decision
approving the PE/Enova business combination. See Notes 1 and 12 of the notes
to Consolidated Financial Statements for additional information.

Allowed Rate of Return

In June 1999, the Company was authorized to earn a rate of return on rate
base of 8.75 percent and a rate of return on common equity of 10.60 percent,
compared to 9.35 percent and 11.6 percent prior to July 1, 1999,
respectively. The Company can earn more than the authorized rate by
controlling costs below approved levels, by experiencing increased volumes of
sales not subject to balancing accounts (both of which are subject to revenue
sharing, as described in Note 12 of the notes to Consolidated Financial
Statements) or by achieving favorable results in certain areas, such as
incentive mechanisms that are not subject to revenue sharing. 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
investment within the amounts authorized to be collected in rates. It is the
intent of management to control operating expenses and investments within the
amounts authorized to be collected in rates in the PBR decision. The Company
intends to make the efficiency improvements, changes in operations and cost
reductions necessary to achieve this objective and earn at least its
authorized rate of return. However, in view of the earnings-sharing mechanism
and other elements of the PBR, it is more difficult to exceed authorized
returns to the degree experienced prior to the inception of PBR. See
additional discussion of PBR above and in Note 12 of the notes to
Consolidated Financial Statements.

Environmental Matters
The Company's operations are subject to federal, state and local
environmental laws and regulations governing such things as land use, solid
waste disposal, hazardous wastes, air and water quality, and the protection
of wildlife.
Because the potential situations in which the Company is faced with
environmental issues are in connection with utility operations, capital costs
to comply with environmental requirements are generally recovered through the
depreciation components of customer rates. California utilities' customers
also generally are responsible for 90 percent of the non-capital costs
associated with hazardous substances and the normal operating costs
associated with safeguarding air and water quality, disposing properly of
solid wastes, and protecting endangered species and other wildlife.
Therefore, the likelihood of the Company's financial position or results of
operations being adversely affected in a significant amount is remote.
The environmental issues currently facing the Company or resolved during
the latest three-year period include investigation and remediation of its
manufactured-gas sites (one completed as of December 31, 1999 and three to be
completed), asbestos and other cleanup at its former fossil fueled power
plants (all sold in 1999 and actual or estimated cleanup costs included in
the transactions), cleanup of third-party waste disposal sites used by the
Company, which has been identified as a Potentially Responsible Party
(investigation and remediations are continuing), and mitigation of damage to
the marine environment caused by the cooling-water discharge from SONGS Units
2 and 3 (the requirements for enhanced fish protection, a 150-acre artificial
reef and restorations on 150 acres of coastal wetlands are in process).

Market Risk

The Company's policy is to use derivative financial instruments to reduce its
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
exposes 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, 1999, the
notional amount of swap transactions associated with the regulated operations
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, the use of derivative financial instruments by the Company is
subject to certain limitations imposed by Sempra Energy's risk management
policies and regulatory requirements. The counterparties with whom the Company
enters into derivative transactions must also meet corporate credit
standards. 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 equity and energy. Sempra Energy has adopted
corporate-wide policies governing its market-risk management activities. An
Energy Risk Management Oversight Committee, consisting of senior officers,
oversees company-wide energy-price risk-management and trading activities to
ensure compliance with Sempra Energy's stated energy risk management and
trading policies. In addition, all affiliates have groups that monitor and
control energy-price risk management and trading activities independently
from the groups responsible for creating or actively managing these risks.

Along with other tools, the Company uses Value at Risk (VaR) to measure
its exposure to market risk. VaR is an estimate of the potential loss on a
position or portfolio of positions over a specified holding period, based on
normal market conditions and within a given statistical confidence level. The
Company has adopted the variance/covariance methodology in its calculation of
VaR, and uses a 95 percent confidence level. Holding periods are specific to
the types of positions being measured, and are determined based on the size
of the position or portfolios, market liquidity, purpose 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, 1999, 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
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. Subject
to regulatory constraints, interest-rate swaps 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 $77 million as of December 31, 1999, assuming a one-year
holding period.

Energy-Price Risk

Market risk related to physical commodities is based upon potential
fluctuations in natural gas and electricity 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 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

SDG&E may, at times, be exposed to limited market risk in its natural gas
purchase, sale and storage activities as a result of activities under its gas
PBR. SDG&E manages this risk within the parameters of the Company's market-
risk management and trading framework. As of December 31, 1999, the total VaR
of SDG&E's natural gas positions was not material.

Credit Risk

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

Year 2000 Issues
Sempra Energy established an overall company-wide Year 2000 readiness effort
that included SDG&E. There were only a few, very minor year 2000
interruptions to the Company's automated systems and applications with
suppliers and customers. Sempra Energy incurred expenses of $48 million ($7.6
million in 1999) for its Year 2000 readiness effort and expects to incur no
additional costs

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. In June 1999, the effective date of this
statement was deferred for one year. As amended, SFAS 133, which is effective
for the company on January 1, 2001, requires that an entity recognize all
derivatives as either assets or liabilities in the statement of financial
position, measure those instruments at fair value and recognize changes in
the fair value of derivatives in earnings in the period of change unless
the derivative qualifies as an effective hedge that offsets certain exposures.
The effect of this standard on the company's Consolidated Financial Statements
has not yet been determined.

Information Regarding Forward-Looking Statements
This Annual Report contains statements that are not historical fact and
constitute forward looking statements within the meaning of the Private
Securities Litigation Reform Act of 1995. The words "estimates," "believes,"
"expects," "anticipates," "plans," "intends," "may" and "should" or similar
expressions or discussions of strategy or of plans are intended to identify
forward-looking statements that involve risks and uncertainties and
assumptions. Future results may differ materially from those expressed in
these forward-looking statements.
These statements are necessarily based upon various assumptions
involving judgments with respect to the future and other risks, 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; exchange rates; energy markets, including the timing and
extent of changes in commodity prices; weather conditions; business,
regulatory or legal decisions; the pace of deregulation of retail natural gas
and electricity delivery; the timing and success of business development
efforts; and other uncertainties - all of which are difficult to predict and
many of which are beyond the control of the Company. Readers are cautioned
not to rely unduly on any forward-looking statements and are urged to review
and consider carefully the risks, uncertainties and other factors which
affect the 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, 1999 and 1998,
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, 1999. 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, 1999 and 1998, and the results of
their operations and their cash flows for each of the three years in the
period ended December 31, 1999 in conformity with generally accepted
accounting principles.

/s/ DELOITTE & TOUCHE LLP

San Diego, California
February 4, 2000

<TABLE>

SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED INCOME
Dollars in millions
<CAPTION>

For the years ended December 31 1999 1998 1997
------- ------- -------
<S> <C> <C> <C>
Operating Revenues
Electric $1,818 $1,865 $1,769
Gas 389 384 398
------- ------- -------
Total 2,207 2,249 2,167
------- ------- -------
Expenses
Electric fuel 69 177 164
Purchased power - net 467 260 441
Gas purchased for resale 168 166 183
Operation and maintenance 479 541 443
Depreciation and decommissioning 561 603 324
Other taxes and franchise payments 80 83 78
Income taxes 102 133 217
------- ------- -------
Total 1,926 1,963 1,850
------- ------- -------
Operating Income 281 286 317
------- ------- -------
Other Income and (Deductions)
Allowance for equity funds used
during construction 5 5 5
Interest income 40 31 4
Regulatory Interest (6) (2) (7)
Taxes on nonoperating income (24) (9) (2)
Other - net 23 (14) (5)
------- ------- -------
Total 38 11 (5)
------- ------- -------
Income Before Interest Charges 319 297 312
------- ------- -------
Interest Charges
Long-term debt 84 96 69
Other 31 4 2
Amortization of debt discount and
expense, less premium 7 8 5
Allowance for borrowed funds
used during construction (2) (2) (2)
------- ------- -------
Total 120 106 74
------- ------- -------
Net Income 199 191 238
Preferred Dividend Requirements 6 6 6
------- ------- -------
Earnings Applicable to Common Shares $ 193 $ 185 $ 232
======= ======= =======
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 1999 1998
------- -------
<S> <C> <C>

ASSETS
Utility plant - at original cost $4,483 $4,903
Accumulated depreciation and decommissioning (2,326) (2,603)
------ ------
Utility plant - net 2,157 2,300
------ ------
Nuclear decommissioning trust 551 494
------ ------
Current assets
Cash and temporary investments 337 284
Accounts receivable 192 199
Due from affiliates 152 110
Income taxes receivable 87 --
Inventories 61 77
Regulatory balancing accounts undercollected - net -- 9
Other 14 17
------ ------
Total current assets 843 696
------ ------
Loan to parent 422 --
Deferred taxes recoverable in rates 114 194
Regulatory assets 233 511
Deferred charges and other assets 46 62
------ ------
Total $4,366 $4,257
====== ======
</TABLE>

<TABLE>
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
Dollars in millions
<CAPTION>
Balance at December 31 1999 1998
------- -------

<S> <C> <C>
CAPITALIZATION AND LIABILITIES
Capitalization
Common stock $ 857 $ 857
Retained earnings 460 267
Accumulated other comprehensive income (3) --
------ ------
Total common equity 1,314 1,124
Preferred stock not subject to mandatory redemption 79 79
Preferred stock subject to mandatory redemption 25 25
Long-term debt 1,418 1,548
------ ------
Total capitalization 2,836 2,776
------- ------
Current liabilities
Current portion of long-term debt 66 72
Accounts payable 159 165
Deferred income taxes 106 37
Dividends payable 2 102
Interest accrued 9 9
Regulatory balancing accounts overcollected - net 192 --
Other 142 148
------ ------
Total current liabilities 676 533
------ ------
Customer advances for construction 44 41
Deferred income taxes - net 327 397
Deferred investment tax credits 51 89
Deferred credits and other liabilities 432 421
------ ------
Total $4,366 $4,257
====== ======
See notes to Consolidated Financial Statements.
</TABLE>

<TABLE>
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED CASH FLOWS
Dollars in millions
<CAPTION>
For the years ended December 31 1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>

Cash Flows from Operating Activities
Net income $ 199 $ 191 $ 238
Adjustments to reconcile net income
to net cash provided by operating activities
Depreciation and decommissioning 561 603 324
Application of plant sale proceeds to stranded costs (303) - -
Allowance for equity funds used during construction (5) (5) (5)
Deferred income taxes and investment tax credits (72) (132) 10
Application of balancing accounts to stranded costs (66) (86) --
Non-cash rate reduction bond revenue (42) -- --
Other - net 57 (64) 21
Changes in working capital components
Accounts receivable (41) 30 (41)
Inventories -- (12) (2)
Other current assets 3 51 (4)
Interest and taxes accrued (17) 39 (40)
Accounts payable and other current liabilities (21) (66) (143)
Regulatory balancing accounts 267 (14) 23
------- ------- -------
Net cash provided by operating activities 520 535 381
------- ------- -------
Cash Flows from Investing Activities
Net proceeds from sales of generating plants 466 -- --
Loan to parent (422) -- --
Utility construction expenditures (245) (227) (197)
Contributions to decommissioning funds (16) (22) (22)
Other - net (8) (28) 5
------- ------- -------
Net cash used by investing activities (225) (277) (214)
------- ------- -------
Cash Flows from Financing Activities
Dividends paid (106) (269) (256)
Issuances of long-term debt -- -- 677
Repayment of long-term debt (136) (241) (133)
------- ------- -------
Net cash provided (used) by financing activities (242) (510) 288
------- ------- -------
Net increase (decrease) 53 (252) 455
Cash and temporary investments, January 1 284 536 81
------- ------- -------
Cash and temporary investments, December 31 $ 337 $ 284 $ 536
======= ======= =======
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 1999 1998 1997
------- ------- -------
<S> <C> <C> <C>
Supplemental Disclosure of Cash Flow Information
Cash paid during the year for:
Income tax payments, net of refunds $ 266 $ 207 $ 217
======= ======= =======
Interest payments, net of amounts capitalized $ 134 $ 118 $ 89
======= ======= =======

Supplemental Schedule of Non-Cash Transactions
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, 1999, 1998, 1997
(Dollars in millions)
<CAPTION>
| Preferred Stock Accumulated
| Not Subject Other Total
Comprehensive | to Mandatory Common Comprehensive Retained Shareholders'
Income | Redemption Stock Income Earnings Equity
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>

Balance at December 31, 1996 | $ 79 $ 857 $ 546 $ 1,482
Net income/comprehensive income $ 238 | 238 238
Special dividend to Enova Corporation | (70) (70)
Preferred stock dividends declared | (6) (6)
Common stock dividends declared | (178) (178)
- -------------------------------------------------------------------------------------------------------------
Balance at December 31, 1997 | 79 857 530 1,466
Net income/comprehensive income 191 | 191 191
Special dividends to Sempra Energy | (129) (129)
Preferred dividends declared | (6) (6)
Common stock dividends declared | (319) (319)
- -------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 | 79 857 267 1,203
Net income 199 | 199 199
Other comprehensive income |
Pension (3)| $ (3) (3)
-----|
Comprehensive income $ 196|
Preferred dividends declared | (6) (6)
- -------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 $ 79 $ 857 $ (3) $ 460 $ 1,393
=============================================================================================================

See notes to Consolidated Financial Statements.

