SAN DIEGO GAS & ELECTRIC CO - 10-Q Quarterly Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2003
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Commission file number 1-3779
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SAN DIEGO GAS & ELECTRIC COMPANY
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(Exact name of registrant as specified in its charter)

California 95-1184800
- ------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

8330 Century Park Court, San Diego, California 92123
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(Address of principal executive offices)
(Zip Code)

(619) 696-2000
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(Registrant's telephone number, including area code)

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 (or for such shorter period
that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days.
Yes X No
----- -----

Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Exchange Act).
Yes X No
----- -----

Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date.

Common stock outstanding: Wholly owned by Enova Corporation

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly 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," "would" and "should" or similar expressions, or discussions of
strategy or of plans are intended to identify forward-looking
statements. Forward-looking statements are not guarantees of
performance. They involve risks, uncertainties and assumptions. Future
results may differ materially from those expressed in these forward-
looking statements.

Forward-looking 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, legislative and
regulatory conditions and developments; actions by the California
Public Utilities Commission, the California Legislature, the Department
of Water Resources, and the Federal Energy Regulatory Commission;
capital market conditions, inflation rates, interest rates and exchange
rates; energy and trading markets, including the timing and extent of
changes in commodity prices; weather conditions and conservation
efforts; war and terrorist attacks; business, regulatory and legal
decisions; the status 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
report and other reports filed by the company from time to time with
the Securities and Exchange Commission.

ITEM 1. FINANCIAL STATEMENTS.

SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED INCOME
(Dollars in millions)

SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED INCOME
(Dollars in millions)

SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)

SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)

SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in millions)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. GENERAL

This Quarterly Report on Form 10-Q is that of San Diego Gas & Electric
Company (SDG&E or the company). SDG&E's common stock is wholly owned by
Enova Corporation (Enova), which is a wholly owned subsidiary of Sempra
Energy, a California-based Fortune 500 holding company. The financial
statements herein are the Consolidated Financial Statements of SDG&E
and its sole subsidiary, SDG&E Funding LLC.

Sempra Energy also indirectly owns all of the common stock of Southern
California Gas Company (SoCalGas). SDG&E and SoCalGas are collectively
referred to herein as "the California Utilities."

The accompanying Consolidated Financial Statements have been prepared
in accordance with the interim-period-reporting requirements of Form
10-Q. Results of operations for interim periods are not necessarily
indicative of results for the entire year. In the opinion of
management, the accompanying statements reflect all adjustments
necessary for a fair presentation. These adjustments are only of a
normal recurring nature. Certain changes in classification have been
made to prior presentations to conform to the current financial
statement presentation.

Information in this Quarterly Report is unaudited and should be read in
conjunction with the Annual Report on Form 10-K for the year ended
December 31, 2002 (Annual Report) and the Quarterly Report on Form 10-Q
for the three months ended March 31, 2003.

The company's significant accounting policies are described in Note 1
of the notes to Consolidated Financial Statements in the Annual Report.
The same accounting policies are followed for interim reporting
purposes.

As described in the notes to Consolidated Financial Statements in the
Annual Report, SDG&E accounts for the economic effects of regulation on
utility operations (excluding generation operations) in accordance with
Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting
for the Effects of Certain Types of Regulation".

COMPREHENSIVE INCOME

The following is a reconciliation of net income to comprehensive
income.

Three months Six months
ended ended
June 30, June 30,
-----------------------------------
(Dollars in millions) 2003 2002 2003 2002
- -------------------------------------------------------------------
Net income $ 42 $ 52 $ 89 $ 107

Minimum pension liability
adjustments -- (1) (6)* (1)

-----------------------------------
Comprehensive income $ 42 $ 51 $ 83 $ 106
- -------------------------------------------------------------------

* This amount does not equal the change in the reported balance of
accumulated other comprehensive income due to rounding.

2. NEW ACCOUNTING STANDARDS

SFAS 143, "Accounting for Asset Retirement Obligations": The adoption
of SFAS 143 on January 1, 2003 resulted in the recording of an addition
of $71 million to utility plant, representing the company's share of
the San Onofre Nuclear Generating Station (SONGS) estimated future
decommissioning costs (as discounted to the present value at the dates
the units began operation), and accumulated depreciation of $41 million
related to the increase to utility plant, for a net increase of $30
million. In addition, the company recorded a corresponding retirement
obligation liability of $309 million (which includes accretion of that
discounted value to December 31, 2002) and a regulatory liability of
$215 million to reflect that SDG&E has collected the funds from its
customers more quickly than SFAS 143 would accrete the retirement
liability and depreciate the asset. These liabilities, less the $494
million recorded as accumulated depreciation prior to January 1, 2003
(which represents amounts collected for future decommissioning costs),
comprise the offsetting $30 million.

On January 1, 2003, the company recorded additional asset retirement
obligations of $10 million associated with the future retirement of a
former power plant.

The change in the asset retirement obligations for the six months ended
June 30, 2003 is as follows (dollars in millions):

Balance as of January 1, 2003 $ --
Adoption of SFAS 143 319
Accretion expense 10
Payments made (7)
------
Balance as of June 30, 2003 $ 322*
======

*A portion of the obligation is included in other current liabilities
on the Consolidated Balance Sheets.

Had SFAS 143 been in effect, the asset retirement obligation liability
would have been $307 million, $330 million, $354 million and $319
million as of January 1, 2000 and December 31, 2000, 2001 and 2002,
respectively.

Except for the items noted above, the company has determined that there
is no other material retirement obligation associated with tangible
long-lived assets.

Implementation of SFAS 143 has had no effect on results of operations
and is not expected to have a significant one in the future.

