Management's Discussion and Analysis of Financial Condition 
and Results of Operations  --  Enova Corporation and SDG&E 

Background
On January 1, 1996, Enova Corporation (referred to herein as Enova, which 
includes the parent and its wholly owned subsidiaries) became the parent of San 
Diego Gas & Electric. SDG&E's outstanding common stock was converted on a share-
for-share basis into Enova Corporation common stock. SDG&E's debt securities, 
preferred stock and preference stock were unaffected and remain with SDG&E. 
     On October 14, 1996, Enova and Pacific Enterprises, Inc., parent company of
Southern California Gas Company, announced that they have agreed to combine the 
two companies. As a result of the combination, which was unanimously approved by
the boards of directors of both companies, (i) each outstanding share of common 
stock of Enova will be converted into one share of common stock of the new 
company, (ii) each outstanding share of common stock of Pacific Enterprises will
be converted into 1.5038 shares of the new company's common stock and (iii) the 
preferred stock and preference stock of SDG&E, Pacific Enterprises and Southern 
California Gas will remain outstanding. On March 11, 1997, the shareholders of 
Enova and Pacific Enterprises approved the combination. Consummation of the 
combination is conditional upon the approvals of the California Public Utilities
Commission and various other regulatory bodies. Completion of the combination is
expected by the end of 1997. Additional information regarding the proposed 
business combination is described in Note 1 of the notes to consolidated 
financial statements. 
     SDG&E is an operating public utility engaged in the electric and 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 711,000 customers 
in San Diego County and also transports electricity and gas for others. Enova 
has six other subsidiaries (referred to herein as non-utility subsidiaries). 
Enova Financial invests in limited partnerships representing approximately 1,100
affordable-housing properties located throughout the United States. Califia 
leases computer equipment. The investments in Enova Financial and Califia are 
expected to provide income-tax benefits over the next several years. Enova 
Energy is an energy management and consulting firm offering services to 
utilities and large consumers. Enova Technologies is in the business of 
developing new technologies generally related to utilities and energy. On 
January 14, 1997, Enova Energy and Enova Technologies formed a joint venture 
with certain subsidiaries of Pacific Enterprises to provide integrated energy 
and energy-related products and services. The merger agreement with Pacific 
Enterprises provides that if the business combination is not consummated, either
party can terminate the joint venture. Enova International is involved in 
natural gas and power projects outside the United States. Pacific Diversified 
Capital is the parent company of Phase One Development, which is engaged in 
real-estate development. Additional information regarding Enova's subsidiaries 
is described in Notes 2 and 3 of the notes to consolidated financial statements.

Results of Operations
Operating Revenues   Electric revenues increased 6 percent in 1996, primarily 
due to the accelerated recovery of San Onofre Nuclear Generating Station Units 
2 and 3. Additional information about the SONGS recovery and depreciation is 
discussed below and in Note 2 of the notes to consolidated financial statements.
Gas revenues increased 12 percent in 1996, reflecting higher purchased-gas 
prices. Gas revenues decreased 10 percent in 1995, reflecting lower purchased-
gas prices, weather-related lower sales volume and an increase in customers' 
purchases of gas directly from other suppliers (for whom SDG&E provides 
transportation). 

Operating Expenses   Electric fuel expense increased 34 percent in 1996, 
primarily due to increased nuclear and natural gas-fired generation, as well as 
increases in natural gas prices. Electric fuel expense decreased 30 percent in 
1995, primarily due to lower prices for natural gas and the shifting of energy 
supply sources from generation to purchased power as a result of two nuclear 
refuelings during the year. 
     Purchased-power expenses decreased 9 percent in 1996, reflecting the 
availability of lower-cost nuclear generation and decreases in purchased-power 
capacity charges due to a surplus of power from hydro-powered plants in the 
Northwest. 
     Gas purchased for resale increased 34 percent in 1996, primarily due to 
higher natural gas prices. Gas purchased for resale decreased 23 percent in 
1995, primarily due to lower prices for natural gas, and lower sales volumes due
to warmer weather and an increase in customers' purchases of gas directly from 
other suppliers. 
     The changes in maintenance expenses reflect higher power plant emissions 
costs and the nuclear refuelings in 1995. 
     The increase in depreciation and decommissioning expense in 1996 is 
primarily due to the accelerated recovery of SONGS Units 2 and 3.  
     The increase in general and administrative expenses in 1996 includes start-
up costs for Enova Energy, Enova Technologies and Enova International, expenses 
related to the proposed merger with Pacific Enterprises, and higher costs for 
customer service. 