</TABLE>

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1: BUSINESS COMBINATION

On June 26, 1998, Enova Corporation (Enova), the parent company of
San Diego Gas & Electric (SDG&E or the Company), and Pacific
Enterprises (PE), parent company of Southern California Gas Company
(SoCalGas), combined into a new company named Sempra Energy
(Parent). 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 the combining companies and their subsidiaries remained
outstanding.

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. The Company's policy is
to consolidate subsidiaries that are more than 50 percent owned
and controlled. All material intercompany accounts and transactions
have been eliminated.

Effects of Regulation

The accounting policies of SDG&E conform with generally accepted
accounting principles for regulated enterprises and reflect the
policies of the California Public Utilities Commission (CPUC) and
the Federal Energy Regulatory Commission (FERC).
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 to be no longer subject to SFAS No. 71, or
recovery was to be 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.
Prior to 1998, 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 has been
applied to transition cost recovery, and fluctuations in certain
costs and consumption levels can now affect earnings from electric
operations. Additional information on electric-industry
restructuring is included in Note 12.

Regulatory Assets

Regulatory assets include unrecovered premium on early retirement
of debt, post-retirement benefit costs, deferred income taxes
recoverable in rates and other regulatory-related expenditures that
the Company expects to recover in future rates. See Note 12 for
additional information.

Inventories

Included in inventories at December 31, 1999, are $50 million
of utility materials and supplies ($48 million in 1998), and
$11 million of natural gas and fuel oil ($29 million in 1998).
Materials and supplies are generally valued at the lower of
average cost or market; fuel oil and natural gas are valued by
the last-in first-out method.

Utility Plant

This primarily represents the buildings, equipment and other
facilities used by SDG&E 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, 1999, are: electric distribution $2.5 billion,
electric transmission $0.7 billion, other electric $0.4 billion and
natural gas operations $0.9 billion. The corresponding amounts at
December 31, 1998, were essentially the same, except that other
electric decreased by $0.5 billion in 1999 in connection with
electric industry restructuring, as described in Note 12.
Accumulated depreciation and decommissioning of electric and
natural gas utility plant in service at December 31, 1999, are $1.8
billion and $0.5 billion, respectively, and at December 31, 1998,
were $2.2 billion and $0.4 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 1999, 1998, and
1997, respectively are: electric generation 8.70, 6.49, 5.60,
electric distribution 4.69, 4.49, 4.39, electric transmission 3.50,
3.31, 3.28, other electric 8.21, 6.29, 6.02, and natural gas
operations 3.83, 4.01, 4.03. The increases for electric generation
reflect the accelerated recovery of generation facilities in 1999
and 1998 and the increase in depreciation rates resulting from the
1999 Cost of Service proceeding. The increase in 1999 for other
electric is due to the increase in depreciation rates resulting
from the 1999 Cost of Service proceeding. 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.

Nuclear-Decommissioning Liability

Deferred credits and other liabilities at December 31, 1999,
include $165 million ($146 million in 1998) of accumulated
decommissioning costs associated with SDG&E's San Onofre Nuclear
Generating Station (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

SFAS No. 130, "Reporting Comprehensive Income." 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, minimum pension
liability adjustments.

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.

Cash and Cash Equivalents

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

Basis of Presentation

Certain prior-year amounts have been reclassified 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." In
June 1999, the effective date of this statement was deferred for
one year. As amended, SFAS 133, which is effective for the company
on January 1, 2001, 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

At December 31, 1999, SDG&E had $205 million of bank lines available
to support commercial paper and variable-rate, long-term debt. The
credit agreements expire at varying dates from 2000 through 2002 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, 1999, and 1998.

NOTE 4: LONG-TERM DEBT

- -------------------------------------------------------------------
December 31,
(Dollars in millions) 1999 1998
- -------------------------------------------------------------------
First Mortgage Bonds
7.625% June 15, 2002 $ 28 $ 28
6.800% June 1, 2015 14 14
5.900% June 1, 2018 68 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 10
Variable rates September 1, 2020 58 58
5.850% June 1, 2021 60 60
8.500% April 1, 2022 10 10
5.420% December 1, 2027 45 45
6.400% December 1, 2027 75 75
Variable rates December 1, 2027 105 130
------------------------
684 712
------------------------
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 526 592
Capital leases 21 63
------------------------
Total 1,485 1,621

Less:
Current portion of long-term debt 66 72
Unamortized debt discount less premium 1 1
------------------------
Total $1,418 $1,548
- -------------------------------------------------------------------

Excluding capital leases, which are described in Note 11, maturities
of long-term debt, including rate-reduction bonds, are $66 million
in 2000, $66 million in $2001, $94 million in 2002, $66 million in
2003, $66 million in 2004 and $1,106 million thereafter. SDG&E has
CPUC authorization to issue an additional $138 million in long-term
debt. Although holders of variable-rate bonds may elect to redeem
them prior to scheduled maturity, for purposes of determining the
maturities listed above, it is assumed the bonds will be held to
maturity.

First-Mortgage Bonds

First-mortgage bonds are secured by a lien on substantially all of
SDG&E's utility plant. SDG&E may issue additional first-mortgage
bonds upon compliance with the provisions of their bond indentures,
which permit, among other things, the issuance of an additional $712
million of first-mortgage bonds as of December 31, 1999.
In 1999, SDG&E retired $28 million of first-mortgage bonds
prior to scheduled maturity.

Callable Bonds

At SDG&E's option, certain first-mortgage bonds may be called at a
premium. SDG&E has $287 million of variable-rate bonds with
provisions that are callable at various dates within one year. Of
the Company's remaining callable bonds, $55 million are callable in
the year 2000, $204 million in the year 2002 and $221 million in
2003.

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.
The sizes of the rate-reduction bond issuances were set so as to
make the utilities neutral as to the 10-percent rate reduction, and
were based on a four-year period to recover stranded costs. Because
SDG&E recovered its stranded costs in only 18 months (due to the
greater-than-anticipated plant-sale proceeds), its bond proceeds
were greater than needed. Accordingly, SDG&E will return to its
customers over $400 million that it has collected or will collect
from its customers. The timing of the return will differ from the
timing of the collection, but the specific timing of the repayment
and the interest rate thereon are the subject of a CPUC proceeding
and are expected to be resolved in early 2000. This refund will not
affect SDG&E's net income, except to the extent that the interest
associated with the refund (12.63 percent if not reduced as a
result of the CPUC proceeding) differs from the return earned by
the Company on the funds. The bonds and their repayment schedule
are not affected by this refund.

Unsecured Debt

Various long-term obligations totaling $254 million are unsecured.
Unsecured bonds totaling $124 million have variable-interest-rate
provisions.

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, 1999, 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. The Company's interests at December
31, 1999, are:

- -----------------------------------------------------------
(Dollars in millions) Southwest
Project SONGS Powerlink
- -----------------------------------------------------------
Percentage ownership 20 89
Utility plant in service $ 57 $ 217
Accumulated depreciation
and amortization $ 25 $ 111
Construction work in progress $ 7 $ 1
- -----------------------------------------------------------

The Company's share of operating expenses is included in the
Statements of Consolidated Income. Each participant in the project
must provide its own financing. The amounts specified above for
SONGS include nuclear production, transmission and other
facilities. Certain 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 $432 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. 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
owner of Unit 1 received the required regulatory approvals to begin
decommissioning Unit 1 in January 2000.
The amounts collected in rates are invested in externally
managed trust funds. The securities held by the trust are
considered available for sale and shown on the Consolidated Balance
Sheets at market value. These values reflect unrealized gains of
$164 million and $149 million at December 31, 1999, and 1998,
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 carrying value
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:
- -------------------------------------------------------------
1999 1998 1997
- -------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Depreciation 5.2 1.3 6.8
State income taxes - net of
federal income tax benefit 5.9 5.6 5.7
Tax credits (2.1) (1.7) (1.3)
Charitable contribution of plant (7.9) - -
Other - net 2.6 2.4 1.7
---------------------------
Effective income tax rate 38.7 42.6% 47.9%
- -------------------------------------------------------------

Accumulated deferred income taxes at December 31 result from the
following:

- -------------------------------------------------------------
(Dollars in millions) 1999 1998
- -------------------------------------------------------------
Deferred tax liabilities
Differences in financial and
tax bases of utility plant $ 382 $ 440
Regulatory balancing accounts 150 74
Loss on reacquired debt 30 34
Other 70 71
---------------------------
Total deferred tax liabilities 632 619
---------------------------
Deferred tax assets
Investment tax credits 61 63
Other 138 122
---------------------------
Total deferred tax assets 199 185
---------------------------
Net deferred income tax liability 433 434
- -------------------------------------------------------------

The net liability is recorded on the consolidated balance
sheet as follows:

- -------------------------------------------------------------
(Dollars in millions) 1999 1998
- -------------------------------------------------------------
Current liability(asset) $ 106 $ 37
Non-current liability 327 397
- -------------------------------------------------------------
Total $ 433 $ 434
- -------------------------------------------------------------

The components of income tax expense are as follows:

- -------------------------------------------------------------
(Dollars in millions) 1999 1998 1997
- -------------------------------------------------------------
Current
Federal $ 90 $ 150 $ 164
State 39 41 44
---------------------------
Total current taxes 129 191 208
---------------------------
Deferred
Federal 11 (30) 13
State ( 9) (16) 2
---------------------------
Total deferred taxes 2 (46) 15
---------------------------
Deferred investment
tax credits - net (5) (3) (4)
---------------------------
Total income tax expense $ 126 $ 142 $ 219
- -------------------------------------------------------------

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 numerous
participants were transferred from the Company's plans to plans of
related entities. In connection therewith, the company recorded a
$9 million special termination benefit in 1998.

