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 September 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 Reports on Form
10-Q for the three months ended March 31, 2003 and June 30, 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 Nine months
ended ended
September 30, September 30,
-----------------------------------
(Dollars in millions) 2003 2002 2003 2002
- ------------------------------------------------------------------
Net income $ 121 $ 48 $ 210 $ 155

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

-----------------------------------
Comprehensive income $ 121 $ 48 $ 204 $ 154
- ------------------------------------------------------------------

* 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
to utility plant of $71 million, representing the company's share of
the San Onofre Nuclear Generating Station's (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 nine months
ended September 30, 2003 is as follows (dollars in millions):

Balance as of January 1, 2003 $ --
Adoption of SFAS 143 319
Accretion expense 16
Payments (12)
------
Balance as of September 30, 2003 $ 323*
======

*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 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities": SFAS 149 amends and clarifies accounting for
derivative instruments, including certain derivative instruments
embedded in other contracts, and for hedging activities under SFAS 133.
The adoption of SFAS 149 did not have an effect on the company's
consolidated results of operations and financial position.

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 previously classified in the mezzanine section of
the balance sheet be reclassified as liabilities. The company has
adopted SFAS 150 beginning July 1, 2003 by reclassifying $23 million of
mandatorily redeemable preferred stock to deferred credits and other
liabilities.

3. MATERIAL CONTINGENCIES

ELECTRIC INDUSTRY REGULATION

The restructuring of California's electric utility industry has
significantly affected the company's electric utility operations and
the power crisis of 2000-2001 caused the California Public Utilities
Commission (CPUC) to adjust its plan for restructuring the electricity
industry. The background of this issue is described in the Annual
Report. Subsequent developments are described herein.

Various projections of electricity demand in SDG&E's service territory
indicate that, without additional electrical generation and
transmission and reductions in electrical usage, beginning in 2005
electricity demand could begin to outstrip available resources. 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
approximately 100 megawatts, and has filed a proposed plan at the CPUC
for meeting these capacity requirements.

On October 7, 2003, SDG&E applied to the CPUC for approval of its RFP
results. SDG&E's electric procurement plan contemplates (i) procuring
643 megawatts of energy and demand reduction resources (73 megawatts
beginning in 2005 with contracts extending through 2020 and 570
megawatts beginning in 2007 and extending through 2017); (ii) acquiring
601 megawatts of new generation, including a 555-megawatt power plant
in Escondido, California, to be constructed by Sempra Energy Resources,
an affiliate, for completion in 2006; and (iii) constructing new
transmission lines. The capital cost related to this proposed plan is
approximately $640 million and the plan includes a mix of energy supply
sources, including renewable resources. Hearings will be held during
the fourth quarter of 2003 and a CPUC decision is expected during the
first half of 2004. In connection with the possible return to a
generation-ownership role for investor-owned utilities (IOUs), SDG&E
required bidders to include both power purchase and SDG&E ownership
options in their response to the RFP noted above.

The California Department of Water Resources' (DWR) Operating Agreement
with SDG&E, approved by the CPUC, governs SDG&E's 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
SDG&E's 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. Since the DWR
retains legal and financial responsibility for the contracts allocated
to SDG&E, the costs associated with the contracts were not included in
the Statements of Consolidated Income during 2003. On July 10, 2003,
the CPUC approved SDG&E's natural gas supply plan related to certain
DWR contracts for the five-month period May 1, 2003 to September 30,
2003. On August 15, 2003, SDG&E filed with the CPUC its natural gas
supply plan related to certain DWR contracts for the six-month period
October 1, 2003 to March 31, 2004. CPUC action on this filing is
pending.

On September 4, 2003, the CPUC approved a $1-billion refund to
consumers of the three major California IOUs as a result of the DWR's
lowering its revenue requirement for 2003. The refund is being returned
to customers in the form of a one-time bill credit. SDG&E's portion is
13.51 percent or about $135 million. The bill credit will have no
effect on SDG&E's net income and net cash flows because customer
savings are coming from lower charges by the DWR, and SDG&E is merely
transmitting the electricity from the DWR to the customers, without
taking title to the electricity.