Earnings   1996 earnings per common share were $1.98 compared to $1.94 in 1995 
and $1.17 in 1994. 1994 earnings per common share from continuing operations 
were $1.71. The increase in earnings in 1996 is primarily due to demand-side 
management rewards, partially offset by SDG&E's lower authorized return on 
equity. The increase in earnings from continuing operations in 1995 was due to 
numerous offsetting factors, including the 1994 writedowns (described in Note 2 
of the notes to consolidated financial statements), SDG&E's increased authorized
return on equity, and changes in incentive rewards for Performance-Based 
Ratemaking and demand-side management programs. 
     Earnings per share for the quarter ended December 31, 1996, were $0.47, 
compared to $0.50 for the same period in 1995. The decrease in earnings for the 
quarter was due to numerous offsetting factors, including SDG&E's lower 
authorized return on equity, changes in incentive rewards for Performance-Based 
Ratemaking and demand-side management 
programs, and 1995 earnings associated with discontinued operations. 
     Califia and Enova Financial's contributions to earnings for the year were 
$0.19 in 1996, $0.17 in 1995 and $0.15 in 1994. The impact of the remaining 
subsidiaries on earnings was not material. 

Liquidity and Capital Resources
SDG&E's operations continue to be a major source of liquidity. In addition, 
financing needs are met primarily through issuances of short-term and long-term 
debt and of common and preferred stock. These capital resources are expected to 
remain available. Cash requirements include plant construction and other capital
expenditures, non-utility subsidiaries' affordable-housing, leasing and other 
investments, and repayments and retirements of long-term debt. In addition to 
changes described elsewhere, major changes in cash flows are described below.

Cash Flows from Operating Activities   The major changes in cash flows from 
operations among the three years result from changes in regulatory balancing 
accounts, income taxes, and accounts payable and other current liabilities. The 
changes in cash flows related to 
regulatory balancing accounts were primarily due to changes in prices for 
natural gas. The changes in cash flows related to income taxes were primarily 
due to higher 1996 income tax payments in connection with settlements with the 
Internal Revenue Service on the timing of certain deductions in prior years. The
changes in accounts payable and other current liabilities were primarily due to 
increased natural gas purchases in 1996 and greater demand-side management 
activity in 1995. 
     Quarterly cash dividends of $0.39 per share were declared for the year 
ended December 31, 1996. The dividend payout ratios for the years ended December
31, 1996, 1995, 1994, 1993 and 1992 were 79 percent, 80 percent, 130 percent, 82
percent and 81 percent, respectively. The increase in the payout ratio for the 
year ended December 31, 1994, was due to the writedowns recorded during 1994. 
Additional information regarding the writedowns is provided in Notes 2 and 3 of 
the notes to consolidated financial statements. The payment of future dividends 
is within the discretion of the Enova Board of Directors and is dependent upon 
future business conditions, earnings and other factors. Net cash flows provided 
by operating activities currently are sufficient to maintain the payment of 
dividends at the present level. 

Cash Flows from Financing Activities   Enova did not issue additional stock 
or long-term debt in 1996 except for refinancings and does not plan any 
issuances in 1997 other than 
for refinancings. 
     In May 1996, the CPUC approved SDG&E's request to issue up to $300 million 
of long-term debt to refinance previously issued long-term debt. The decision 
also grants a two-year extension of a prior CPUC authorization to issue $138 
million of long-term debt and $100 million of preferred stock. 
     During 1996, SDG&E issued $130 million of Pollution Control Bonds and $99 
million of Industrial Development Bonds. The funds obtained from these issues 
were used to retire previously issued Pollution Control Bonds and Industrial 
Development Bonds of $129 million and $126 million, respectively. Enova 
Financial and Califia repaid $29 million of long-term debt in 1996 during the 
ordinary course of business. 
     SDG&E's capital structure is one factor that has enabled it to obtain long-
term financing at attractive rates. The following table shows the percentages of
capital represented by the various components. The capital structures are net of
the construction funds held by a trustee in 1992 and 1993. 