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) 1999 1998 1999 1998
- --------------------------------------------------------------------------------
Weighted-Average Assumptions
as of December 31:
<S> <C> <C> <C> <C>
Discount rate 7.75% 6.75% 7.75% 6.75%
Expected return on plan assets 8.00% 8.50% 4.00% 4.50%
Rate of compensation increase 5.00% 5.00% 5.00% 5.00%
Cost trend of covered
health-care charges - - 7.75%(1) 8.00%(1)

Change in Benefit Obligation:
Net benefit obligation at
January 1 $ 494 $ 605 $ 48 $ 43
Service cost 11 19 1 1
Interest cost 34 43 3 3
Plan Participants' contributions - - 2 -
Plan amendments - (3) - -
Actuarial (gain) loss 4 (17) (4) 5
Transfer of liability (2) (15) (112) - -
Special termination benefits - 9 - -
Gross benefits paid (52) (50) (5) (4)
-----------------------------------------------
Net benefit obligation at
December 31 476 494 45 48
-----------------------------------------------
Change in Plan Assets:
Fair value of plan assets
at January 1 587 699 17 14
Actual return on plan assets 178 103 - 1
Employer contributions - 1 4 6
Plan Participants' contributions - - 2 -
Transfer of assets (2) - (166) - -
Gross benefits paid (52) (50) (5) (4)
-----------------------------------------------
Fair value of plan assets
at December 31 713 587 18 17
-----------------------------------------------
Funded status at December 31 237 93 (27) (31)
Unrecognized net actuarial
(gain) loss (317) (196) (2) 1
Unrecognized prior service cost 20 23 - -
-----------------------------------------------
Net liability at December 31 $ (60) $ (80) $ (29) $ (30)
- --------------------------------------------------------------------------------
(1) Decreasing to ultimate trend of 6.50% in 2004.
(2) To reflect transfer of plan assets and liability to Sempra Energy.

</TABLE>

The following table provides the components of net periodic benefit
cost (income) for the plans:
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------
Other
Pension Benefits Postretirement Benefits
-----------------------------------------------
(Dollars in millions) 1999 1998 1997 1999 1998 1997
-----------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Service cost $ 11 $ 19 $ 18 $ 1 $ 1 $ 1
Interest cost 34 43 40 3 3 3
Expected return on assets (47) (60) (50) - (1) -
Amortization of:
Transition obligation - - - 2 2 2
Prior service cost 3 3 3 - - -
Actuarial gain (9) (11) (9) - - -
Special termination benefit - 9 - - - -
Regulatory adjustment - - - - - (1)
-----------------------------------------------
Total net periodic benefit cost $ (8) $ 3 $ 2 $ 6 $ 5 $ 5
(income)
- ---------------------------------------------------------------------------------
</TABLE>
The following table provides the amounts recognized on the
SDG&E balance sheet at December 31.
<TABLE>
<caption
- -------------------------------------------------------------------------------------
Other
Pension Benefits Postretirement Benefits
----------------------------------------------
(Dollars in millions) 1999 1998 1999 1998
- -------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Prepaid benefit cost - - - -
Accrued benefit cost $(57) $(80) $(29) $(30)
Additional minimum liability - - - -
Intangible asset - - - -
Accumulated other
comprehensive income ( 3) - - -
- -------------------------------------------------------------------------------------
Net liability (60) (80) (29) (30)
- -------------------------------------------------------------------------------------
</TABLE>
Assumed health care cost trend rates have a significant effect
on the amounts reported for the health care plans. A one-percent
change in assumed health care cost trend rates would have the
following effects:
- ------------------------------------------------------------------------
(Dollars in millions) 1% Increase 1% Decrease
- -----------------------------------------------------------------------
Effect on total of service and interest cost
components of net periodic postretirement
health care benefit cost -- --

Effect on the health care component of the
accumulated postretirement benefit obligation $ 2 $ (1)
- ------------------------------------------------------------------------
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 stock or mutual
funds. Employer contributions, after one year of service, are made
in shares of Sempra Energy stock. Employer contributions are equal
to 50 percent of the first 6 percent of eligible base salary
contributed by employees. During 1999, SDG&E's plan contribution
was age-based for represented employees. Annual expense for the
savings plans was $4 million in 1999, $5 million in 1998 and $3
million in 1997.

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.
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 and $1
million in 1997.

NOTE 9: FINANCIAL INSTRUMENTS

Fair Value

The fair values of the Company's financial instruments are not
materially different from the carrying amounts, except for long-
term debt and preferred stock. The carrying amounts and fair values
of long-term debt are $1,484 million and $1,465 million,
respectively, at December 31, 1999, and $1,620 million and $1,679
million at December 31, 1998. Included in long-term debt are
SDG&E's rate-reduction bonds. The carrying amounts and fair values
of the bonds are $526 million and $511 million, respectively, at
December 31, 1999, and $592 million and $607 million, respectively,
at December 31, 1998. The carrying amounts and fair values of
preferred stock are $104 million and $97 million, respectively, at
December 31, 1999, and $104 million and $105 million, respectively,
at December 31, 1998. The fair values of the first-mortgage and
other bonds and preferred stock are estimated based on quoted
market prices for them or for similar issues. The fair values of
long-term notes payable are based on the present value of the
future cash flows, discounted at rates available for similar notes
with comparable maturities.

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, 1999, and 1998, 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 $1.3 million at December 31, 1999, and $3 million at
December 31, 1998. 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, 1999, 1998, and 1997, gains
and losses from these activities are not material to SDG&E's
financial statements.

NOTE 10: SHAREHOLDERS' EQUITY

- --------------------------------------------------------------
December 31,
(Dollars in millions) 1999 1998
- --------------------------------------------------------------
COMMON EQUITY
Common stock, without par value,
authorized 255,000,000 shares $ 857 $ 857
Retained earnings 460 267
Accumulated other comprehensive income (3) --
----------------------
Total common equity $1,314 $1,124
- --------------------------------------------------------------

All shares of SDG&E common stock are owned by Enova
Corporation.

Dividend Restrictions
The CPUC regulates SDG&E's capital structure, limiting the
dividends it may pay. At December 31, 1999, $401 million of
retained earnings was available for future dividends.

- ---------------------------------------------------------------
Call December 31,
(Dollars in millions except call price) Price 1999 1998
- ---------------------------------------------------------------
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 7 7
4.60% Series, 373,770
shares outstanding $ 20.25 7 7
Without par value:
$1.70 Series, 1,400,000
shares outstanding $ 25.85 35 35
$1.82 Series, 640,000
shares outstanding $ 26.00 16 16
--------------
Total not subject to
mandatory redemption $79 $79
---------------------------------------------------------------

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
The company buys natural gas under several short-term and long-term
contracts. Short-term purchases are primarily from various
Southwest U.S. suppliers and are based on monthly spot-market
prices. SDG&E natural gas purchases are primarily from various U.S.
Southwest gas supplies and are based on monthly spot-market prices.
SDG&E has long-term capacity contracts with interstate pipelines
which expire on various dates between 2007 and 2023. These
agreements provide for payments of an annual reservation charge.
SDG&E recovers such fixed charges in rates.
SDG&E had been involved in negotiations and litigation with
four Canadian suppliers concerning contract terms and prices
related to long-term natural gas supply contracts. In 1999, SDG&E
settled with the last of the four suppliers, terminating the
contract. SDG&E continues to purchase natural gas from one of the
suppliers under terms of the settlement agreement. SDG&E purchases
natural gas on a spot basis to fill any additional long-term
pipeline capacity. SDG&E intends to continue using the long-term
pipeline capacity in other ways as well, including the transport of
replacement natural gas and the release of a portion of this
capacity to third parties. All of SDG&E's gas is delivered through
SoCalGas pipelines under a short-term transportation agreement. In
addition, SoCalGas provides SDG&E six billion cubic feet of natural
gas storage capacity under an agreement expiring March 2001
At December 31, 1999, the future minimum payments under
natural gas contracts were:

- -----------------------------------------------------------------
Storage and
(Dollars in millions) Transportation Natural Gas
- -----------------------------------------------------------------
2000 $ 14 23
2001 11 23
2002 9 24
2003 11 14
2004 14 -
Thereafter 196 -
----------------------------------
Total minimum payments $ 255 84
- -----------------------------------------------------------------

Total payments under the contracts were $220 million in 1999,
$324 million in 1998 and $335 million in 1997.

Purchased-Power Contracts

SDG&E buys electric power under several long-term contracts. The
contracts expire on various dates between 2000 and 2025. Under
California's electric-industry restructuring law, which is
described in Note 12, the above market cost of these contracts is
recovered from virtually all of SDG&E's customers. In general, the
market value of these contracts is recovered by bidding them into
the California Power Exchange (PX) and receiving revenue from the
PX for bids accepted.

At December 31, 1999, the estimated future minimum payments
under the long-term contracts were:

- -----------------------------------------------------------------
(Dollars in millions)
- -----------------------------------------------------------------
2000 $ 198
2001 180
2002 133
2003 133
2004 127
Thereafter 2,046
----------
Total minimum payments $2,817
- -----------------------------------------------------------------

The payments 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, under the contracts were $251
million in 1999, $293 million in 1998 and $421 million in 1997.

Leases

SDG&E has capital and operating leases on real and personal
property expiring at various dates from 2000 to 2037. Certain
leases on office facilities contain escalation clauses
requiring annual increases in rent ranging from 2 percent to 7
percent. The rentals payable under these leases are determined
on both fixed and percentage bases, and most leases contain
options to extend, which are exercisable by the Company. The
Company also has nuclear fuel and real property that are
financed by long-term capital leases. Property, plant and
equipment included $46 million at December 31, 1999, and $177
million at December 31, 1998 related to these leases. The
associated accumulated amortization is $24 million and $114
million, respectively.

The minimum rental commitments payable in future years under
all noncancellable leases are:

- -----------------------------------------------------------------
Operating Capitalized
(Dollars in millions) Leases Leases
- -----------------------------------------------------------------
2000 $ 13 $23
2001 12 -
2002 11 -
2003 8 -
2004 7 -
Thereafter 26 -
------------------------------
Total future rental commitment $ 77 23
Imputed interest (5% to 6%) (2)
-----------
Net commitment $21
- -----------------------------------------------------------------

Rent expense totaled $39 million in 1999, $50 million in 1998
and $43 million in 1997.

Other Commitments and Contingencies

At December 31, 1999, commitments for capital expenditures were
approximately $10 million.

Environmental Issues

The Company believes that its operations are subject to federal,
state and local environmental laws and regulations governing
hazardous wastes, air and water quality, land use, solid waste
disposal and the protection of wildlife. SDG&E incurs significant
costs to operate its facilities in compliance with these laws and
regulations and these costs generally have been recovered in
customer rates.
In 1994, the CPUC approved the Hazardous Waste Collaborative
Memorandum account allowing utilities to recover their hazardous
waste costs, including those related to Superfund sites or similar
sites requiring cleanup. Recovery of 90 percent of cleanup costs
and related third-party litigation costs and 70 percent of the
related insurance-litigation expenses is permitted. In addition,
the Company has the opportunity to retain a percentage of any
insurance recoveries to offset the 10 percent of costs not
recovered in rates. Environmental liabilities that may arise are
recorded when remedial efforts are probable and the costs can be
estimated.
SDG&E's capital expenditures to comply with environmental laws
and regulations were $160,000 in 1999, $1 million in 1998 and $4
million in 1997, and are not expected to be significant over the
next five years due to the sale of the Company's fossil fuel power
plants. 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.
As discussed in Note 12, restructuring of the California
electric-utility industry has changed the way utility rates are
set and costs are recovered. In 1998, the CPUC modified the
Hazardous Waste Collaborative mechanism by providing that electric
generation-related cleanup costs be eligible for transition-cost
recovery. The effect of this decision is that SDG&E's costs of
compliance with environmental regulations may not 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 $9.5 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 $36 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 pro-vides 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
12 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 $5 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.
The Nuclear Waste Policy Act of 1982 made the DOE responsible for
the disposal of nuclear fuel and other radioactive waste. However,
it is uncertain when the DOE will begin accepting nuclear fuel from
SONGS. Continued delays by the DOE can lead to increased cost of
disposal, which could be significant. If this occurs and the
Company is unable to recover the increased costs from the federal
government or from its customers, the Company's profitability from
SONGS would be adversely affected.