SFAS 150 "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity": This statement
establishes standards for how an issuer classifies and measures certain
financial instruments with characteristics of both liabilities and
equity. SFAS 150 requires that certain mandatorily redeemable
financial instruments currently classified in the mezzanine section of
the balance sheet be reclassified as liabilities. The company will
adopt SFAS 150 in the third quarter of 2003 by changing its
presentation of $24 million of mandatorily redeemable preferred stock.

3. MATERIAL CONTINGENCIES

ELECTRIC INDUSTRY REGULATION

The restructuring of California's electric utility industry has
significantly affected the company's electric utility operations. The
background of this issue is described in the Annual Report. Subsequent
developments are described herein.

The power crisis of 2000-2001 has caused the California Public
Utilities Commission (CPUC) to adjust its plan for restructuring the
electricity industry. In addition, several California state agencies,
including the CPUC, the Consumer Power and Conservation Financing
Authority, and the California Energy Commission, recently adopted an
Energy Action Plan for California. The plan calls for a continuation of
regulated electricity rates and existing direct access contracts,
increased conservation, more renewable energy, and a stable regulatory
environment that encourages private investment in the state.

Subsequent to the electric capacity shortages of 2000-2001, SDG&E's
service territory has had and continues to have an adequate supply of
electricity. However, various projections of electricity demand in
SDG&E's service territory indicate that, without additional electrical
generation or reductions in electrical usage, beginning in 2005
electricity demand could begin to outstrip available resources. SDG&E's
strategy for meeting this demand is to: (1) reduce power demand through
conservation and efficiency; (2) increase the supply of electricity
from renewable sources, including wind and solar; (3) establish new
transmission lines by 2008 to import more power; and (4) provide new
electric generation by 2005 to meet the expected shortfall. SDG&E has
issued a request for proposals (RFP) to meet the electric capacity
shortfall, estimated at 69 megawatts in 2005 and increasing annually by
100 megawatts. SDG&E is ahead of the interim schedule required by
California legislation in meeting the CPUC's requirement of obtaining
20 percent of its electricity from renewable sources by 2017.

There continues to be legislative and regulatory interest in returning
California's investor-owned utilities(IOUs) to an ownership role for
generation. At present, there is no firm guidance or set of terms and
conditions under which this might take place that would provide
adequate customer and shareholder protections, and SDG&E continues to
state that these items must be in place before it would consider an
ownership position. In anticipation of possible direction on these
matters, SDG&E has required bidders to include both power purchase and
ownership options in their response to the RFP noted above for
additional local generation beginning in 2005.

Several legislative proposals relating to utility regulation have
failed to be enacted by the California Legislature. California Senate
Bill (SB) 429 would have subjected the company and other California
energy-utility holding companies to continuing authority of the CPUC to
enforce any condition placed upon their authorizations to acquire their
California utility subsidiaries, including obligations to give first
priority to the capital requirements of the utilities as determined by
the CPUC to be necessary to meet the utilities' obligations to serve.
It would also require that the CPUC order the holding companies to
infuse into the utility subsidiaries sufficient capital, of any type
deemed necessary by the CPUC, to enable the utilities to fulfill their
service obligations. SB 888 would repeal the provisions of Assembly
Bill (AB) 1890, which enabled electric industry restructuring in
September 1996.

California Governor Davis recently announced that he is seeking a $1-
billion electric rate reduction. SDG&E's portion of this is 13.51
percent or $135 million. This rate reduction will have no effect on
SDG&E's net income and net cash flows because customer savings are
coming from lower charges by the California Department of Water
Resources (DWR), and SDG&E is merely transmitting the electricity from
the DWR to the customers, acting as a conduit for the parties. In
accordance therewith, on July 1, 2003 the DWR submitted to the CPUC a
supplemental determination of its 2003 revenue requirement. The DWR's
supplemental determination contains a $1-billion reduction in its
revenue requirement for 2003. In order to make the corresponding rate
reduction available to ratepayers as soon as possible, and consistent
with the very limited scope of this phase of this proceeding, the
procedural schedule is being expedited. A draft decision is expected by
the end of August 2003, with a final decision by September 2003.

The CPUC has undertaken a proceeding and issued numerous decisions
establishing the framework, rules and processes that would govern
SDG&E's renewed responsibility of procuring electricity for its
customers. These include decisions (1) allocating to the customers of
California's IOUs the power from the long-term contracts entered into
by the DWR, with the DWR retaining the legal and financial
responsibility for the contracts; (2) adopting an Operating Agreement
between SDG&E and the DWR to govern the terms and conditions for
SDG&E's administration of DWR contracts; (3) adopting annual
procurement plans that include securing supplies to satisfy SDG&E's
additional power requirements; (4) consideration of a 20-year resource
plan to assess SDG&E's resource needs, emphasizing the next five years;
and (5) developing the criteria by which the acceptability and recovery
of procurement transactions will be determined, including possible
development of an incentive mechanism for procurement activities.

The DWR's Operating Agreement with SDG&E, approved by the CPUC, governs
SDG&E's relationship with the DWR now that SDG&E has assumed
administration of the allocated DWR contracts. The agreement provides
that SDG&E is acting as a limited agent on behalf of the DWR in
undertaking energy sales and natural gas procurement functions under
the DWR contracts allocated to its customers. Legal and financial risks
associated with these activities will continue to reside with the DWR.
However, in certain limited circumstances involving transactions in
which SDG&E, as DWR's limited agent, is selling DWR surplus energy
pursuant to the terms of the Operating Agreement, SDG&E may be
obligated to provide lines of credit in connection with the allocated
contracts. The risk associated with these lines of credit is considered
to be minimal. On April 17, 2003, SDG&E filed with the CPUC its natural
gas procurement plan related to certain DWR contracts. On July 10,
2003, the CPUC approved SDG&E's natural gas supply plan.