                             1992    1993    1994    1995    1996     Goal
-------------------------------------------------------------------------------
Common equity                 47 %    47 %    48 %     49 %    50 %   	46-49 %
Preferred stock                5       4       4        4       4       3-5
Debt and leases               48      49      48       47      46     46-49
-------------------------------------------------------------------------------
Total                        100 %   100 %   100 %    100 %   100 %     100 %
===============================================================================

     The CPUC regulates SDG&E's capital structure, limiting the dividends it may
pay Enova. At December 31, 1996, $67 million of common equity was available for 
future dividends. This restriction is not expected to affect Enova's ability to 
meet its cash obligations. 
     During 1996, Standard & Poor's Ratings Group upgraded SDG&E's long-term-
bond rating from an A+/negative outlook to an A+/positive outlook following the 
passage of California's electric-restructuring law and the announcement of 
Enova's proposed business combination with Pacific Enterprises. Moody's 
Investors Service affirmed SDG&E's long-term-bond rating of A1/stable outlook. 
     The state of California has authorized the issuance of rate-reduction bonds
to finance a portion of transition costs that residential and commercial 
customers will pay from 1998 to 2001. Principal and interest on the bonds will 
be paid through a charge on customers' bills. SDG&E is expected to receive 
approximately $500 million from the proceeds. The bonds are expected to be 
issued by the California Infrastructure and Economic Development Bank in late 
1997. Additional information on the bonds is provided below under "Industry 
Restructuring." 
     In January 1996, SDG&E redeemed its $7.20 series preference stock. The 
entire $15 million issue was called for mandatory redemption at $101 per share. 

Cash Flows from Investing Activities   Cash used in investing activities in 
1996 included SDG&E's construction expenditures and payments to its nuclear 
decommissioning trust. Construction expenditures, excluding nuclear fuel and the
allowance for equity funds used during construction, were $209 million in 1996 
and are estimated to be $240 million in 1997. SDG&E continuously reviews its 
construction, investment and financing programs and revises them in response to 
changes in competition, customer growth, inflation, customer rates, the cost of 
capital, and environmental and regulatory requirements. Among other things, the 
level of expenditures in the next few years will depend heavily on the impacts 
of industry restructuring, and on the timing of expenditures to comply with air-
emission reduction and other environmental requirements. 
     Payments to the nuclear decommissioning trust are expected to continue 
until SONGS is decommissioned, which is not expected to occur before 2013. 
Although Unit 1 was permanently shut down in 1992, it is expected to be 
decommissioned concurrently with Units 2 and 3. 
     Enova's level of non-utility expenditures in the next few years will depend
primarily on the activities of its subsidiaries, including the joint venture 
with Pacific Enterprises. The Mexican Energy Regulatory Commission has awarded 
Enova International and its partners, Pacific Enterprises International and 
Proxima S.A. de C.V., the first natural gas privatization license in Mexico, 
allowing the partnership to build and operate a natural gas distribution system 
in Mexicali, Baja California. The partnership was granted a 30-year license to 
supply natural gas to the region, with exclusive rights  for the first 12 years.
The Mexican company formed by the three partners, Distribuidora de Gas Natural 
de Mexicali, will invest up to $25 million during the first five years of the 
license period. Natural gas service to major commercial and industrial users is 
expected to begin in the third quarter of 1997, and be extended to more than 
25,000 residential customers by the fifth year. Separately, in January 1997, the
partnership submitted a bid to the Mexican Energy Regulatory Commission to build
and operate a natural gas distribution system in Chihuahua, Mexico. The 
commission is expected to announce the winning bidder by April 1, 1997. In 
addition, Enova International is part of two consortia preparing bids to build 
and operate a power plant and natural gas pipeline in Rosarito, Baja California.

Derivatives   The policy of Enova is to use derivative financial instruments 
to reduce exposure to fluctuations in interest rates, foreign currency exchange 
rates and natural gas prices. These financial instruments are with major 
investment firms and expose Enova to market and credit risks. At times, these 
risks may be concentrated with certain counterparties, although counterparty 
non-performance is not anticipated. Enova does not use derivatives for 
speculative purposes. 
     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 
borrowing. These swap and cap 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 income statement as part of interest expense. SDG&E 
would be exposed to interest-rate fluctuations on the underlying debt should 
other parties to the agreement not perform. Such non-performance is not 
anticipated. At December 31, 1996, SDG&E had an agreement for a floating-to-
fixed rate swap associated with $45 million of variable-rate bonds maturing in 
2002. 
     SDG&E's pension fund periodically uses foreign-currency forward contracts 
to reduce its exposure to exchange-rate fluctuations associated with certain 
investments in foreign equity securities. These contracts generally have 
maturities ranging from three to six months. At December 31, 1996, there were no
forward contracts. 
     In October 1996, the Enova Energy and SDG&E boards of directors approved 
the companies' use of energy derivatives in price-risk management activities for
both hedging and trading purposes within certain limitations imposed by company 
policies. The Enova Corporation board has approved the execution of guarantees 
by Enova in support of these activities. In November 1996, SDG&E commenced 
price-risk management activities, on a limited basis, in the area of hedging 
price volatility of natural gas purchases. 
     Additional information on derivative financial instruments is provided in 
Note 8 of the notes to consolidated financial statements. 