Litigation

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

Electric Distribution System Conversion

Under a CPUC-mandated program and through franchise agreements
with various cities, SDG&E is committed, in varying amounts, to
converting overhead distribution facilities to underground. As
of December 31, 1999, the aggregate unexpended amount of this
commitment was approximately $105 million. Capital expenditures
for underground conversions were $20 million in 1999, and $17
million in 1998 and 1997.

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 PX that serves as an independent 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.
California's investor-owned 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. Purchases from the PX/ISO are included in purchased-power
expenses and PX/ISO power revenues have been netted therein on the
Statements of Consolidated Income. Revenues from the PX/ISO reflect
sales to the PX/ISO commencing April 1, 1998, at market prices of
energy from SDG&E's power plants and from long-term purchased-power
contracts.
Utilities were 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 the utilities had
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. Outside of those exceptions,
any stranded costs not recovered through 2001 would not be
collected from customers. Such costs, if any, would be written off
as a charge against earnings. Nuclear decommissioning costs are
nonbypassable until fully recovered, but are not included as part
of transition costs. Additional information is provided in Note 5.
In June 1999, SDG&E completed the recovery of its stranded
costs, other than the future above-market portion of qualifying
facilities and other purchased-power contracts that were in effect
at December 31, 1995, and SONGS costs as described below. These
costs will continue to be collected in rates. Recovery of the other
stranded costs was effected by, among other things, the sale of
SDG&E's fossil power plants and combustion turbines during the
quarter ended June 30, 1999. The South Bay Power Plant sale to the
San Diego Unified Port District for $110 million was completed on
April 23, 1999. Duke South Bay, a subsidiary of Duke Energy Power
Services, will manage the plant for the Port District. The sale of
the Encina Power Plant and 17 combustion-turbine generators to
Dynegy Inc. and NRG Energy Inc. for $356 million was completed on
May 21, 1999. SDG&E will operate and maintain both the South Bay
and Encina facilities for the new owners until April 2001 and May
2001, respectively.
Stranded costs included the cost of SONGS as of December 31,
1995. SDG&E retains ownership of its 20 percent interest in SONGS.
Subsequent SONGS costs are recoverable only from the sales of power
from SONGS, at rates previously fixed by the CPUC through December
31, 2003 and as determined by the market thereafter. If approved by
the CPUC, SDG&E is planning to auction its interest in SONGS. A
major issue being addressed is how to handle the decommissioning
trust to ensure that adequate funding is available at the time the
plant is decommissioned.
AB 1890 required 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.
The sizes of the rate-reduction bond issuances were set so as
to make the IOUs neutral as to the 10-percent rate reduction, and
were based on a four-year period to recover stranded costs. Because
SDG&E recovered its stranded costs in only 18 months (due to the
greater-than-anticipated plant-sale proceeds), the bond proceeds
were greater than needed. Accordingly, SDG&E will return to its
customers over $400 million that it has collected or will collect
from its customers. The timing of the return will differ from the
timing of the collection, but the specific timing of the repayment
and the interest rate thereon are the subject of a CPUC proceeding
and are expected to be resolved in early 2000. This refund will not
affect SDG&E's net income, except to the extent that the interest
associated with the refund (12.63 percent if not reduced as a
result of the CPUC proceeding) differs from the return earned by
the Company on the funds to be refunded. The bonds and their
repayment schedule are unaffected by this refund.
AB 1890 also includes a rate freeze for all IOU customers.
Beginning in 1998, SDG&E's system-average rates were fixed at 9.43
cents per kwh. The rate freeze would have stayed in place until
January 1, 2002. However, in connection with completion of its
stranded cost recovery (described above), SDG&E filed with the CPUC
for a mechanism to structure electric rates after the end of the
rate freeze. SDG&E received approval to reduce base rates (the non-
commodity portion of rates) to all electric customers effective
July 1, 1999. As a result base electric rates will decrease beyond
the original 10 percent rate reduction described above. The portion
of the electric rate representing the commodity cost is simply
passed through to customers and will fluctuate with the price of
electricity from the PX. Except for the interim protection
mechanism described below, customers will no longer be insulated
from commodity price fluctuations.
In April 1999, SDG&E filed an all-party settlement (including
energy service providers, the CPUC's Office of Ratepayer Advocates
(ORA), and the Utility Consumers Action Network (UCAN)) detailing
proposed implementation plans for lifting the rate freeze. Included
in the settlement is an interim customer-protection mechanism for
residential and small commercial customers that capped rates
between July 1999 and September 1999, regardless of how high the PX
price had moved during that period. The resulting undercollection
(which amounted to less than $1 million) is being recovered through
a balancing account mechanism. A CPUC decision adopting the all-
party settlement was issued in May 1999 and became effective July
1, 1999. The interim post rate-freeze period runs until the CPUC
issues its decision on the pending legal and policy issues of
ending the rate freeze. This decision is expected during the second
quarter of 2000. The decision will address, among other things, a
proposal by SDG&E that would limit SDG&E's obligation to purchase
from the PX to 80 percent of the electricity required by its
utility default customers, and to establish an Electric Commodity
Performance-Based Regulation mechanism, which would measure the
Company's effectiveness in procuring electricity on behalf of its
utility default commodity customers and the administration of its
above market purchased power contracts.
In October 1997, the FERC approved key elements of the
California IOU's restructuring proposal. This included the transfer
by the IOUs of the operational control of their transmission
facilities to the ISO, which is under FERC jurisdiction. The FERC
also approved the establishment of the California PX to operate as
an independent wholesale power pool. The IOUs pay to the PX an
upfront restructuring charge (in four annual installments) and an
administrative usage charge for each megawatt hour of volume
transacted. SDG&E's share of the restructuring charge is
approximately $10 million, which is being recovered in rates. 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 restructuring has been confined to
generation. Transmission and distribution have remained subject to
traditional cost-of-service regulation and performance-based
regulation. However, the CPUC is exploring the possibility of
opening up electric distribution to competition. During 2000, the
CPUC will consider whether any changes should be made in electric
distribution regulation. A CPUC staff report will be submitted on
this issue to the CPUC in the second quarter of 2000. SDG&E and
SoCalGas will actively participate in this effort.
On December 20, 1999 the FERC issued "Order 2000" concerning
the formation of Regional Transmission Organizations (RTOs). The
rule generally requires all public utilities that own, operate or
control interstate transmission to file by October 15, 2000, a
proposal for an RTO. Public utilities that are members of an
existing, FERC-approved regional entity, which includes SDG&E, must
file by January 15, 2001. The rule states that RTOs will be
operational by December 15, 2001. The FERC order permits a number
of different types of RTOs, including non-profit independent system
operators, for-profit transmission companies, or other approaches.
The FERC also allows flexibility so that an RTO can improve its
structure, geographic scope, market support and operations to meet
market needs. It notes that the FERC intends for RTOs: to alleviate
stress on the bulk power system caused by changes in the structure
of the industry; improve efficiencies in transmission grid
management through better pricing and congestion management;
improve grid reliability; remove remaining opportunities for
discriminatory transmission practices; improve market performance;
increase coordination among state regulatory agencies; cut
transaction costs; facilitate the success of state retail access
programs; and facilitate reduced regulation. The order also
specifies the required characteristics for each RTO, including
independence from market participants, and the functional
responsibilities required of each RTO. The order also provides
guidance on transmission pricing reforms. The identification of RTO
regions and formation of the RTO's will be subject to a
collaborative process. The impact of Order 2000 on SDG&E depends on
the results of this process and other implementation issues.

Gas Industry Restructuring

The natural gas industry experienced an initial phase of
restructuring during the 1980s by deregulating gas sales to noncore
customers. On January 21, 1998, the CPUC released a staff report
initiating a proceeding 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's natural gas consumers.
In August 1998, California enacted a law prohibiting the CPUC
from enacting any natural gas industry restructuring decision for
core (residential and small commercial) customers prior to January
1, 2000. During the implementation moratorium, the CPUC held
hearings throughout the state and intends to give the legislature a
draft ruling before adopting a final market-structure policy. SDG&E
has been actively participating in this effort and has argued in
support of competition intended to maximize benefits to customers
rather than to protect competitors.
In October 1999, the State of California enacted a law (AB
1421) which requires that gas utilities provide "bundled basic gas
service" (including transmission, storage, distribution,
purchasing, revenue-cycle services and after-meter services) to all
core customers, unless the customer chooses to purchase gas from a
non-utility provider. The law prohibits the CPUC from further
unbundling of distribution-related gas services (including meter
reading and billing) and after-meter services (including leak
investigation, inspecting customer piping and appliances, pilot
relighting and carbon monoxide investigation) for most customers.
The objective is to preserve both customer safety and customer
choice.

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 plant in a market where a
utility already has a highly developed infrastructure.
SDG&E's PBR mechanism is in effect through December 31, 2002
and scheduled to be updated at December 31, 2002, at which time it
will be updated for, among other things, changes in costs and
volumes. Key elements of the mechanism include an initial reduction
in base rates, an indexing mechanism that limits future rate
increases to the inflation rate less a productivity factor, a
sharing mechanism with customers if earnings exceed the authorized
rate of return on rate base, and rate refunds to customers if
service quality deteriorates or awards if service quality exceeds
set standards. Specifically, the key elements of the mechanism
include the following:

- -- Earnings up to 25 basis points in excess of the authorized rate
of return on rate base are retained 100 percent by shareholders.
Earnings that exceed the authorized rate of return on rate base by
greater than 25 basis points are shared between customers and
shareholders on a sliding scale that begins with 75 percent of the
additional earnings being given back to customers and declining to
0 percent as earned returns approach 300 basis points above
authorized amounts. There is no sharing if actual earnings fall
below the authorized rate of return. In 1999, SDG&E was authorized
to earn 9.05 percent on its rate base. For 2000, the authorized
return is 8.75 percent.

- -- Base rates are indexed based on inflation less an estimated
productivity factor.

- -- Performance indicators, including employee safety, electric
reliability, customer satisfaction, and call-center responsiveness,
affect the Company's future income potential. SDG&E is authorized
to earn or be penalized up to a maximum of $14.5 million annually
as a result of its performance in those areas.

- -- Annual cost of capital proceedings are replaced by an automatic
adjustment mechanism if changes in certain indices exceed
established tolerances. SDG&E's mechanism is triggered by a six-
month trailing average and a 100 basis point change in interest
rates. If this occurs, there would be an automatic adjustment of
rates for the change in the cost of capital according to a formula
which applies a percentage of the change to various capital
components.

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. On January 11, 2000, the CPUC issued a
proposed decision adopting an overall decrease in natural gas
revenues of $38 million for SDG&E. A final CPUC decision is
expected in the second quarter of 2000.

Cost Of Capital

For 2000, electric-industry restructuring has changed the method of
calculating the utility's annual cost of capital. In May 1998,
SDG&E filed with the CPUC its unbundled Cost of Capital application
to establish rates of return for SDG&E's electric-distribution and
natural gas businesses. In June 1999, the CPUC adopted a 10.6
percent return on common equity and 8.75 percent return on rate
base for SDG&E, compared to 9.35 percent and 11.6 percent prior to
July 1, 1999, respectively. The electric transmission cost of
capital is determined under a separate FERC proceeding.

Transactions Between Utilities and Affiliated Companies

On December 16, 1997, the CPUC adopted rules, effective January 1,
1998, establishing uniform standards of conduct governing the
manner in which IOUs conduct business with their energy-related
affiliates. The objective of the affiliate-transaction rules is to
ensure that these affiliates do not gain an unfair advantage over
other competitors in the marketplace and that utility customers do
not subsidize affiliate activities. The rules establish standards
relating to non-discrimination, disclosure and information
exchange, and separation of activities. The CPUC excluded utility-
to-utility transactions between SDG&E and SoCalGas from the
affiliate-transaction rules in its March 1998 decision approving
the business combination of Enova and PE, which is described in
Note 1.
During 1999, 1998 and 1997, the Company purchased natural gas
transportation and storage services from SoCalGas in the amount of
$50 million to $60 million per year.These sales were at rates
established by the CPUC.