NATURAL GAS INDUSTRY RESTRUCTURING

As discussed in Note 11 of the notes to Consolidated Financial
Statements in the Annual Report, in December 2001 the CPUC issued a
decision related to natural gas industry restructuring, with
implementation anticipated during 2002. During 2002 the California
Utilities filed a proposed implementation schedule and revised tariffs
and rules required for implementation. However, on February 27, 2003,
the CPUC issued a resolution rejecting without prejudice those proposed
tariffs and rules. If the December 2001 decision is implemented, it is
not expected to adversely affect the California Utilities' earnings. A
CPUC decision is expected during 2004.

BORDER PRICE INVESTIGATION

In November 2002, the CPUC instituted an investigation into the
Southern California natural gas market and the price of natural gas
delivered to the California-Arizona (CA-AZ) border during the period of
March 2000 through May 2001. If the investigation determines that the
conduct of any respondent contributed to the natural gas price spikes
at the CA-AZ border during this period, the CPUC may modify the
respondent's applicable natural gas procurement incentive mechanism,
reduce the amount of any shareholder award for the period involved,
and/or order the respondent to issue a refund to ratepayers to offset
the higher rates paid. The California Utilities, included among the
respondents to the investigation, are fully cooperating in the
investigation and believe that the CPUC will ultimately determine that
they were not responsible for the high border prices during this
period. On August 1, 2003, the Administrative Law Judge (ALJ) issued a
revised schedule with hearings scheduled to begin in March 2004 and
with a Commission decision by late 2004.

CPUC INVESTIGATION OF COMPLIANCE WITH AFFILIATE RULES

On February 27, 2003, the CPUC opened an investigation of the business
activities of SDG&E, SoCalGas and Sempra Energy to ensure that they
have complied with relevant statutes and CPUC decisions in the
management, oversight and operations of their companies. The Assigned
Commissioner and ALJ issued a ruling which suspends the procedural
schedule until the CPUC completes an independent audit to evaluate
energy-related business activities undertaken by Sempra Energy within
the service territories of SDG&E and SoCalGas, relative to holding
company systems and affiliate activities. The audit is to consider
whether these activities pose any problems for ratepayers and whether
they are consistent with the CPUC's decision, rules or orders and/or
affiliate statutes. The objective of the audit is to analyze the
adequacy of the Affiliate Rules. In accordance with existing CPUC
requirements, the California Utilities' transactions with other Sempra
Energy affiliates have been audited by an independent auditing firm
each year, with results reported to the CPUC, and there have been no
material adverse findings in those audits.

COST OF SERVICE FILING

On May 22, 2003, the assigned CPUC Commissioner modified his previously
adopted procedural schedule on the California Utilities' Cost of
Service applications to expedite a decision by approximately one month,
permitting a decision by as early as March 2004. The assigned
Commissioner also provided for additional comments to be filed on the
California Utilities' request for interim relief for the period from
January 1, 2004 to the date of the Cost of Service decision and stated
that a decision on the request would be prepared for consideration of
the full Commission. On June 3, 2003, various parties filed reply
comments supporting or opposing the motion for January 1, 2004 interim
relief. The CPUC's Office of Ratepayer Advocates' (ORA) report on the
California Utilities' filing is due on August 8, 2003.

An October 10, 2001 decision denied the California Utilities' request
to continue equal sharing between ratepayers and shareholders of the
estimated savings for the 1998 Enova-PE business combination that
created Sempra Energy and, instead, ordered that all of the estimated
2003 merger savings go to ratepayers. This decision will adversely
affect 2003 net income by $11 million.

MARKET INDEXED CAPITAL ADJUSTMENT MECHANISM (MICAM)

Under MICAM, automatic adjustments are made to SDG&E's cost of capital
based on when the April-September average of single-A utility bond
rates in any given calendar year varies more than 100 basis points from
a predetermined benchmark. When this occurs, SDG&E's return on common
equity (ROE) is adjusted by one-half of the change. SDG&E must file its
annual MICAM advice letter with the CPUC on October 15, reporting how
the year's April-September average of the utility bond yield compares
to the benchmark. Any resulting change in SDG&E's ROE would go into
effect January 1 of the following year. Due to a large general decline
in interest rates, it is likely that the existing MICAM mechanism would
trigger during 2003. However, if the CPUC approves an all-party
settlement previously filed, the likelihood of a trigger this year
would be less since the benchmark rate under the settlement was changed
to the double-A utility bond rate during a different time period which
produced a lower benchmark rate.

The current MICAM benchmark, based on the April-September 1996 single-A
utility bond yield, stands at 7.97%. The MICAM benchmark that would
take effect under the settlement agreement, 7.24%, is based on the
April-September 2002 double-A utility bond yield.

Single-A utility interest rates under the existing mechanism averaged
6.40% from April through June, and an ROE adjustment would occur if the
July through September rate averages 7.53% or lower. Double-A utility
interest rates under the settlement agreement averaged 6.26% from April
through June, and an ROE reduction would occur if the July through
September rate averages 6.20% or lower.

In both versions of MICAM, every percentage point of variance between
the April-September average and the benchmark in excess of the
threshold reduces SDG&E's authorized annual net income by $5 million.

PERFORMANCE-BASED REGULATION (PBR)

On July 15, 2003, the CPUC issued a Draft Resolution (DR) approving
SDG&E's 2001 and 2002 Distribution PBR Performance Reports. If the DR
is approved by the CPUC, SDG&E would be awarded $12.2 million for
exceeding PBR benchmarks on all six of its performance indicators in
2001. SDG&E would also be awarded $6.0 million for exceeding the PBR
benchmarks on five of its six performance indicators in 2002. The total
maximum reward (or penalty) SDG&E could earn in a given year under the
Distribution PBR mechanism is $14.5 million. A final CPUC decision is
expected during the third quarter of 2003.