Electric Industry Restructuring 
Background   In September 1996, the state of California enacted a law 
restructuring California's electric utility industry (AB 1890). The legislation 
adopts the December 1995 CPUC policy decision restructuring the industry to 
stimulate competition and reduce rates. The new law supersedes the CPUC policy 
decision when in conflict. 
     Beginning in January 1998, customers will be able to buy their electricity 
through a Power Exchange. The Power Exchange will obtain power from Qualifying 
Facilities, nuclear units, "must-run" facilities (those needed to provide 
reactive power, voltage support and transmission stability) and, lastly, from 
the lowest-bidding suppliers. The Power Exchange will serve as a wholesale power
pool, allowing all energy producers to participate competitively. An Independent
System Operator (ISO) will schedule power transactions and access to the 
transmission system. Consumers also may choose either to continue to purchase 
from their local utility under regulated tariffs or to enter into private 
contracts with generators, brokers or others. The local utility will continue to
provide distribution services regardless of which source the consumer chooses. 
These customer choices will, in effect, open up the service territories of all 
California utilities. This will allow Enova to pursue customers outside of 
SDG&E's traditional service territory to provide competitive generation and 
other energy-related services. This will also allow energy producers, brokers 
and others to enter SDG&E's service territory to compete for generation 
customers. 
     In addition, both the CPUC decision and the California legislation provide 
that, within certain limits, utilities will be allowed to recover their stranded
costs incurred for certain above-market CPUC-approved facilities, contracts and 
obligations through the establishment of a nonbypassable competition transition 
charge (CTC). The CPUC's vision is that traditional cost-of-service regulation 
will move toward performance-based regulation. 

Transition Costs   Utilities will be allowed a reasonable opportunity to 
recover their stranded costs through December 31, 2001. Stranded costs such as 
reasonable employee-related costs directly caused by restructuring and 
purchased-power contracts (including those with qualifying facilities) may be 
recovered beyond the 1998-2001 time period. Nuclear decommissioning costs are 
nonbypassable until fully recovered, although not included as part of transition
costs. These decommissioning costs are expected to be recovered through 2013, 
the estimated last year of service for SONGS, but recovery may be accelerated to
the extent possible.
     SDG&E's transition cost application, filed in October 1996, identifies $2 
billion of stranded costs, including generation, purchased power and qualifying 
facilities' contracts, and regulatory assets. These identified transition costs 
are subject to CPUC audit and approval. The amounts include sunk costs, as well 
as ongoing costs the CPUC finds reasonable and necessary to maintain generation 
facilities through December 31, 2001. 
     For purposes of transition cost recovery, overcollections of $98 million 
recorded in the Energy Cost Adjustment Clause and Electric Revenue Adjustment 
Mechanism balancing accounts as of December 31, 1996, will be applied to 
recovery of transition costs once those costs are approved by the CPUC. Outside 
of those exceptions discussed above, stranded costs not recovered by December 
31, 2001, will not be collected from customers. Such costs, if any, would be 
written off as a charge against earnings. AB 1890 clarifies that all existing 
and future consumers must pay CTC, except for a segment of self-generators and 
irrigation districts. SDG&E has very few, if any, of these types of customers 
and does not anticipate a material impact from the exemption. 

Rate-Reduction Bonds   The California legislation provides for a 10-percent 
reduction of residential and small commercial customers' rates beginning in 
January 1998. The utilities intend to finance the rate reduction with the 
proceeds of rate-reduction bonds issued by an agency of the state of California.
SDG&E estimates that it will need $500 million of bond proceeds to finance a 
decrease in rate base sufficient to result in the desired rate reduction. These 
bonds will be repaid over 10 years by SDG&E's residential and small commercial 
customers via a charge on their electric bills. SDG&E and the two other major 
investor-owned utilities in California are in discussions with the Securities 
and Exchange Commission concerning the accounting for the receipt. For financial
reporting purposes, there will be no gain or loss from the issuance of the bonds
or the receipt of the proceeds. SDG&E has not yet determined the details of how 
the proceeds will be used and, therefore, is unable to project the impact on 
liquidity or on results of operations from utilization of the proceeds. 