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 generally are recorded the same as sales
or transactions with third parties. Interest expense and income tax
expense are not allocated to the reportable segments.

- -----------------------------------------------------------------------
For the year ended December 31,
(Dollars in millions) 1999 1998 1997
- -----------------------------------------------------------------------
Revenues:
Transmission & distribution $ 1,396 $ 1,430 $ 1,202
Electric Generation 422 435 567
Natural Gas 389 384 398
-------------------------------------
Total $ 2,207 $ 2,249 $ 2,167
-------------------------------------
Depreciation and amortization:
Transmission & distribution $ 148 $ 134 $ 128
Electric Generation 374 430 159
Natural Gas 39 39 37
-------------------------------------
Total $ 561 $ 603 $ 324
-------------------------------------
Segment Income:
Transmission & distribution $ 318 $ 302 $ 349
Electric Generation (5) 54 106
Natural Gas 70 63 79
-------------------------------------
Total segment income 383 419 534
-------------------------------------
Interest expense (120) (106) (74)
Income tax expense (126) (142) (219)
Nonoperating income 62 20 (3)
-------------------------------------
Net income $ 199 $ 191 $ 238
-------------------------------------
Capital Expenditures:
Transmission & distribution $ 201 $ 173 $ 147
Electric Generation 9 18 14
Natural Gas 35 36 36
-------------------------------------
Total $ 245 $ 227 $ 197
-------------------------------------

- -----------------------------------------------------------------------
At December 31, or for
the year then ended
(Dollars in millions) 1999 1998 1997
- -----------------------------------------------------------------------
Assets:
Transmission & distribution $ 2,563 $ 2,518 $ 2,257
Electric Generation 146 685 1,051
Natural Gas 539 553 592
All other 1,118 501 754
-------------------------------------
Total $ 4,366 $ 4,257 $ 4,654
-------------------------------------
Geographic Information:
Long-lived assets
United States $ 2,157 $ 2,300 $ 2,359
-------------------------------------
Operating Revenues:
United States $ 2,207 $ 2,249 $ 2,159
Mexico -- -- 8
-------------------------------------
Total $ 2,207 $ 2,249 $ 2,167
- -----------------------------------------------------------------------

NOTE 14: QUARTERLY FINANCIAL DATA (UNAUDITED)

<TABLE>
<CAPTION>
Quarter ended
-----------------------------------------------------
Dollars in millions March 31 June 30 September 30 December 31
- ----------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1999
Operating revenues $ 461 $ 740 $ 520 $ 486
Operating expenses 390 673 438 425
---------------------------------------------------
Operating income $ 71 $ 67 $ 82 $ 61
---------------------------------------------------
Net income $ 55 $ 47 $ 61 $ 36
Dividends on preferred stock 2 1 2 1
---------------------------------------------------
Net income applicable
to common shares $ 53 $ 46 $ 59 $ 35
===================================================
1998
Operating revenues $ 606 $ 569 $ 563 $ 511
Operating expenses 529 524 475 435
---------------------------------------------------
Operating income $ 77 $ 45 $ 88 $ 76
---------------------------------------------------
Net income $ 50 $ 27 $ 64 $ 50
Dividends on preferred stock 2 1 2 1
---------------------------------------------------
Net income applicable
to common shares $ 48 $ 26 $ 62 $ 49
===================================================
</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 2000 annual meeting of
shareholders. The information required on the Company's executive
officers is set forth below.

EXECUTIVE OFFICERS OF THE REGISTRANT

Name Age* Positions
- -------------------------------------------------------------------
Warren I. Mitchell 62 Chairman

Edwin A. Guiles 50 President and Chief Financial
Officer

Gary D. Cotton 59 Senior Vice President - Fuels &
Power Operations

Steven D. Davis 43 Vice President - Distribution
Operations, and Corporate
Secretary

Pamela J. Fair 41 Vice President - Marketing &
Customer Services

* As of December 31, 1999.

Except for Mr. Davis, each Executive Officer has been an officer of
Sempra Energy or one of its subsidiaries for more than five years.

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 2000 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 2000 annual meeting of shareholders.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

None.

PART IV

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

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

1. Financial statements
Page in
This Report

Independent Auditors' Report . . . . . . . . . . . . . .30

Statements of Consolidated Income for the years
ended December 31, 1999, 1998 and 1997 . . . . . . . .31

Consolidated Balance Sheets at December 31,
1999 and 1998. . . . . . . . . . . . . . . . . . . . .32

Statements of Consolidated Cash Flows for the
years ended December 31, 1999, 1998 and 1997 . . . . .34

Statements of Consolidated Changes in
Shareholders' Equity for the years ended
December 31, 1999, 1998 and 1997 . . . . . . . . . . .36

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

2. Financial statement schedules

Schedules for which provision is made in Regulation S-X are not
required under the instructions contained therein or are
inapplicable.

3. Exhibits

See Exhibit Index on page 65 of this report.

(b) Reports on Form 8-K

There were no reports on Form 8-K filed after September 30, 1999.

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 7, 2000

Principal Financial Officer:
Edwin A. Guiles
President,
Chief Financial Officer /s/ Edwin A.Guiles March 7, 2000

Principal Accounting Officer:
Edwin A. Guiles
President,
Chief Financial Officer /s/ Edwin A.Guiles March 7, 2000

Directors:
Warren I. Mitchell
Chairman /s/ Warren I. Mitchell March 7, 2000

Hyla H. Bertea,
Director /s/Hyla H. Bertea March 7, 2000

Ann L. Burr,
Director /s/Ann L. Burr March 7, 2000

Herbert L. Carter,
Director /s/Herbert L. Carter March 7, 2000

Richard A. Collato,
Director /s/Herbert L. Carter March 7, 2000

Daniel W. Derbes,
Director /s/Herbert L. Carter March 7, 2000

Wilford D. Godbold, Jr.,
Director /s/Wilford. D. Godbold, Jr. March 7, 2000

Robert H. Goldsmith,
Director /s/Robert H. Goldsmith March 7, 2000

William D. Jones,
Director /s/William D. Jones March 7, 2000

Ignacio E. Lozano, Jr.,
Director /s/Ignacio E. Lozano, Jr., March 7, 2000

Ralph R. Ocampo,
Director /s/Ralph R. Ocampo March 7, 2000

William G. Ouchi,
Director /s/William G. Ouchi March 7, 2000

Richard J. Stegemeier,
Director /s/Richard J. Stegemeier March 7, 2000

Thomas C. Stickel,
Director /s/Thomas C. Stickel March 7, 2000

Diana L. Walker,
Director /s/Diana L. Walker March 7, 2000

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.
(1998 SDG&E Form 10-K Exhibit 3.01).

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

Financing

10.08 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).

10.09 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).

10.10 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).

10.11 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).

10.12 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).

10.13 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).

10.14 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).

10.15 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).

10.16 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).

10.17 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).

10.18 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

10.19 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).

10.20 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).

10.21 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).

10.22 Amendment No. 1 to the Qualified CPUC Decommissioning Master
Trust Agreement dated September 22, 1994 (see Exhibit 10.21
herein)(1994 SDG&E Form 10-K Exhibit 10.56).

10.23 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 10.21 herein)(1994 SDG&E Form 10-K Exhibit 10.57).

10.24 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 10.21 herein)(1996 Form 10-K Exhibit 10.59).

10.25 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 10.21 herein)(1996 Form 10-K Exhibit 10.60).

10.26 Fifth Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station.
(see Exhibit 10.21 herein)

10.27 Sixth Amendment to the San Diego Gas & Electric Company
Nuclear facilities qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station.
(see Exhibit 10.21 herein)

10.28 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).

10.29 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 10.28 herein)(1996 Form 10-K Exhibit 10.62).

10.30 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 10.28 herein)(1996 Form 10-K Exhibit 10.63).

10.31 Third 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 10.28 herein)

10.32 Fourth 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 10.28 herein)

10.33 Second Amended San Onofre Operating 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).

10.34 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).

Natural Gas Commodity, Transportation and Storage

10.35 Master Services Contract, Schedule J, Transaction Based Storage
Service Agreement dated April 1, 2000 and expiring March 31, 2001
between San Diego Gas & Electric Company and Southern California Gas
Company.

10.36 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. (1998 10-K Exhibit 10.61)

10. 37 Master Services Contract (Intrastate Transmission Service ),dated
July 1, 1998 and expiring July 1, 2000 between San Diego Gas & Electric
Company and Southern California Gas Company. (1998 10-K Exhibit 10.64)

10.38 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).

10.39 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).

10.40 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

10.41 Lease agreement dated as of March 25, 1992 with CarrAmerica
Development and Construction as lessor of an office
complex at Century Park (1994 SDG&E Form 10-K Exhibit 10.70).

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, 1999, 1998, 1997, 1996 and 1995.

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, 1999.

GLOSSARY

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

AFUDC Allowance for Funds Used During
Construction

BCAP Biennial Cost Allocation Proceeding

Bcf Billion Cubic Feet (of natural gas)

CEC California Energy Commission

CPUC California Public Utilities Commission

CTC Competition Transition Charge

DOE Department of Energy

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

IDBs Industrial Development Bonds

IOUs Investor-Owned Utilities

ISO Independent System Operator

Kwhr Kilowatt Hour

Mw Megawatt

NRC Nuclear Regulatory Commission

ORA Office of Ratepayer Advocates

PBR Performance-Based Regulation

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 Potentially Responsible Party

PX Power Exchange

RWQCB Regional Water Quality Control Board

SDG&E San Diego Gas & Electric Company

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

UEG Utility Electric Generation

VaR Value at Risk

WSPP Western Systems Power Pool

AMENDMENT NO. 5 TO THE Exhibit 10.26
SAN DIEGO GAS & ELECTRIC COMPANY
NUCLEAR FACILITIES QUALIFIED CPUC
DECOMMISSIONING MASTER TRUST
AGREEMENT FOR SAN ONOFRE
NUCLEAR GENERATING STATIONS

This Amendment is entered into as of the __26th day of __December,
1997, by and between San Diego Gas & Electric Company, a corporation
duly organized and existing under the laws of the State of
California, and having its principal office at 101 Ash Street, San
Diego, California 92101-3017 (the "Company"), and State Street Bank
and Trust Company, as Trustee, having its principal office at 1
Enterprise Drive, Quincy, Massachusetts 01171 (the "Trustee").

WHEREAS, in Section 2.12 of the Nuclear Facilities Qualified CPUC
Decommissioning Master Trust Agreement dated June 29, 1992 (the
"Agreement") between the Company and Trustee, the parties
specifically reserve the right to amend the Agreement; and

WHEREAS, the San Diego Gas & Electric Company Nuclear Facilities
Decommissioning Master Trust Committee has authorized the amendment
of the Agreement and the California Public Utilities Commission
filing and review process has been completed with no objections;

NOW, THEREFORE, the parties agree as follows:
1. The recitals set forth above are incorporated herein by this
reference thereto.

2. The Agreement shall be amended by restating Section 2.01 (5) to
read in its entirety:

Interim Disbursements. The estimated costs and schedule for
decommissioning each of the Plants shall be reviewed
periodically and updated when the revenue requirement for
decommissioning is reviewed by the CPUC in the Company's
general rate cases. One year prior to the time
decommissioning of a Plant or Plants is estimated to begin,
the Company shall apply for CPUC approval of the estimated
cost and schedule for decommissioning each Plant. Upon the
occurrence of changed circumstances, the Company may apply to
the CPUC for amendments to the estimated cost and schedule
for decommissioning each plant. Upon approval of the cost
and schedule for decommissioning each Plant or Plants, the
CPUC shall authorize Interim Disbursements from the
applicable Fund to pay Decommissioning Costs. Interim
Disbursements shall be limited to 90% of the forecast of
Decommissioning Costs approved by the CPUC. Final payment
from the applicable Fund for all Decommissioning costs shall
be made pursuant to Section 2.01 (6).