On March 19, 2003, the ORA issued its Monitoring and Evaluation Report
on SDG&E's natural gas procurement activities in Year 9 (August 1, 2001
through July 31, 2002). The ORA analyzed and confirmed the PBR results
put forth by SDG&E, resulting in a Year 9 shared loss of $1.9 million
and a shareholder penalty of $1.4 million, both of which were recorded
in 2002. The ORA recommended the extension of the PBR mechanism, as
modified in Years 8 and 9, to Year 10 and beyond. The ORA has stated
that the CPUC's adoption of the natural gas procurement PBR mechanism
is beneficial both to ratepayers and to shareholders of SDG&E.

On July 10, 2003, the CPUC issued a decision relative to SDG&E's Year
11 Gas PBR application, which would extend the PBR mechanism with some
modification. The decision approved the Joint Parties' Motion for an
Order Adopting Settlement Agreement filed by SDG&E and the ORA, which
will apply to Year 10 and beyond. The effect of the modifications is to
reduce slightly the potential size of future PBR rewards or penalties.

SDG&E's request for a reward of $6.7 million for the PBR natural gas
procurement period ended July 31, 2001 (Year 8) was approved by the
CPUC on January 30, 2003. Since part of the reward calculation is based
on CA-AZ natural gas border price indices, the decision reserved the
right to revise the reward in the future, depending on the outcome of
the CPUC's border price investigation (see above) and the FERC's
investigation into alleged energy price manipulation (see below).

Performance incentives rewards are not included in the company's
earnings until CPUC approval is received.

TRANSMISSION RATE INCREASE

On May 2, 2003, the FERC accepted SDG&E's request for modification of
its Transmission Owner Tariff to adopt a rate increase. The new
transmission rates are effective October 1, 2003, and will increase the
charges for retail transmission service by $32.3 million (27 percent).
SDG&E has proposed formula-based rates which would allow the company
over a 4 to 5 year period to recover all of its recorded costs as well
as an adopted ROE. Thus, SDG&E would earn no more or no less than the
FERC-adopted ROE for the predetermined period. These new rates are
subject to refund based on the FERC's final order. FERC staff and
intervenor testimonies are due on August 29, 2003. Litigation of the
case would result in a decision by the end of 2004.

In August 2002 the FERC issued Opinion No. 458, which effectively
disallowed SDG&E's recovery of the differentials between certain costs
paid to SDG&E under existing transmission contracts (the "Participation
Agreements") and charges assessed to SDG&E under the ISO FERC tariff.
These charges are for transmission line losses and grid management
charges attributable to energy schedules on portions of the Southwest
Powerlink. As a result, SDG&E is incurring unreimbursed cost
differentials on an ongoing basis at a rate ranging between $4 million
and $8 million per year. SDG&E has petitioned the United States Court
of Appeals for review of these FERC orders. In addition, SDG&E is
challenging the propriety of the ISO charges as applied to the portions
of the Southwest Powerlink jointly owned with Arizona Public Service
Co. and the Imperial Irrigation District in proceedings before the
FERC, and in an arbitration under the ISO tariff, the result of which
may be appealed to the FERC. To the extent SDG&E prevails in these
matters, the FERC may require the ISO to refund to SDG&E all or part of
the subject charges. SDG&E has also commenced a private arbitration to
reform the Participation Agreements to remove prospectively SDG&E's
obligation to provide services giving rise to unreimbursed ISO tariff
charges.

FERC ACTIONS

The FERC is investigating prices charged to buyers in the California
Power Exchange (PX) and Independent System Operator (ISO) markets by
various electric suppliers. It is seeking to determine the extent to
which individual sellers have yet to be paid for power supplied during
the period of October 2, 2000 through June 20, 2001 and to estimate the
amounts by which individual buyers and sellers paid and were paid in
excess of competitive market prices. Based on these estimates, the FERC
could find that individual net buyers, such as SDG&E, are entitled to
refunds and individual net sellers are required to provide refunds. To
the extent any such refunds are actually realized by SDG&E, they would
reduce SDG&E's rate-ceiling balancing account. In December 2002, a FERC
ALJ issued preliminary findings indicating that California owes power
suppliers $1.2 billion (the $3.0 billion that California still owes
energy companies less $1.8 billion energy companies charged California
customers in excess of the FERC cap). On March 26, 2003, the FERC
largely adopted the ALJ's findings, but expanded the basis for refunds
by adopting a staff recommendation from a separate investigation to
change the natural gas proxy component of the mitigated market clearing
price that is used to calculate refunds. The March 26 order estimates
that the replacement formula for estimating natural gas prices will
increase the refund totals to more than $3.0 billion. The precise
number will not be available until the ISO and PX recalculate the
number through their settlement models based on the final FERC
instructions. California is seeking $8.9 billion in refunds and has
appealed the FERC's preliminary findings and requested rehearing of the
March 26 order. The power sellers have joined in appeal of the FERC's
preliminary findings and requested rehearing.

In addition to the refund proceeding described above, the FERC is also
investigating whether there was manipulation of short-term energy
prices in the West that would constitute violations of applicable
tariffs and warrant disgorgement of associated profits. In this
proceeding, the FERC has authority to look at time periods outside of
the October 2, 2000 through June 20, 2001 period relevant to the refund
proceeding. In May 2002 the FERC ordered all energy companies engaged
in electric energy trading activities to state whether they had engaged
in various specific trading activities described as manipulating or
"gaming" the California energy markets.

On June 25, 2003, the FERC issued several orders requiring various
entities to show cause why they should not be found to have violated
California ISO and PX tariffs. The FERC directed 43 entities, including
SDG&E, to show cause why they should not disgorge profits from certain
transactions between January 1, 2000 and June 20, 2001 that are
asserted to have constituted gaming and/or anomalous market behavior
under the California ISO tariff. The ISO has calculated SDG&E's gains
attributable to these issues at less than $200,000.