Rates   The California legislation includes a rate freeze for all customers. 
Until the earlier of March 31, 2002, or when transition cost recovery is 
complete, SDG&E's system average rate will be frozen at June 10, 1996 levels 
(9.64 cents per kwh), except for the impact of natural gas price changes and the
10-percent rate reduction. If gas prices change significantly, SDG&E is 
permitted to seek CPUC authority to increase or decrease rates, but rates cannot
be increased above 9.985 cents per kwh. 
     Late-1996 natural gas prices were more than double early-1996 prices due to
weather-related factors, storage levels, etc., resulting in electric rate 
increases in January and February 1997. The rate changes have increased SDG&E's 
system average rate from 9.64 cents per kwh to the 9.985 cents-per-kwh rate cap.
     Recovery of the transition costs is limited by the rate cap during the 1997
to 2001 transition period. If expenses during a period exceed revenues 
authorized under the rate cap, SDG&E will be unable to recover transition costs 
during that period. SDG&E will be able to recover transition costs, including 
those deferred from earlier periods, in periods in which its other expenses are 
under the cap. Transition costs not recovered during the transition period, if 
any, will be written off after December 31, 2001. In addition, recovery of 
incentive-program rewards such as Performance-Based Ratemaking and demand-side 
management is also limited by reward amounts included in current rates, and the 
possibility exists that these rewards may not be recoverable until after 2001, 
if at all. 

Balancing Accounts   SDG&E has proposed the elimination of 18 electric 
balancing accounts, including ERAM and ECAC, and the retention of the 
catastrophic event and hazardous waste memorandum accounts. The CPUC is 
currently evaluating the issue. 
     Elimination of ERAM and ECAC will result in earnings volatility beginning 
with the first quarter of 1997. Although no significant effect is expected for 
any full year, quarterly earnings will fluctuate significantly, as is already 
the case for many electric utilities. The largest impacts will be reduced first-
quarter earnings and increased third-quarter earnings.

Regulatory Accounting Standards   SDG&E accounts for the economic effects of 
regulation in accordance with Statement of Financial Accounting Standards No. 
71, "Accounting for the Effects of Certain Types of Regulation," under which a 
regulated entity 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 revenues for amounts due 
to customers.
     The SEC has indicated a concern that the California investor-owned 
utilities may not meet the criteria of SFAS No. 71 with respect to their 
electric-generation net regulatory assets. While discussions are ongoing with 
the SEC, if a decision is ultimately made that would result in the 
discontinuation of the application of SFAS No. 71 for electric-generation 
operations, the impact of a writeoff of SDG&E's generation-related net 
regulatory assets would not be material to SDG&E's financial condition, results 
of operations or liquidity.

Performance-Based Ratemaking   The CPUC has affirmed its belief that the new 
competitive environment should be based on policies that encourage efficient 
operation and improved productivity rather than on reasonableness reviews and 
disallowances. On an experimental basis, SDG&E is participating in a PBR process
for base rates, gas procurement, and electric generation and dispatch, beginning
in 1993. SDG&E has applied to extend the gas procurement mechanism. The genera-
tion and dispatch mechanism is in the process of being terminated, possibly to 
be replaced by a new generation mechanism with diminished scope. In addition, 
SDG&E plans to file a proposal for a new distribution PBR mechanism, which has 
been delayed pending further CPUC guidance. Discussions are ongoing.
     Rates for generation services that the ISO determines will be required to 
provide reliable service may remain cost-of-service based. These services may be
provided under a contract with the ISO, which will be terminable when the ISO 
determines it no longer requires them. Regardless of whether these services are 
provided to the ISO under a traditional cost-of-service or PBR-based contract, 
SDG&E expects to recover its costs of production and the cost of having its 
generating units available. 

Federal Restructuring Activities   In April 1996, the Federal Energy 
Regulatory Commission issued a final rule that will require all utilities to 
offer wholesale "open-access" transmission service on a nondiscriminatory basis 
and to share information about available transmission capacity. 
     In November 1996, the FERC approved a proposal by the three California 
investor-owned utilities to create a Power Exchange and Independent System 
Operator to run California's electric transmission facilities. The FERC, which 
has jurisdiction over the exchange, the ISO and interstate transmission, 
accepted the proposal to separate the ISO from the Power Exchange and to charge 
access fees to recover transmission costs and congestion fees to encourage 
efficient use of the system. 
     Several bills on electric industry restructuring were filed in 1996 at the 
federal level. One bill would make states establish rules to let all residences,
businesses and industries choose their own power suppliers by December 15, 2000,
or force states to give way to the FERC to open the local market to competition 
after 2000. Another bill calls for full customer choice by January 1, 1998. This
measure provides that if retail choice is not a reality by that date, the FERC 
will set rates until competition takes effect. A third bill, introduced on the 
last day of the 1996 Congressional session and, therefore, too late for hearings
or debate, would, if reintroduced and enacted as written, supersede state 
regulations and legislations, and prevent utility customers from being charged 
for stranded investments of the utilities. The other bills and similar bills 
introduced in 1997 would mandate recovery of stranded costs or leave the 
recovery to the discretion of each state. 