Prior to the issuance of an Interim Disbursement order, the
Trustee is authorized to pay up to 3 percent of the amount
specified in paragraph 50.75 of Title 10 of the Code of Federal
Regulations for decommissioning planning purposes upon receipt
of a Disbursement Certificate or a Withdrawal Certificate
meeting the requirements of Section 2.01 (4) (a)-(c).

4. Except as expressly amended hereby, the Agreement is hereby
restated, confirmed, and ratified in all respects and shall
remain in full force and effect.

5. Capitalized terms used herein and not otherwise defined shall
have the definitions ascribed thereto in the agreement.

IN WITNESS WHEREOF, the Company, the California Public Utilities
Commission, and the Trustee have set their Hands and seals to this
Amendment to the Agreement as of _____________, 1997.

SAN DIEGO GAS & ELECTRIC COMPANY

By:
------------------------------

Title:
---------------------------

Attest:
--------------------------
Title:
--------------------------

Accepted:

STATE STREET BANK AND TRUST COMPANY
By:
-------------------------------

Title:
----------------------------
Attest:
---------------------------

Title:
----------------------------

Approved and Accepted:

CALIFORNIA PUBLIC UTILITIES COMMISSION
By:
-----------------------------------

Title:
--------------------------------

Attest:
-------------------------------

Title:
-------------------------------

AMENDMENT NO. 6 TO THE Exibit 10.27
SAN DIEGO GAS & ELECTRIC COMPANY
NUCLEAR FACILITIES QUALIFIED CPUC
DECOMMISSIONING MASTER TRUST
AGREEMENT FOR SAN ONOFRE
NUCLEAR GENERATING STATIONS

This amendment is entered into as of the __1st_ day of
_October_, 1999, by and between San Diego Gas & Electric Company, a
corporation duly organized and existing under the laws of the State
of California, and having its principal office at 101 Ash Street, San
Diego, California 92101-3017 (the "Company"), and Mellon Bank, N.A.
having its principal office at One Mellon Bank Center, Pittsburgh,
Pennsylvania 15258.

WHEREAS, the Company wishes to appoint Mellon Bank, N.A. as
successor Trustee , and Mellon Bank, N.A. agrees to act as successor
Trustee subject to the terms of the Nuclear Facilities Qualified CPUC
Decommissioning Master Trust Agreement dated June 29, 1992 (the
"Agreement") between the Company and State Street Bank and Trust
Company, as amended;

WHEREAS, in Section 2.12 of the Agreement, the parties
specifically reserve the right to amend the Agreement; and

NOW, THEREFORE, the parties agree as follows:

1. Paragraph (b) of Section 1.04 is amended to read as follows:

"(b) appoints Mellon Bank, N.A. as Trustee of each of the
Funds."

2. The first sentence of the second paragraph of section 4.03
shall be restated to read as follows:

"The attached Exhibit C is effective from the date that
assets are transferred to Mellon Bank, N.A. as successor
Trustee."

3. The first and second sentences of the fourth paragraph of
section 4.03 shall be restated to read as follows:

"The attached Exhibit D is effective as of the date that
assets are transferred to Mellon Bank, N.A. as successor
Trustee."

4. The third sentence of the first paragraph of Section 4.07 is
amended to read as follows:

"The Trustee shall not be responsible for any losses
resulting from the deposit or maintenance of securities or
other property (in accordance with market practice, custom,
or regulation) with any recognized foreign clearing
facility, book-entry system, centralized custodial
depository, or similar organization."

5. Section 4.08 is amended to read as follows:

"The Company shall indemnify and hold harmless the Trustee
from all claims, liabilities, losses, damages and expenses,
including reasonable attorneys' fees and expenses, incurred
by the Trustee in connection with this Agreement, except as
a result of the Trustee's own bad faith, negligence, or
willful misconduct or for any breach of the Agreement that
results from the Trustee's own bad faith, negligence or
willful misconduct."

6. The fifth sentence of Section 5.02 shall be restated as
follows:

"Notification of the issuance of each such authorization
shall be given promptly to the Trustee by the Investment
Manager(s), and the Investment Manager(s) shall cause the
execution of such order to be confirmed in writing to the
Trustee by the broker or dealer. Such notification to the
Trustee from the Investment Manager shall be in writing, by
facsimile transmission, electronic transmission, or any
other method specifically agreed to in writing by the
Committee and the Trustee, provided the Trustee may, in its
discretion, accept oral directions and instructions and may
require confirmation in writing."

7. Paragraph 6.04 shall be deleted.

The following Section 6.08 shall be added:

"6.08 If the Trustee advances cash or securities for any
purpose, or in the event that the Trustee shall incur or be
assessed taxes, interest, charges, expenses, assessments, or
other liabilities in connection with the performance of this
Agreement, except such as may arise from its own negligent
action, negligent failure to act or willful misconduct, any
property at any time held for the Fund or under this
Agreement shall be security therefor and the Trustee shall
be entitled to collect from the Fund sufficient cash for
reimbursement , and if such cash is insufficient, dispose of
the assets of the Fund held under this Agreement to the
extent necessary to obtain reimbursement and to the extent
that such reimbursement is not a violation of any provision
of Section 468A of the Internal Revenue Code. To the extent
the Trustee advances funds to the Fund for disbursements or
to effect the settlement of purchase transactions, the
Trustee to the extent permitted under Section 468A of the
Internal Revenue Code shall be entitled to collect from the
Fund with respect to domestic assets, (i) an amount equal
to what would have been earned on the sums advanced (an
amount approximating the "federal funds" interest rate) or
(ii) with respect to nondomestic assets, the rate applicable
to the appropriate foreign market with respect to non-
domestic assets."

9. The following paragraph shall be added to 7.02:

"Settlements of transactions may be effected in trading and
processing practices customary in the jurisdiction or market
where the transaction occurs. The Company acknowledges that
this may, in certain circumstances, require the delivery of
cash or securities (or other property) without the
concurrent receipt of securities (or other property) or cash
and, in such circumstances, the Company shall have sole
responsibility for nonreceipt of payment (or late payment)
by the counterparty."

10. The following 8.13 shall be added:

"8.13 Notwithstanding anything in this Agreement to the
contrary contained herein, the Trustee shall not be
responsible or liable for its failure to perform under this
Agreement or for any losses to the Account resulting from
any event beyond the reasonable control of the Trustee its
agents or subcustodians, including but not limited to
nationalization, strikes, expropriation, devaluation,
seizure, or similar action by any governmental authority, de
facto or de jure; or enactment, promulgation, imposition or
enforcement by any such governmental authority of currency
restrictions, exchange controls, levies or other charges
affecting the Account's property; or the breakdown, failure
or malfunction of any utilities or telecommunications
systems; or any order or regulation of any banking or
securities industry including changes in market rules and
market conditions affecting the execution or settlement of
transactions; or acts of war, terrorism, insurrection or
revolution; or acts of God; or any other similar event.
This Section shall survive the termination of this
Agreement."

11. The following Section 8.14 shall be added:

"8.14 Each Party hereby represents and warrants to the
other that it has full authority to enter into this
Agreement upon the terms and conditions hereof and that the
individual executing this Agreement on its behalf has the
requisite authority to bind that Party."

IN WITNESS WHEREOF, the Parties have set their Hands and seals
to this Amendment to the Agreement as of the date and year
first written above.

CALIFORNIA PUBLIC UTILITIES
COMMISSION

By:
---------------------------
Name:
-------------------------
Title:
-----------------------

SAN DIEGO GAS &
ELECTRIC COMPANY

By:
---------------------------
Name:
-------------------------
Title
------------------------

MELLON BANK, N.A.

By:
---------------------------
Name:
-------------------------
Title:
------------------------

02/26/99:baker\agreemen\sandiego.doc

MELLON BANK, N.A.
------------------
MASTER TRUST SERVICES FEE SCHEDULE
----------------------------------
FOR
---
QUALIFIED
---------
SAN DIEGO GAS & ELECTRIC N.D.T.
-------------------------------

Pro Forma

TRUST/CUSTODY CHARGES, PORTFOLIO ADMINISTRATION, PORTFOLIO ACTIVITY
- -------------------------------------------------------------------

Fixed Income:

SGE3 Brown Brothers $ 79,637,000 *1.50 bpts $ 11,946
SGE7 NISA $ 123,891,000 *1.50 bpts 18,584

Domestic Equity:

SGE5 SSGA R3000 154,102,000 *1.50 bpts 23,115

International Equity:

SGE6 SSGA EAFE 44,824,000 *7.50 bpts 33,618
--------

$ 87,303

PERFORMANCE MEASUREMENT
- -----------------------

Customized Benchmarks $ 750

OUT-OF-POCKET EXPENSES $ 1,000
- ----------------------

TRUST SERVICES $ 2,000
- -------------- --------

TOTAL: $ 91,053
--------

Exhibit C

MELLON BANK, N.A.
------------------
MASTER TRUST SERVICES FEE SCHEDULE
----------------------------------
FOR
---
SAN DIEGO GAS & ELECTRIC N.D.T.
-------------------------------

TRUST/CUSTODY CHARGES, PORTFOLIO ADMINISTRATION, PORTFOLIO ACTIVITY
- -------------------------------------------------------------------

Domestic Asset Fee (Active):
1.5 basis points on Market Value of Assets

International Asset Fee (Active):
7.5 basis points on Market Value of Assets

PERFORMANCE MEASUREMENT
- -----------------------

Includes Basic Return Calculation, Historical data download, Universe
Comparison and Commingled Funds.

Customized Benchmarks/Universes: $250 per benchmark
BARRA, Vestek, etc.: $250 per portfolio
Attribution: $500 per portfolio
Trading Cost Analysis: $250 per portfolio
CMS BondEdge: Pass Through
TUCS: $750 per portfolio/Minimum $7,500
Look Through Analytics: $500

ON-LINE SERVICES
- ----------------

Includes Terminal Charge, Communication software, CPU connect time.

Executive Workbench: Client Reporting
First User Free of Charge
Performance Report Generator
Analytics Report Generator
Accounting Report Generator
Investment Monitor

OUT-OF-POCKET EXPENSES
- ----------------------

Wire Transfer: $10 per transfer out charge
Courier Service: Pass Through
Telex Charges: Pass Through
Computer Processing: Pass Through
Staff Training: Included
Stamp Duty: Pass Through
Registration: Pass Through

SAN DIEGO GAS & ELECTRIC N.D.T.
FEE SCHEDULE
PAGE 2 OF 2

OUT-OF-POCKET EXPENSES (Cont.)
- ------------------------------

We will pass through to the client any out-of-pocket expenses
including, but not limited to, postage, courier expense, registration
fees, stamp duties, telex charges, custom reporting or custom
programming, internal/external tax, legal or consulting costs and
proxy voting expenses.

TRUST SERVICES
- --------------

Cash Sweep Fee: 12 basis points (Annually)
Tax Reporting: $125 per hour
Tax Return Preparation: $400 per filing/per year

BENEFIT PAYMENT SERVICES
- ------------------------

Non-periodic $6.00 per check

MISCELLANEOUS
- -------------

*All costs associated with the asset conversion will be waived.
*This fee assumes Mellon Trust is the sole foreign exchange
dealer.
*This fee assumes that all investment portfolios are valued on
a monthly basis.
*Mellon Trust bills clients on a monthly basis via a direct
account deduction.
*Fee Schedule is guaranteed for five (5) years.
*We reserve the right to amend our fees if the service
requirements change in a way that materially affects our
responsibilities or costs. Support of other derivative
investment strategies or special processing requirements
(e.g. external cash sweep, etc.) may result in additional
fees.
(Note: Fees will not be amended prior to the notification and
consent of the company.)