In addition, the FERC determined that it was appropriate to initiate an
investigation into possible economic withholding in the California ISO
and PX markets. For this purpose, the FERC used an initial screen of
$250 per mW for all bids between May 1, 2000 and October 2, 2000. SDG&E
received data requests from the FERC staff. The FERC staff will prepare
a report to the Commission, which will be the basis to decide whether
additional proceedings are warranted. SDG&E believes that its bids and
bidding procedures were consistent with ISO and PX tariffs and
protocols and applicable FERC price caps.

NUCLEAR INSURANCE

SDG&E and the other co-owners of SONGS have insurance to respond to any
nuclear liability claims related to SONGS. The insurance policy
provides $300 million in coverage, which is the maximum amount
available. In addition to this primary financial protection, the Price-
Anderson Act provides for up to $9.25 billion of secondary financial
protection if the liability loss exceeds the insurance limit. Should
any of the licensed/commercial reactors in the United States experience
a nuclear liability loss which exceeds the $300 million insurance
limit, all utilities owning nuclear reactors could be assessed under
the Price-Anderson Act to provide the secondary financial protection.
SDG&E and the other co-owners of SONGS could be assessed up to $176
million under the Price-Anderson Act. SDG&E's share would be $36
million unless default occurs by any other SONGS co-owner. In the event
the secondary financial protection limit is insufficient to cover the
liability loss, the Price-Anderson Act provides for Congress to enact
further revenue-raising measures to pay claims. These measures could
include an additional assessment on all licensed reactor operators.
SDG&E and the other co-owners of SONGS have $2.75 billion of nuclear
property, decontamination and debris removal insurance.

The coverage also provides the SONGS owners up to $490 million for
outage expenses incurred because of accidental property damage. This
coverage is limited to $3.5 million per week for the first 52 weeks,
and $2.8 million per week for up to 110 additional weeks. 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. The insurance is provided through a mutual insurance company
owned by utilities with nuclear facilities. Under the policy's risk
sharing arrangements, insured members are subject to retrospective
premium assessments if losses at any covered facility exceed the
insurance company's surplus and reinsurance funds. Should there be a
retrospective premium call, SDG&E could be assessed up to $7.4 million.

Both the nuclear liability and property insurance programs include
industry aggregate limits for terrorism-related SONGS losses, including
replacement power costs.

LITIGATION

Lawsuits filed in 2000 and currently consolidated in San Diego Superior
Court seek class-action certification and damages, alleging that Sempra
Energy, SoCalGas and SDG&E, along with El Paso Energy Corp. (El Paso)
and several of its affiliates, unlawfully sought to control natural gas
and electricity markets. In March 2003, plaintiffs in these cases and
the applicable El Paso entities announced that they had reached a
settlement in principle of the class actions, certain of the individual
actions, claims asserted by the California Attorney General and by
other western states, and certain complaint proceedings filed with FERC
by the CPUC and the California Energy Oversight Board. On June 26,
2003, the settlement was filed for approval with the relevant state
courts and the FERC. The settlement provides more than $1.5 billion in
consideration to be received by customers, with no effect on the income
of the utilities processing the refunds. Of these funds, the settlement
provides the following allocation for each SDG&E and SoCalGas customer
group: SDG&E Electric Customers -- $60 million, SDG&E Core Gas -- $29
million and SoCalGas Core Gas -- $36 million. Non-core natural gas
customers will go through a claims process in the courts, by which they
can establish their harm and receive a fair share of the consideration.

A similar lawsuit has been filed by the Attorney General of Arizona
alleging that El Paso and certain Sempra Energy subsidiaries unlawfully
sought to control the natural gas market in Arizona. In April 2003,
Sierra Pacific and its utility subsidiary Nevada Power jointly filed a
lawsuit in U.S. District Court in Las Vegas against major natural gas
suppliers, including Sempra Energy, the California Utilities and other
company subsidiaries, seeking damages resulting from an alleged
conspiracy to drive up or control natural gas prices, eliminate
competition and increase market volatility, and breach of contract and
wire fraud.

Various lawsuits, which seek class-action certification, allege that
Sempra Energy and certain company subsidiaries, including SDG&E,
unlawfully manipulated the electric-energy market. In January 2003, the
applicable Federal Court granted a motion to dismiss a similar lawsuit
on the grounds that the claims contained in the complaint were subject
to the Filed Rate Doctrine and were preempted by the Federal Power Act.
That ruling has been appealed in the Ninth Circuit Court of Appeal and
a decision is expected by first quarter of 2004. Similar suits filed in
Washington and Oregon were voluntarily dropped by the plaintiffs
without court intervention in June 2003.

Except for the matters referred to above, neither the company nor its
subsidiary are party to, nor is their property the subject of, any
material pending legal proceedings other than routine litigation
incidental to their businesses.

Management believes that none of these matters will have a material
adverse effect on the company's financial condition or results of
operations.

PENDING INTERNAL REVENUE SERVICE MATTERS

The company is in discussions with the Internal Revenue Service (IRS)
to resolve issues related to various prior years' returns. A recently
issued Revenue Ruling dealing with utility balancing accounts, and
recent discussions with the IRS concerning this Ruling and another
matter lead the company to believe it will be entitled to record a
reduction in previously recorded income tax expense, accrue significant
interest income on overpayments of tax in certain prior periods and
reverse recorded interest associated with the reporting of these items
in other prior periods. The company expects that these matters will be
favorably resolved before year end and estimates that the resolution
will increase reported 2003 earnings in excess of $60 million.

4. FINANCIAL INSTRUMENTS

Note 8 of the notes to Consolidated Financial Statements in the Annual
Report discusses the company's financial instruments, including the
adoption of SFAS 133, "Accounting for Derivative Instruments and
Hedging Activities," as amended by SFAS 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities." The effect is
to recognize all derivatives as assets or liabilities on the balance
sheet, measure those instruments at fair value, and recognize any
changes in fair value in earnings for the period that the change occurs
unless the derivative qualifies as an effective hedge that offsets
other exposures.