Natural Gas 
The ongoing restructuring of the natural gas utility industry has allowed 
customers to bypass utilities as suppliers and, to a lesser extent, as 
transporters of natural gas. Currently, non-utility electricity producers and 
other large customers may use a natural gas utility's facilities to transport 
gas purchased from non-utility suppliers. Also, smaller customers may form 
groups to buy natural gas from another supplier. 

Cost of Capital   
In November 1996, the CPUC adopted the agreement between SDG&E and the CPUC's 
Office of Ratepayer Advocates setting SDG&E's authorized rate of return, return 
on equity and capital structure. SDG&E's 1997 return on equity will remain at 
11.60 percent and the overall rate of return will change from 9.37 percent to 
9.35 percent. This establishes the basis for SDG&E's new cost of capital 
mechanism, the Market Indexed Capital Adjustment Mechanism (MICAM), effective 
January 1, 1998, which will automatically reset SDG&E's return annually based on
changes in market interest rates. SDG&E's authorized capital structure remains 
49.75 percent common equity, 44.5 percent long-term debt and 5.75 percent 
preferred stock. 
     During the industry-restructuring transition period, MICAM will apply to 
distribution rate base and the generation rate base not being recovered in CTC. 
After the transition period, MICAM will apply to distribution rate base only. 
Transmission will be regulated by the FERC. 

Resource Planning
Sources of Fuel and Energy   SDG&E's primary sources of fuel and purchased 
power include natural gas from Canada and the Southwest, surplus power from 
other utilities in the Southwest and the Northwest, and uranium from Canada. 
Although short-term natural gas supplies are volatile due to weather and other 
conditions, these sources should provide SDG&E with an adequate supply of low-
cost natural gas. SDG&E is currently involved in litigation concerning its long-
term contracts for natural gas with certain Canadian suppliers. SDG&E has long-
term pipeline capacity commitments related to its contracts for Canadian natural
gas supplies. If the supply of Canadian natural gas to SDG&E is not resumed, 
SDG&E intends to use the capacity in other ways. SDG&E cannot predict the 
outcome of the litigation, but does not expect that an unfavorable outcome would
have a material effect on its financial condition, results of operations or 
liquidity. 

San Onofre Nuclear Generating Station   In January 1996, the CPUC approved 
the accelerated recovery of the existing capital costs of Units 2 and 3. The 
decision allowed SDG&E to recover its remaining investment in the units at a 
lower rate of return over an 8-year period beginning in 1996, rather than over 
the life of the units' license, which extends to 2013. The accelerated recovery 
began in April 1996. At December 31, 1996, approximately $670 million was 
unrecovered. California electric-industry-restructuring legislation requires 
that all generation-related stranded assets, which includes Units 2 and 3, be 
recovered by 2001. The January decision also includes a performance incentive 
plan that encourages continued, efficient operation of the plant. Through Decem-
ber 31, 2003, customers will pay about $0.04 per kilowatt-hour. This pricing 
structure replaces the traditional method of recovering the units' operating 
expenses and capital improvements. This is intended to make the units more 
competitive with other sources. 
     Cracked and dented tubes were found during the latest refueling of Unit 2. 
This delayed the restart of the unit and added to the cost of the refueling. The
problems and the resultant  need to plug a small percentage of the unit's tubes 
will permanently reduce the unit's output and pose the possibility that the 
reactor may be taken out of service prior to 2013. 

Environmental Matters
SDG&E's operations are conducted in accordance with federal, state and local 
environmental laws and regulations governing hazardous wastes, air and water 
quality, land use and solid-waste disposal. SDG&E incurs significant costs to 
operate its facilities in compliance with these laws and regulations, and to 
clean up the environment as a result of prior operations of SDG&E or of others. 
     The costs of compliance with environmental laws and regulations are 
normally recovered in customer rates. However, restructuring of the California 
electric-utility industry (see above) will change the way utility rates are set 
and costs are recovered. SDG&E has proposed the retention of the hazardous waste
memorandum account, which is intended to encompass cleanup costs, including 
those related to generation activities, as described below. Capital costs 
related to environmental regulatory compliance are intended to be included in 
transition costs for recovery through 2001. However, depending on the final 
outcome of industry restructuring and the impact of competition, the costs of 
compliance with future environmental regulations may not be fully recoverable. 
     Capital expenditures to comply with environmental laws and regulations were
$6 million in 1996, $4 million in 1995 and $5 million in 1994, and are expected 
to aggregate $34 million over the next 5 years. These expenditures primarily 
include the estimated cost of retrofitting SDG&E's power plants to reduce air 
emissions. They do not include potential expenditures to comply with water-
discharge requirements for the Encina, South Bay and SONGS power plants, which 
are discussed below. 