Exhibit D

MELLON BANK, N.A.
------------------
INVESTMENT MANAGEMENT FEE SCHEDULE
----------------------------------
FOR
---
SAN DIEGO GAS & ELECTRIC N.D.T.
-------------------------------

50 Basis points for the first $ 50,000,000
40 Basis points for the next $150,000,000
30 Basis points thereafter

AMENDMENT NO. 3 TO THE Exhibit 10.31
SAN DIEGO GAS & ELECTRIC COMPANY
NUCLEAR FACILITIES NON-QUALIFIED CPUC
DECOMMISSIONING MASTER TRUST
AGREEMENT FOR SAN ONOFRE
NUCLEAR GENERATING STATIONS

This Amendment is entered into as of the _26th day of __December,
1997, by and between San Diego Gas & Electric Company, a corporation
duly organized and existing under the laws of the State of
California, and having its principal office at 101 Ash Street, San
Diego, California 92101-3017 (the "Company"), and State Street Bank
and Trust Company, as Trustee, having its principal office at 1
Enterprise Drive, Quincy, Massachusetts 01171 (the "Trustee").

WHEREAS, in Section 2.12 of the Nuclear Facilities Non-Qualified CPUC
Decommissioning Master Trust Agreement dated June 29, 1992 (the
"Agreement") between the Company and Trustee, the parties
specifically reserve the right to amend the Agreement; and

NOW, THEREFORE, the parties agree as follows:

1. The recitals set forth above are incorporated herein by this
reference thereto.

2. The Agreement shall be amended by restating Section 2.01 (5) to
read in its entirety:

Prior to the issuance of an Interim Disbursement order, the
Trustee is authorized to pay up to 3 percent of the amount
specified in paragraph 50.75 of Title 10 of the Code of
Federal Regulations for decommissioning planning purposes upon
receipt of a Disbursement Certificate or a Withdrawal
Certificate meeting the requirements of Section 2.01 (4) (a)-(c).

3. Except as expressly amended hereby, the Agreement is hereby
restated, confirmed, and ratified in all respects and shall
remain in full force and effect.

4. Capitalized terms used herein and not otherwise defined shall
have the definitions ascribed thereto in the agreement.

IN WITNESS WHEREOF, the Company, the California Public Utilities
Commission, and the Trustee have set their Hands and seals to this
Amendment to the Agreement as of _____________, 1997.

SAN DIEGO GAS & ELECTRIC COMPANY

By:
----------------------------

Title:
-------------------------

Attest:
------------------------

Title:
------------------------

Accepted:
STATE STREET BANK AND TRUST COMPANY

By:
-------------------------------

Title:
----------------------------

Attest:
---------------------------

Title:
----------------------------

Approved and Accepted:

CALIFORNIA PUBLIC UTILITIES COMMISSION

By:
-------------------------------------

Title:
----------------------------------

Attest:
--------------------------------

Title:
---------------------------------

ATTACHMENT A

Title 10 Code of Federal Regulations
Paragraph 50.82
Before July 29, 1996 Amendment

ATTACHMENT B

Title 10 Code of Federal Regulations
Paragraph 50.82
As Amended July 29, 1996

ATTACHMENT C

Resolution Amending the San Diego Gas & Electric
Company Nuclear Facilities Qualified and Non-Qualified
Decommissioning Master Trust Agreements

AMENDMENT NO. 4 TO THE Exhibit 10.32
SAN DIEGO GAS & ELECTRIC COMPANY
NUCLEAR FACILITIES NON-QUALIFIED CPUC
DECOMMISSIONING MASTER TRUST
AGREEMENT FOR SAN ONOFRE
NUCLEAR GENERATING STATIONS

This amendment is entered into as of the __1st__ day of
_October_, 1999, by and between San Diego Gas & Electric Company, a
corporation duly organized and existing under the laws of the State
of California, and having its principal office at 101 Ash Street, San
Diego, California 92101-3017 (the "Company"), and Mellon Bank,
N.A., having its principal office at One Mellon Bank Center,
Pittsburgh, Pennsylvania 15258.

WHEREAS, the Company wishes to appoint Mellon Bank, N.A. as
successor Trustee , and Mellon Bank, N.A. agrees to act as successor
Trustee subject to the terms of the Nuclear Facilities Non-Qualified
CPUC Decommissioning Master Trust Agreement dated June 29, 1992 (the
"Agreement") between the Company and State Street Bank and Trust
Company, as amended;

WHEREAS, in Section 2.12 of the Agreement, the parties
specifically reserve the right to amend the Agreement; and

NOW, THEREFORE, the parties agree as follows:

1. Paragraph (c) of Section 1.04 is amended to read as follows:

"(c) appoints Mellon Bank, N.A. as Trustee of the Master
Trust and of each of the Funds."

2. The first sentence of the second paragraph of section 4.03
shall be restated to read as follows:

"The attached Exhibit C is effective from the date that
assets are transferred to Mellon Bank, N.A. as successor
Trustee."

3. The first and second sentences of the fourth paragraph of
section 4.03 shall be restated to read as follows:

"The attached Exhibit D is effective as of the date that
assets are transferred to Mellon Bank, N.A. as successor
Trustee."

4. The third sentence of the first paragraph of Section 4.07 is
amended to read as follows:

5. Section 4.08 is amended to read as follows:

6. The fifth sentence of Section 5.02 shall be restated as
follows:

7. Paragraph 6.04 shall be deleted.

8. The following Section 6.08 shall be added:

"6.08 If the Trustee advances cash or securities for any
purpose, or in the event that the Trustee shall incur or be
assessed taxes, interest, charges, expenses, assessments, or
other liabilities in connection with the performance of this
Agreement, except such as may arise from its own negligent
action, negligent failure to act or willful misconduct, any
property at any time held for the Fund or under this
Agreement shall be security therefor and the Trustee shall
be entitled to collect from the Fund sufficient cash for
reimbursement , and if such cash is insufficient, dispose of
the assets of the Fund held under this Agreement to the
extent necessary to obtain reimbursement and to the extent
that such reimbursement is not a violation of any provision
of Section 468A of the Internal Revenue Service. To the
extent the Trustee advances funds to the Fund for
disbursements or to effect the settlement of purchase
transactions, the Trustee shall be entitled to collect from
the Fund with respect to domestic assets, (i) an amount
equal to what would have been earned on the sums advanced
(an amount approximating the "federal funds" interest rate)
or (ii) with respect to nondomestic assets, the rate
applicable to the appropriate foreign market with respect to
non-domestic assets."

9. The following paragraph shall be added to 7.02:

10. The following 8.13 shall be added:

"8.13 Notwithstanding anything in this Agreement to the
contrary contained herein, the Trustee shall not be
responsible or liable for its failure to perform under this
Agreement or for any losses to the Account resulting from
any event beyond the reasonable control of the Trustee its
agents or subcustodians, including but not limited to
nationalization, strikes, expropriation, devaluation,
seizure, or similar action by any governmental authority, de
facto or de jure; or enactment, promulgation, imposition or
enforcement by any such governmental authority of currency
restrictions, exchange controls, levies or other charges
affecting the Account's property; or the breakdown, failure
or malfunction of any utilities or telecommunications
systems; or any order or regulation of any banking or
securities industry including changes in market rules and
market conditions affecting the execution or settlement of
transactions; or acts of war, terrorism, insurrection or
revolution; or acts of God; or any other similar event. This
Section shall survive the termination of this Agreement."

11. The following Section 8.14 shall be added:

"8.14 Each Party hereby represents and warrants to the
others that it has full authority to enter into this
Agreement upon the terms and conditions hereof and that the
individual executing this Agreement on its behalf has the
requisite authority to bind that Party."

IN WITNESS WHEREOF, the Parties have each set their Hands and
Seals to this Amendment to the Agreement as of the date and
year first written above.

CALIFORNIA PUBLIC UTILITIES
COMMISSION

By:
---------------------------
Name:
-------------------------
Title:
-------------------------

SAN DIEGO GAS &
ELECTRIC COMPANY

By:
--------------------------
Name:
-------------------------
Title:
------------------------

MELLON BANK, N.A.

By:
--------------------------
Name:
-------------------------
Title:
-----------------------

MELLON BANK, N.A.
------------------
MASTER TRUST SERVICES FEE SCHEDULE
----------------------------------
FOR
---
NON-QUALIFIED
--------------
SAN DIEGO GAS & ELECTRIC N.D.T.
-------------------------------

Pro Forma

TRUST/CUSTODY CHARGES, PORTFOLIO ADMINISTRATION, PORTFOLIO ACTIVITY
- -------------------------------------------------------------------

Fixed Income:

SGE2 Brown Brothers $ 36,360,000 *1.50 bpts $ 5,454

Domestic Equity:

SGE1 SSGA R3000 55,386,000 *1.50 bpts 8,308
--------
$13,742

PERFORMANCE MEASUREMENT
- -----------------------

Customized Benchmarks $ 250

OUT-OF-POCKET EXPENSES $ 1,000
- ----------------------

TRUST SERVICES $ 2,000
- -------------- ---------

TOTAL: $ 16,992
---------

Exhibit C

MELLON BANK, N.A.
------------------
MASTER TRUST SERVICES FEE SCHEDULE
----------------------------------
FOR
---
SAN DIEGO GAS & ELECTRIC N.D.T.
-------------------------------

TRUST/CUSTODY CHARGES, PORTFOLIO ADMINISTRATION, PORTFOLIO ACTIVITY
- -------------------------------------------------------------------

Domestic Asset Fee (Active):
1.5 basis points on Market Value of Assets

International Asset Fee (Active):
7.5 basis points on Market Value of Assets

PERFORMANCE MEASUREMENT
- -----------------------

Includes Basic Return Calculation, Historical data download, Universe
Comparison and Commingled Funds.

Customized Benchmarks/Universes:$250 per benchmark
BARRA, Vestek, etc.: $250 per portfolio
Attribution: $500 per portfolio
Trading Cost Analysis: $250 per portfolio
CMS BondEdge: Pass Through
TUCS: $750 per portfolio/Minimum $7,500
Look Through Analytics: $500

ON-LINE SERVICES
- ----------------

Includes Terminal Charge, Communication software, CPU connect time.

Executive Workbench: Client Reporting
First User Free of Charge
Performance Report Generator
Analytics Report Generator
Accounting Report Generator
Investment Monitor

OUT-OF-POCKET EXPENSES
- ----------------------

SAN DIEGO GAS & ELECTRIC N.D.T.
FEE SCHEDULE
PAGE 2 OF 2

OUT-OF-POCKET EXPENSES (Cont.)
- ------------------------------

TRUST SERVICES
- --------------

Cash Sweep Fee: 12 basis points (Annually)
Tax Reporting: $125 per hour
Tax Return Preparation: $400 per filing/per year

BENEFIT PAYMENT SERVICES
- ------------------------

Non-periodic $6.00 per check

MISCELLANEOUS
- -------------

Exhibit D

MELLON BANK, N.A.
-----------------
INVESTMENT MANAGEMENT FEE SCHEDULE
----------------------------------
FOR
---
SAN DIEGO GAS & ELECTRIC N.D.T.
-------------------------------

50 Basis points for the first $ 50,000,000
40 Basis points for the next $150,000,000
30 Basis points thereafter

MASTER SERVICES CONTRACT Exhibit 10.35

SCHEDULE J

TRANSACTION BASED STORAGE SERVICE AGREEMENT

THIS TRANSACTION BASED STORAGE SERVICE AGREEMENT ("Agreement") is
entered into as of the 4th day of October, 1999, by and between
Southern California Gas Company ("Utility") and San Diego Gas &
Electric Company ("Service User") and sets forth the terms and
conditions under which Utility will provide storage services to
Service User. This Agreement shall be attached to and
incorporated as Schedule J to the Master Services Contract ("MSC")
entered into by the parties.