The company utilizes derivative financial instruments to manage its
exposure to unfavorable changes in commodity prices, which are subject
to significant and often volatile fluctuations. Derivative financial
instruments include futures, forwards, swaps, options and long-term
delivery contracts. These contracts allow the company to predict with
greater certainty the effective prices to be received by the company
and their customers. In accordance with SFAS 133, the company has
elected to account for contracts that are settled by physical delivery
at historical cost, with gains and losses reflected in the income
statement at the contract settlement date.

Fixed-price contracts and other derivatives on the Consolidated Balance
Sheets primarily reflect the company's derivative gains and losses
related to long-term delivery contracts for purchased power and natural
gas transportation. The company has established regulatory assets and
liabilities to the extent that these gains and losses are recoverable
or payable through future rates. The changes in fixed-price contracts
and other derivatives on the Consolidated Balance Sheets for the six
months ended June 30, 2003 were primarily due to physical deliveries
under long-term purchased-power and natural gas transportation
contracts. The transactions associated with fixed-price contracts and
other derivatives had no material impact to the Statements of
Consolidated Income for the six months ended June 30, 2003 or 2002.

ITEM 2.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with the
financial statements contained in this Form 10-Q and "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" contained in the Annual Report.

RESULTS OF OPERATIONS

Electric revenues increased to $799 million for the six months ended
June 30, 2003 from $604 million for the same period in 2002, and the
cost of electric fuel and purchased power increased to $300 million in
2003 from $140 million in 2002. Additionally, electric revenues
increased to $402 million for the three months ended June 30, 2003 from
$323 million for the same period in 2002, and the cost of electric fuel
and purchased power increased to $137 million in 2003 from $79 million
in 2002. These changes were mainly due to the effect of the DWR's
purchasing the net short position of SDG&E during 2002, changes in
electric commodity costs, the increase in authorized distribution
revenue and higher volumes in 2003. Under the current regulatory
framework, changes in commodity costs do not affect net income. The
commodity costs associated with the DWR's purchases and the
corresponding sale to SDG&E's customers were not included in the
Statements of Consolidated Income as SDG&E was merely transmitting the
electricity from the DWR to the customers, acting as a conduit to pass
through the electricity from the DWR to the customers. During 2003,
costs associated with long-term contracts allocated to SDG&E from the
DWR were likewise not included in the income statement, since the DWR
retains legal and financial responsibility for these contracts.

Natural gas revenues increased to $283 million for the six months ended
June 30, 2003 from $242 million for the corresponding period in 2002,
and the cost of natural gas increased to $152 million in 2003 from $120
million in 2002. Additionally, natural gas revenues increased to $118
million for the three months ended June 30, 2003 from $91 million for
the corresponding period in 2002, and the cost of natural gas increased
to $67 million in 2003 from $42 million in 2002. These changes were
primarily attributable to natural gas price increases, which are passed
on to customers, partially offset by reduced volumes.

Under the current regulatory framework, changes in core-market natural
gas prices for core customers (primarily residential and small
commercial and industrial customers) do not affect net income, since
core-customer rates generally recover the actual cost of natural gas on
a substantially concurrent basis and are fully balanced. However,
SDG&E's gas procurement PBR mechanism provides an incentive mechanism
by measuring SDG&E's procurement of natural gas against a benchmark
price comprised of monthly natural gas indices, resulting in
shareholder rewards for costs achieved below the benchmark and
shareholder penalties when costs exceed the benchmark.

The tables below summarize the electric and natural gas volumes and
revenues by customer class for the six months ended June 30, 2003 and
2002.

Electric Distribution and Transmission
(Volumes in millions of kilowatt hours, dollars in millions)

Although commodity-related revenues from the DWR's purchasing of
SDG&E's net short position or from the DWR's allocated contracts are
not included in revenue, the associated volumes and distribution
revenue are included herein.

Gas Sales, Transportation and Exchange
(Volumes in billion cubic feet, dollars in millions)

SDG&E recorded net income of $89 million and $107 million for the six-
month periods ended June 30, 2003 and 2002, respectively, and net
income of $42 million and $52 million for the three-month periods ended
June 30, 2003 and 2002, respectively. The decreases were primarily due
to income-tax effects, primarily the $25 million after-tax benefit from
the favorable resolution of prior years' income-tax issues recorded in
the second quarter of 2002, and the end of sharing of the merger
savings, partially offset by increased margins and increased output at
SONGS.

CAPITAL RESOURCES AND LIQUIDITY

The company's operations are the major source of liquidity. In
addition, working capital requirements can be met through the issuance
of short-term and long-term debt. Cash requirements primarily consist
of capital expenditures for utility plant. At June 30, 2003, the
company had $92 million in cash and $300 million in unused, committed
lines of credit available. Management believes these amounts, cash
flows from operations and new debt issuances will be adequate to
finance capital expenditure requirements and other commitments.
Management continues to regularly monitor the company's ability to
adequately meet the needs of its operating, financing and investing
activities.

For additional discussion, see "Factors Influencing Future Performance-
Electric Industry Restructuring and Electric Rates" herein and Note 3
of the notes to Consolidated Financial Statements.

CASH FLOWS FROM OPERATING ACTIVITIES

Net cash provided by operating activities totaled $217 million and $421
million for the six months ended June 30, 2003 and 2002, respectively.
The decrease in cash flows from operations was attributable to higher
income tax payments in 2003 and the higher rate of recovery of the AB
265 undercollection in 2002.

CASH FLOWS FROM INVESTING ACTIVITIES

Net cash used in investing activities totaled $148 million and $344
million for the six months ended June 30, 2003 and 2002, respectively.
The change in cash flows from investing activities was primarily due to
the repayments by Sempra Energy in 2003 of advances made to it in 2002.