Hazardous Wastes   In 1994, the CPUC approved the Hazardous Waste 
Collaborative which allows utilities to recover cleanup costs of hazardous waste
contamination at sites where the utility may have responsibility or liability 
under the law to conduct or participate in any required cleanup. In general, 
utilities are allowed to recover 90 percent of their cleanup costs and any 
related costs of litigation with responsible parties. 
     SDG&E disposes of its hazardous wastes at facilities owned and operated by 
other entities. Operations at these facilities may result in actual or 
threatened risks to the environment or public health. Where the owner or 
operator of such a facility fails to complete any corrective action required by 
regulatory agencies to abate such risks, applicable environmental laws may 
impose an obligation to undertake corrective actions on SDG&E and others who 
disposed of hazardous wastes at the facility. 
     During the early 1900s, SDG&E and its predecessors manufactured gas from 
coal and oil at its Station A facility and at two other, small facilities in 
Escondido and Oceanside. Certain amounts of residual by-products from the gas-
manufacturing process and subsurface hydrocarbon contamination were discovered 
on portions of the Station A site during an environmental assessment, which was 
completed in 1996. The estimate for cleanup of the on-site contamination is in 
the $3 million to $6 million range. SDG&E may be required to assess whether or 
not such contamination extends to off-site locations. Not included in this 
estimate are costs related to a shallow underground tank-like structure found 
under a public street immediately west of Station A. A risk assessment has been 
completed for Station A and SDG&E is completing negotiations for an appropriate 
site-remediation work plan with the County of San Diego's Department of Health. 
     The Escondido facility was remediated during 1990 through 1993 at a cost of
$3 million and a site-closure letter from the Department of Health has been 
received. However, contaminants similar to those on the Escondido site have been
observed on adjacent property. SDG&E plans to assess the nature of and whether 
it has any liability for these adjacent contaminants. Finally, potential 
contaminants resulting from the gas-manufacturing process by-products will be 
assessed at the Oceanside facility, as well as on adjacent property. Sufficient 
information is not currently available to estimate the extent of remediation 
necessary or the amount of cleanup costs for the property adjacent to the 
Escondido and Oceanside facilities or at the Oceanside facility itself. 
     Asbestos was used in the construction of SDG&E's Station B power plant, 
which closed in 1993. Renovation, reconditioning or demolition of the facility 
will require the removal of the asbestos in a manner complying with all 
applicable environmental, health and safety laws. Additionally, reuse of the 
facility may require the removal or cleanup of PCBs, paints containing heavy 
metals, fuel oil or other substances. SDG&E has assessed the extent of any 
possible contamination by these or other hazardous materials at the facility. 
The estimated cost of this removal effort is estimated to be between $4 million
and $5 million. 

Electric and Magnetic Fields (EMF)   In recent property-damage litigation, 
the California Supreme Court agreed with SDG&E and unanimously affirmed the 1995
California Court of Appeal decision that the CPUC has exclusive jurisdiction 
over EMF health and safety issues.  The California Supreme Court also stated 
that scientific evidence is insufficient to conclude that EMFs pose a health 
hazard. Although scientists continue to research the possibility that exposure 
to EMFs causes adverse health effects, to date, science has demonstrated no 
cause-and-effect relationship between adverse health effects and exposure to the
type of EMFs emitted by utilities' power lines and other electrical facilities. 
Some laboratory studies suggest that such exposure creates biological effects, 
but those effects have not been shown to be harmful. The studies that have most 
concerned the public are certain 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 Quality   The San Diego Air Pollution Control District (APCD) regulates 
air quality in San Diego County in conformance with the California and Federal 
Clean Air Acts. California's standards are more restrictive than federal 
standards. 
     During 1996, SDG&E installed equipment on South Bay Unit 1 in order to 
comply with the first tier of nitrogen-oxide emission limits that the APCD 
imposed on electric generating boilers through its Rule 69. Under this rule, 
SDG&E must maintain the total nitrogen-oxide emissions from its entire system 
below a prescribed emissions cap which decreases periodically through 2005. The 
estimated capital costs for compliance with the rule are $60 million. The 
California Air Resources Board has expressed concern that Rule 69 does not meet 
the requirements of the California Clean Air Act and may impose more restrictive
emissions limitations, causing SDG&E's Rule 69 compliance costs to increase. 
     Under a South Coast Air Quality Management District program called RECLAIM,
SDG&E is required to reduce its nitrogen-oxide emission levels of the natural 
gas compressor engines at its Moreno facility by 10 percent a year through 2003.
This will be accomplished through the installation of new emission-monitoring 
equipment, operational changes to take advantage of low-emission engines and 
engine retrofits. The cost of complying with RECLAIM may be as much as $3 
million. 