SECTION 1 - STORAGE SERVICES

(a) For the Time Period for Service indicated below (the "Service
Period"), Utility shall provide Service User with the storage
services set forth below. This Agreement and the rights
established herein shall be subject to the terms and conditions of
Utility's Tariff Rate Schedule G-TBS and other applicable Tariff
Rules hereto from time to time (including, without limitation, the
definitions in Utility's Tariff Rule No. 1).

Storage Maximum Firm or Time Period for Service
Services Quantity As-Available ("Service Period")

Inventory 6,000,000 (Dth) Firm, 4/1/00 to 3/31/01
Injection 28,037 (Dth/day) Firm 4/1/00 to 10/31/00
Withdrawal 225,000, (Dth/day) Firm 11/1/00 to 3/31/01

(b) All gas to be stored under this Agreement must be delivered
by Service User to Utility system at the California border during
the period from April 1, 2000 to October 31, 2000, subject,
however, to Utility system constraints. Withdrawals must be
completed by March 31, 2001 .

(c) If storage injection and withdrawal services are offered
hereunder on an "as-available" basis, such services may be
temporarily restricted in accordance with Utility Tariff Rule
23.C.1.(4), Utility Tariff Rule 30.F.2 and G, and G-IMB Special
Conditions 3.

(d) Upon Service User's request for withdrawal, Utility will re-
deliver all gas stored by Service User under this Agreement at the
California border or other mutually agreed upon locations.

(e) Other: Service User has multiple cycling rights.

SECTION 2 - RESERVATION AND STORAGE CHARGES

Service User agrees to pay to Utility the following charges:
Variable Storage Charges
Storage Quantity Unit Reservation In-Kind O&M Injection
Services (Dth) Charges Fuel or Withdrawal

Inventory 6,000,000 (Dth) 0.26 $/(Dth)
Injection 28,037 (Dth/day) 0.10545 $/(Dth) 2.44% 0.0302$/(Dth)
Withdrawal 225,000 (Dth/day) 13.295, $/(Dth/day) 0.0234$/(Dth)

Other charges: The inventory, injection, and withdrawal
reservation charges are adjusted effective April 1, 1999 with
their percentage change equal to the percentage change of the
Coinsumer Price Index - All Urban Consumbers ("CPI") for
September as published by the Bureau of Labor Statistics of the
United States Department of Labor in December. The percentage
change is detemined by subtracting the previous Septmeber CPI from
the latest September CPI and dividing the result by the previous
September CPI. Injection variable charges (in-kind and O&M) apply
april through November. Withdrawal variable chargesm (O&M) apply
November through March. Variable charges are set by the G-TBS
tariff.

SECTION 3 - TRANSMISSION CHARGES

Service User agrees to pay Utility all applicable transportation
charges incurred to move gas to Utility system, including the
Wheeler Ridge access fee, if applicable.

Other transportation charges and conditions: All gas delivered
for injection (less in-kind fuel) shall be assessed a transmission
charge of $0.567 per deatherm and all gas withdrawn shall receive
a credit of $0.567 per decatherm. The transmission charge and
credit shall also apply to gas injected or withdrawn through
imbalance trading or through a transfer with another storage
account.

SECTION 4 - BILLING AND PAYMENT

(a) All reservation charges shall be billed by Utility and paid
by Service User in equal monthly installments over the Service
Period of this Agreement. Provided, however, that if Service User
is not an end-use customer of Utility, 25% of the reservation
charges shall be paid to Utility prior to the commencement of the
Service Period and the balance shall be billed and paid in equal
monthly installments over the Service Period. All other charges
shall be billed and paid as the applicable services are provided.

(b) All bills shall be timely paid. In addition to any remedies
provided under Utility's Tariff Rate Schedules and Tariff Rules,
in the event that Service User fails to timely pay any amounts due
hereunder and such amounts are not paid in full within seven (7)
days following notice by Utility that such payment is in arrears,
Utility may, without any additional notice, immediately suspend
service hereunder until Service User pays all amounts due.

(c) In the event of a billing dispute, the bill must be paid in
full by Service User pending resolution of the dispute. Such
payment shall not be deemed a waiver of Service User's right to a
refund. All bills shall be sent to Service User as specified
below in Section 5 (a).

SECTION 5 - MISCELLANEOUS

(a) Notices - All notices and requests under this Agreement shall
be deemed to have been duly given if sent by facsimile (fax)
properly addressed, as with confirming original copy thereof being
sent by postage prepaid, certified mail properly addressed, as
following:

SERVICE USER UTILITY
Operating Matters
Contact Name: Contact Name:
Lonnie Mansi Gas Transactions Hotline
Contact Title: Contact Title:
Natural Gas Scheduler Gas Transactions & Operations
Fax No.: (619) 650-6192 Fax No.: (213) 244-8281
Telephone: (619) 650-6169 Telephone: (213) 244-3900

Billing Matters
Contact Name: Contact Name:,
Mike G. Strong Susana Santa Maria
Contact Title: Contact Title:
Manger, Entergy Restructuring Billing Analyst
& Entergy Accounting
Fax No.: (619) 650-6192 Fax No.: (213) 244-4337
Telephone: (619) 650-6154 Telephone: (213) 244-8449

Contract Matters
Contact Name: Contact Name:
Carl Funke Gwoon Tom
Contact Title: Contact Title:
Sr. Energy Administrator Storage Products Manager
Fax No.: (619) 650-6170 Fax No.: (213) 244-3692
Telephone: (619) 650-6192 Telephone: (213) 244-8645

Either party may change its designation set forth above by giving
the other party at least seven (7) days prior written notice.

(b) Governing Law - This Agreement shall be construed in
accordance with the laws of the State of California and the
orders, rules and regulations of the Public Utilities Commission
of the State of California in effect from time to time.

(c) Credit Worthiness - From time to time, as is deemed
necessary, Utility may request that Service User furnish Utility
with all relevant information or data to establish Service User's
credit worthiness, including, without limitation, financial
statements of Service User which are audited or otherwise attested
to Utility's satisfaction. Following review of such information,
Utility may require that Service User supply additional assurance
as may be necessary to establish Service User's ongoing financial
ability to perform under this Agreement during the Term,
including, without limitation, contractual guarantees or financial
instruments such as letters of credit.

(d) Limited Storage Liability - Utility shall not be responsible
for any loss of gas in storage, including, without limitation,
losses due to the inherent qualities of gas (including leakage and
migration) or due to physical or legal inability to withdraw gas
from storage, unless such loss is caused by failure of Utility to
exercise the ordinary care and diligence required by law. In the
event of any such loss, the portion of such loss which is
attributable to Service User shall be determined based on Service
User's pro rata share of the total recoverable working gas
inventory in Utility's storage facilities at the time of the loss.

(e) Incorporated Provisions - The provisions of Section 6 of the
MSC are incorporated by reference herein as if set forth in full
herein, except to the extent such Section 6 is superseded by
Utility's Tariff Rule 4.

IN WITNESS WHEREOF, the authorized representatives of the parties
have executed two (2) duplicate original copies of this Agreement
as of the date first written above.

SAN DIEGO GAS & ELECTRIC SOUTHERN CALIFORNIA GAS COMPANY

By By

Title: Title:

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

1995 1996 1997 1998 1999
-------- -------- -------- --------- ---------
<S> <C> <C> <C> <C> <C>
Fixed Charges and Preferred
Stock Dividends:

Interest:
Long-Term Debt $ 82 $ 76 $ 69 $ 55 $ 49
Rate Reduction Bonds -- -- -- 41 35
Short-Term Debt & Other 18 13 14 14 40
Amortization of Debt
Discount and Expense,
Less Premium 5 5 5 8 7
Interest Portion of
Annual Rentals 10 8 10 7 5
-------- -------- ------- --------- ----------
Total Fixed
Charges 115 102 98 125 136
-------- -------- -------- --------- ----------
Preferred Dividend
Requirements 8 6 6 6 6
Ratio of Income Before
Tax to Net Income 1.78991 1.88864 1.91993 1.73993 1.63317
-------- -------- -------- --------- ----------
Preferred Dividends
for Purpose of Ratio 14 13 13 11 10
-------- -------- -------- --------- ----------
Total Fixed Charges
and Preferred Stock
Dividends For
Purpose of Ratio $129 $115 $111 $136 $146
======== ======== ======== ========= =========
Earnings:

Net Income (before
preferred dividend
requirements) $219 $222 $238 $191 $199
Add:
Fixed charges
(from above) 115 102 98 125 136
Less: Fixed charges
capitalized 2 1 2 1 1
Taxes on Income 173 198 219 141 126
-------- -------- -------- --------- ----------
Total Earnings for
Purpose of Ratio $505 $521 $553 $456 $460
======== ======== ======== ========= ==========
Ratio of Earnings
to Combined Fixed
Charges and Preferred
Stock Dividends 3.92 4.54 5.00 3.36 3.15
======== ======== ======== ========= ==========

</TABLE>

EXHIBIT 21.01

SAN DIEGO GAS & ELECTRIC COMPANY
Schedule of Subsidiaries at December 31, 1999

Subsidiary State of Incorporation
- ---------- ----------------------

SDG&E Funding LLC Delaware

EXHIBIT 23.01

INDEPENDENT AUDITORS' CONSENT

We consent to the incorporation by reference in Registration
Statement Nos. 33-45599, 33-52834, and 33-49837 of San Diego Gas &
Electric Company on Forms S-3 of our report dated February 4, 2000,
appearing in this Annual Report on Form 10-K of San Diego Gas &
Electric Company for the year ended December 31, 1999.

/s/ DELOITTE & TOUCHE LLP

San Diego, California
March 28, 2000

<ARTICLE> UT
<LEGEND> THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION
EXTRACTED FROM THE CONDENSED STATEMENT OF CONSOLIDATED INCOME,
BALANCE SHEET AND CASH FLOWS AND IS QUALIFIED IN ITS ENTIRETY
BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
<CIK> 0000086521
<NAME> SAN DIEGO GAS & ELECTRIC COMPANY
<MULTIPLIER> 1,000,000

<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,157
<OTHER-PROPERTY-AND-INVEST> 559
<TOTAL-CURRENT-ASSETS> 843
<TOTAL-DEFERRED-CHARGES> 385
<OTHER-ASSETS> 422
<TOTAL-ASSETS> 4,366
<COMMON> 857
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 460
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,314
25
79
<LONG-TERM-DEBT-NET> 1,397
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 66
0
<CAPITAL-LEASE-OBLIGATIONS> 21
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,464
<TOT-CAPITALIZATION-AND-LIAB> 4,366
<GROSS-OPERATING-REVENUE> 2,207
<INCOME-TAX-EXPENSE> 102
<OTHER-OPERATING-EXPENSES> 1,824
<TOTAL-OPERATING-EXPENSES> 1,926
<OPERATING-INCOME-LOSS> 281
<OTHER-INCOME-NET> 38
<INCOME-BEFORE-INTEREST-EXPEN> 319
<TOTAL-INTEREST-EXPENSE> 120
<NET-INCOME> 199
6
<EARNINGS-AVAILABLE-FOR-COMM> 193
<COMMON-STOCK-DIVIDENDS> 0
<TOTAL-INTEREST-ON-BONDS> 84
<CASH-FLOW-OPERATIONS> 520
<EPS-BASIC> 0
<EPS-DILUTED> 0

</TABLE>