The final true-up of DWR's 2001/2002 energy costs among California's
three major investor-owned electric utilities could result in SDG&E's
customers being allocated up to $60 million of additional costs or
having their allocation reduced by as much as $100 million. In either
case, SDG&E would account for any adjustment in its commodity balancing
account, which would be repaid to its customers or collected from its
customers in the near future. Either change in allocation would have a
short-term effect on SDG&E's cash flow (positive or negative as the
case may be), but would not otherwise affect its results of operations.

On August 21, 2003, the CPUC denied a rehearing requested by opponents
of its December 2002 decision that had approved a settlement with SDG&E
allocating between SDG&E customers and shareholders the profits from
intermediate-term purchase power contracts that SDG&E had entered into
during the early stages of California's electric utility industry
restructuring. As previously reported, the settlement provided $199
million of these profits to customers, by reductions to balancing
account undercollections in prior years. The settlement provided the
remaining $173 million of profits to SDG&E shareholders, of which $57
million had been recognized for financial reporting purposes in prior
years. As a result of the decision, SDG&E recognized additional after-
tax income of $65 million in the third quarter of 2003. On September
25, 2003 the Utility Consumers' Action Network (UCAN), a consumer-
advocacy group which had requested the CPUC rehearing, appealed the
decision to the California Court of Appeals. On October 24, 2003, SDG&E
and the Commission filed responses with the court to the UCAN appeal,
setting forth the reasons why there is no issue of law for the court to
consider and that the appeal should be denied. UCAN has twenty days to
file a reply. Acceptance of any appeal is at the discretion of the
court. There is no deadline by which the court must act.

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.

On September 29, 2003, the CPUC issued a ruling indicating that the
proceeding will initially only consider implementation of the original
December 2001 decision, but the Assigned Commissioner said he will
informally look at the alternatives proposed by SoCalGas. The matter
has been set for hearing and a CPUC decision is expected by January
2004. If the December 2001 decision is implemented, it is not expected
to have a material effect on the company's earnings.

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. On September
18, 2003, the Commission suspended 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 will be combined with the annual
affiliate audit and should be completed by the end of 2004. The scope
of the audit will be broader than the annual affiliate audit. In
addition to an evaluation of compliance with CPUC rules and
requirements, this audit will assess the potential for conflicts
between the interests of Sempra Energy and the interests of the
California Utilities and their ratepayers, and examine whether business
activities undertaken by the utilities and/or their holding company and
affiliates pose potential problems or unjust or unreasonable impacts on
utility customers.

COST OF SERVICE FILING

As previously reported, the California Utilities have filed cost of
service applications with the CPUC seeking rate increases designed to
reflect forecasts of 2004 capital and operating costs. SDG&E is
requesting revenue increases of approximately $76 million. The CPUC's
Office of Ratepayer Advocates (ORA) filed its prepared testimony in the
applications on August 8, 2003, recommending rate decreases that would
reduce annual revenues by $41 million from their current level. UCAN
has proposed rates for SDG&E that would reduce annual revenues by $88
million from their current level. Hearings are expected to conclude by
the end of this month. The procedural schedule for the cost of service
applications permits a decision as early as March 2004, and the
California Utilities have filed a petition for interim rate relief for
the period from January 1, 2004 until the effective date of the
decision. On November 3, 2003, the CPUC ALJ released a Proposed
Decision that would authorize the California Utilities to create a
memorandum account as of January 1, 2004, to record the difference
between existing rates and those that are later authorized in the
Commission's final decision in this case. The difference would then be
amortized in rates. The full Commission can vote on the Proposed
Decision as soon as December 4, 2003. The California Utilities have
also filed for continuation through 2004 of existing PBR mechanisms for
service quality and safety that would otherwise expire at the end of
2003.

MARKET INDEXED CAPITAL ADJUSTMENT MECHANISM (MICAM)

MICAM has the potential to revise a utility's rates to reflect changes
in market interest rates. On September 4, 2003, the CPUC approved an
all-party settlement that modified the MICAM such that the possibility
of a MICAM-caused reduction in SDG&E's authorized return on common
equity for 2004 has been eliminated.