Water Quality   Wastewater discharge permits issued by the Regional Water 
Quality Control Board (RWQCB) for SDG&E's Encina and South Bay power plants are 
required to enable SDG&E to discharge its cooling water and certain other 
wastewaters into the Pacific Ocean and into San Diego Bay. The continued cooling
and wastewater discharges and, therefore, the necessary permits are 
prerequisites to the continued operation of the power plants as they are 
currently configured. Increasingly stringent cooling-water and waste-water 
discharge limitations may be imposed in the future and SDG&E may be required to 
build additional facilities or modify existing facilities to comply with these 
requirements. Such facilities could include waste-water treatment facilities, 
cooling towers or offshore-discharge pipelines. However, any required 
construction could involve substantial expenditures, and certain plants or units
may be unavailable for electric generation during construction. 
     In 1981, SDG&E submitted a demonstration study in support of its request 
for two exceptions to certain thermal discharge requirements imposed by the 
California Thermal Plan for the Encina power plant. In November 1994, the 
RWQCB issued a new permit, subject to the results of certain additional 
thermal studies to be used in considering SDG&E's exception requests. The 
results of these additional studies will be completed in 1997. If SDG&E's 
exception requests are denied, SDG&E could be required to construct 
off-shore discharge facilities at a cost of $75 million to 
$100 million or to perform mitigation.
     During 1997, in conjunction with its permit requirements to treat 
wastewater at its Encina and South Bay power plants, SDG&E will be evaluating
whether any remediation activities may be required at the power plants. 
In addition, SDG&E will be determining whether remediation is required at 
its Silvergate plant, which was shut down in 1984. Sufficient information 
is not currently available to estimate the costs of any necessary remediation.
     The California Coastal Commission required a study of the offshore impact 
on the marine environment from the cooling-water discharge by SONGS Units 2 and 
3. The study concluded that some environmental damage is caused by the 
discharge. To mitigate the damage, the California Coastal Commission ordered 
Southern California Edison, SDG&E and the cities of Anaheim and Riverside to 
improve the plant's fish-protection system, build a 300-acre artificial reef to 
help restore kelp beds and restore 150 acres of coastal wetlands. SDG&E may be 
required to incur capital costs of up to $30 million to comply with this order. 
The new pricing structure contained in the CPUC's decision regarding accelerated
recovery of SONGS Units 2 and 3 (see "San Onofre Nuclear Generating Station" 
above) accommodates these added mitigation costs. In addition, SDG&E and Edison 
have asked the California Coastal Commission to reconsider and modify this 
mitigation plan to reduce the size of the artificial reef and shorten the 
monitoring period based on new studies that show that the environmental damage 
is much less than anticipated. Discussions are ongoing. 

Wood-Pole Preservatives   Mateel Environmental Justice Foundation agreed to 
the dismissal, without prejudice, of its complaint against Pacific Bell, Pacific
Gas & Electric and two wood-pole manufacturers in April 1996. The complaint 
alleged that utility-pole owners and manufacturers failed to comply with 
Proposition 65 requirements to warn the public that the poles are treated with 
hazardous chemicals known to the state to cause cancer or reproductive harm. 
SDG&E was not a party to the litigation, but had received a copy of the notice 
served by Mateel stating its intent to bring suit against responsible parties 
using such poles and chemicals. 

Information Regarding Forward-Looking Statements 
This Annual Report to Shareholders includes forward-looking statements within 
the definition of Section 27A of the Securities Act of 1933 and Section 21E of 
the Securities Exchange Act of 1934. When used in this "Management's Discussion 
and Analysis of Financial Condition and Results of Operations," the words 
"estimates," "expects," "anticipates," "plans," and "intends," variations of 
such words, and similar expressions are intended to identify forward-looking 
statements that involve risks and uncertainties. 
     Although the Registrants believe that their expectations are based on 
reasonable assumptions, they can give no assurance that those expectations will 
be realized. Important factors that could cause actual results to differ 
materially from those in the forward-looking statements herein include political
developments affecting state and federal regulatory agencies, the pace of 
electric industry deregulation in California and in the United States, the 
existence of or ability to create a market for rate-reduction bonds, the ability
to effect a coordinated and orderly implementation of both state legislation and
the CPUC's restructuring regulations, the consummation and timing of the 
combination of Enova and Pacific Enterprises, international political 
developments, environmental regulations, and the timing and extent of changes in
interest rates and prices for natural gas and electricity.