Capital expenditures for property, plant and equipment are estimated to
be $400 million for the full year 2003 and are being financed primarily
by internally generated funds and security issuances. Construction,
investment and financing programs are continuously reviewed and revised
in response to changes in competition, customer growth, inflation,
customer rates, the cost of capital, and environmental and regulatory
requirements.

CASH FLOWS FROM FINANCING ACTIVITIES

Net cash used in financing activities totaled $136 million and $62
million for the six months ended June 30, 2003 and 2002, respectively.
The change in cash flows from financing activities was attributable to
higher dividends paid to Sempra Energy of $100 million in 2003,
partially offset by reduced payments on long-term debt in 2003.

In May 2003, SoCalGas and SDG&E replaced their expiring $500 million,
364-day credit agreement with a substantially identical agreement
expiring on May 14, 2004. Under the agreement, each utility may
individually borrow up to $300 million, subject to a combined borrowing
limit for both utilities of $500 million. At the maturity date, each
utility may convert its then outstanding borrowings to a one-year term
loan, subject to having obtained any requisite regulatory approvals.
Borrowings under the agreement would be available for general corporate
purposes including back-up support for commercial paper and variable-
rate long-term debt, and would bear interest at rates varying with
market rates and the borrowing utility's credit rating. The agreement
requires each utility to maintain a debt-to-total capitalization ratio
(as defined in the agreement) of not to exceed 60 percent. The rights,
obligations and covenants of each utility under the agreement are
individual rather than joint with those of the other utility, and a
default by one utility would not constitute default by the other.

FACTORS INFLUENCING FUTURE PERFORMANCE

Performance of the company will depend primarily on the ratemaking and
regulatory process, electric and natural gas industry restructuring,
and the changing energy marketplace. These factors are discussed in the
Annual Report and in Note 3 of the notes to Consolidated Financial
Statements herein.

Income-Tax Issues

Resolution of the income-tax issues described in Note 3 of the notes to
Consolidated Financial Statements herein could have a material impact
on results of operations for 2003, or one or more future periods.

Electric Industry Restructuring and Electric Rates

Supply/demand imbalances and a number of other factors resulted in
abnormally high electric-commodity costs beginning in mid-2000 and
continuing into 2001. This caused SDG&E's customer bills to be
substantially higher than normal. In response, legislation enacted in
September 2000 imposed a ceiling on the cost of electricity that SDG&E
could pass on to its small-usage customers on a current basis. SDG&E
accumulated the amount that it paid for electricity in excess of the
ceiling rate in an interest-bearing balancing account, which it
continues to collect from its customers. During the six months ended
June 30, 2003, the balance in the balancing account declined from $215
million to $174 million.

Subsequent to the electric capacity shortages of 2000-2001, SDG&E's
service territory has had and continues to have an adequate supply of
electricity. However, various projections of electricity demand in
SDG&E's service territory indicate that, without additional electrical
generation or reductions in electrical usage, beginning in 2005
electricity demand could begin to outstrip available resources. SDG&E's
strategy for meeting this demand is to: (1) reduce power demand through
conservation and efficiency; (2) increase the supply of electricity
from renewable sources, including wind and solar; (3) establish new
transmission lines by 2008 to import more power; and (4) provide new
electric generation by 2005 to meet the expected shortfall. SDG&E has
issued a request for proposals to meet the electric capacity shortfall,
estimated at 69 megawatts in 2005. SDG&E is ahead of the interim
schedule required by California legislation in meeting the requirement
of obtaining 20 percent of its electricity from renewable sources by
2017.

Operating costs of SONGS Units 2 and 3, including nuclear fuel and
related financing costs, and incremental capital expenditures are
recovered through the Incremental Cost Incentive Pricing (ICIP)
mechanism which allows SDG&E to receive approximately 4.4 cents per
kilowatt-hour for SONGS generation. Any differences between these costs
and the incentive price affect net income. This mechanism expires on
December 31, 2003. For the year ended December 31, 2002, ICIP
contributed $50 million to SDG&E's net income. The CPUC has denied the
previously approved market-based pricing for SONGS beginning in 2004
and instead provided for traditional rate-making treatment, under which
the SONGS ratebase would begin at zero, essentially eliminating
earnings from SONGS until ratebase grows. The company has applied for
rehearing of this decision, which the CPUC has not yet ruled on. The
company is in the process of litigating the SONGS revenue requirement,
primarily in conjunction with the General Rate Case of Southern
California Edison (the operator and 75-percent owner of SONGS), for
rates that begin in January 2004. (SDG&E seeks to recover approximately
95 percent of its 2004 SONGS operating & maintenance and capital
revenue requirements in that case.) The remaining five percent of the
company's SONGS revenue requirement will be litigated in SDG&E's Cost
Of Service proceeding.

See additional discussion of this and related topics, including the
CPUC's adjustment to its plan for deregulation of electricity, in Note
3 of the notes to Consolidated Financial Statements.

Natural Gas Restructuring and Rates

As discussed in the Annual Report, in December 2001 the CPUC issued a
decision related to natural gas industry restructuring, with
implementation anticipated during 2002. During 2002 the California
Utilities filed a proposed implementation schedule and revised tariffs
and rules required for implementation. However, on February 27, 2003,
the CPUC issued a resolution rejecting without prejudice those proposed
tariffs and rules. If the December 2001 decision is implemented, it is
not expected to adversely affect the California Utilities' results of
operations, cash flows or financial position. A CPUC decision is
expected during 2004.

CPUC Investigation of Compliance with Affiliate Rules

On February 27, 2003, the CPUC opened an investigation of the business
activities of SDG&E, SoCalGas and Sempra Energy to ensure that they
have complied with relevant statutes and CPUC decisions in the
management, oversight and operations of their companies. The Assigned
Commissioner and ALJ issued a ruling which suspends the procedural
schedule until the CPUC completes an independent audit to evaluate
energy-related business activities undertaken by Sempra Energy within
the service territories of SDG&E and SoCalGas, relative to holding
company systems and affiliate activities. The audit is to consider
whether these activities pose any problems for ratepayers and whether
they are consistent with the CPUC's decision, rules or orders and/or
affiliate statutes. The objective of the audit is to analyze the
adequacy of the Affiliate Rules. In accordance with existing CPUC
requirements, the California Utilities' transactions with other Sempra
Energy affiliates have been audited by an independent auditing firm
each year, with results reported to the CPUC, and there have been no
material adverse findings in those audits.

Cost of Service Filing

On May 22, 2003, the assigned CPUC Commissioner modified his previously
adopted procedural schedule on the California Utilities' Cost of
Service applications to expedite a decision by approximately one month,
permitting a decision by as early as March 2004. The assigned
Commissioner also provided for additional comments to be filed on the
California Utilities' request for interim relief for the period from
January 1, 2004 to the date of the Cost of Service decision and stated
that a decision on the request would be prepared for consideration of
the full Commission. On June 3, 2003, various parties filed reply
comments supporting or opposing the motion for January 1, 2004 interim
relief. The CPUC's Office of Ratepayer Advocates' (ORA) report on the
California Utilities' filing is due on August 8, 2003.

An October 10, 2001 decision denied the California Utilities' request
to continue equal sharing between ratepayers and shareholders of the
estimated savings for the 1998 Enova-PE business combination that
created Sempra Energy and, instead, ordered that all of the estimated
2003 merger savings go to ratepayers. This decision will adversely
affect 2003 net income by $11 million.

NEW ACCOUNTING STANDARDS

New pronouncements that have recently become effective or that are yet
to be effective are SFAS 143, 148, 149 and 150, Interpretations 45 and
46, EITF 02-3, and the rescission of EITF 98-10. See discussion in Note
2 of the notes to Consolidated Financial Statements. Pronouncements
that have or potentially could have a material effect on future
earnings are described below.

SFAS 143, "Accounting for Asset Retirement Obligations" is the only one
of the above pronouncements that is material to the company. Issued in
July 2001, SFAS 143 addresses financial accounting and reporting for
legal obligations associated with the retirement of tangible long-lived
assets. It requires entities to record the fair value of a liability
for an asset retirement obligation in the period in which it is
incurred. The company adopted SFAS 143 on January 1, 2003. See further
discussion in Note 2 of the notes to Consolidated Financial Statements.

ITEM 3. MARKET RISK

There have been no significant changes in the risk issues affecting the
company subsequent to those discussed in the Annual Report.

As of June 30, 2003, the total Value at Risk of SDG&E's natural gas
positions was not material.

ITEM 4. CONTROLS AND PROCEDURES

The company has designed and maintains disclosure controls and
procedures to ensure that information required to be disclosed in the
company's reports under the Securities Exchange Act of 1934 is recorded,
processed, summarized and reported within the time periods specified in
the rules and forms of the Securities and Exchange Commission and is
accumulated and communicated to the company's management, including its
Chief Executive Officer and Chief Financial Officer, as appropriate, to
allow timely decisions regarding required disclosure. In designing and
evaluating these controls and procedures, management recognizes that any
system of controls and procedures, no matter how well designed and
operated, can provide only reasonable assurance of achieving the desired
objectives and necessarily applies judgment in evaluating the cost-
benefit relationship of other possible controls and procedures. Under
the supervision and with the participation of management, including the
Chief Executive Officer and the Chief Financial Officer, the company
within 90 days prior to the date of this report has evaluated the
effectiveness of the design and operation of the company's disclosure
controls and procedures. Based on that evaluation, the company's Chief
Executive Officer and Chief Financial Officer have concluded that the
controls and procedures are effective.

There have been no significant changes in the internal controls or in
other factors that could significantly affect the internal controls
subsequent to the date the company completed its evaluation.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Except as described in Note 3 of the notes to Consolidated Financial
Statements, neither the company nor its subsidiary is party to, nor is
their property the subject of, any material pending legal proceedings
other than routine litigation incidental to their businesses.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits

Exhibit 10 - Material Contracts

10.1 2003 Executive Incentive Plan (June 30, 2003 Sempra
Energy 10-Q Exhibit 10.1)

10.2 Amended 1998 Long-Term Incentive Plan (June 30, 2003
Sempra Energy 10-Q Exhibit 10.2)

Exhibit 12 - Computation of ratios

12.1 Computation of Ratio of Earnings to Combined Fixed
Charges and Preferred Stock Dividends.

Exhibit 31 - Section 302 Certification

31.1 Statement of Registrant's Chief Executive Officer pursuant
to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

31.2 Statement of Registrant's Chief Financial Officer pursuant
to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

Exhibit 32 - Section 906 Certification

32.1 Statement of Registrant's Chief Executive Officer pursuant
to 18 U.S.C. Sec. 1350.

32.2 Statement of Registrant's Chief Financial Officer pursuant
to 18 U.S.C. Sec. 1350.

(b) Reports on Form 8-K

The following report on Form 8-K was filed after March 31, 2003:

Current Report on Form 8-K filed May 1, 2003, filing as an exhibit
Sempra Energy's press release of May 1, 2003, giving the financial
results for the three months ended March 31, 2003.

Current Report on Form 8-K filed August 7, 2003, filing as an exhibit
Sempra Energy's press release of August 7, 2003, giving the financial
results for the three months ended June 30, 2003.

SIGNATURE

Pursuant to the requirement of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.

SAN DIEGO GAS & ELECTRIC COMPANY
(Registrant)

Date: August 7, 2003 By: /s/ D.L. Reed
-----------------------------
D.L. Reed
President and
Chief Financial Officer