PERFORMANCE-BASED REGULATION (PBR)

On August 21, 2003, the CPUC issued a final resolution approving
SDG&E's 2001 and 2002 Distribution PBR Performance Reports. SDG&E was
awarded $12.2 million for exceeding PBR benchmarks on all six of its
performance indicators in 2001, and $6.0 million for exceeding the PBR
benchmarks on five of its six performance indicators in 2002. These
rewards were included in income in the third quarter of 2003. The total
maximum reward (or penalty) SDG&E could earn in a given year under the
Distribution PBR mechanism is $14.5 million.

On July 16, 2003, SDG&E filed an Advice Letter requesting approval of a
shareholder penalty of $1.4 million for Year 9 (August 1, 2001 through
July 31, 2002) of its Gas Procurement PBR mechanism. The $1.4 million
penalty was recorded in 2002 and is consistent with the ORA's March 19,
2003 Monitoring and Evaluation Report on SDG&E's natural gas
procurement activities in Year 9. In its report, the ORA recommended
the extension of the PBR mechanism, as modified in Years 8 and 9, to
Year 10 and beyond, and 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. This award was recorded in income in the
first quarter of 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 before CPUC approval is received.

DEMAND SIDE MANAGEMENT (DSM) AND ENERGY EFFICIENCY AWARDS

Since the 1990s, IOUs have been eligible to earn awards for
implementing and administering energy conservation and efficiency
programs. The California Utilities have offered these programs to
customers and have consistently achieved significant earnings
therefrom. On October 16, 2003, the CPUC issued a decision that the
pre-1998 DSM earnings mechanism would not be reopened. Therefore, the
CPUC will not redetermine the uncollected portion of past awards earned
by the IOUs and will not be recomputing the amounts of the awards, but
may adjust such amounts consistent with the application of known,
standard measurement and verification protocols.

The CPUC has consolidated the 2000, 2001, 2002 and 2003 award
applications. On May 2, 2003, the CPUC released an RFP to conduct a
review of the IOUs' studies used as the basis for the awards claims.
The review should be completed by the second quarter of 2004. All
outstanding claims are on hold pending completion of the independent
review. As of September 30, 2003, SDG&E had $36 million in DSM/energy
efficiency rewards requested but pending CPUC approval and had $26
million in rewards for which it has not yet requested approval.

BLYTHE GAIN ON SALE

The ORA is proposing to use a risk analysis to allocate the 2001 gain
on the sale of SDG&E's surplus property in Blythe, California rather
than the time in rate base versus out of rate base methodology proposed
by SDG&E and historically used by the CPUC. SDG&E's proposal would
allocate $3.1 million to ratepayers, whereas the ORA proposes to
allocate $14.4 million. This issue is being addressed in the Cost of
Service filing described above. A decision is expected as early as
March 2004.

TRANSMISSION RATE INCREASE

SDG&E's retail-related rates applicable to transmission service were
set based on a 1998 test year, at a level that during 2002 was
substantially lower than needed to maintain an adequate return on
equity (ROE). Consequently, SDG&E filed revised rates on March 7, 2003,
proposing a formula rate that would allow, through June 2007, the full
recovery of all transmission-related rate base and expenses on a trued-
up basis. Thus, SDG&E would earn no more nor no less than its
transmission cost of service at the FERC-adopted ROE for the
predetermined period. On May 2, 2003, the FERC accepted SDG&E's request
for modification of its Transmission Owner Tariff to adopt a rate
increase, subject to hearing and, if appropriate, refunds. New
transmission rates, which are subject to refund based on the FERC's
final order, became effective October 1, 2003.

On October 9, 2003, SDG&E filed a proposed settlement agreement with
the FERC, supported by the FERC trial staff, the CPUC and the
Independent System Operator (ISO). As a result of the settlement,
SDG&E's ROE would be 11.25 percent, rather than the 13 percent SDG&E
requested. SDG&E's revenue requirements for its retail and wholesale
customers for the initial 12-month period beginning October 1, 2003,
would be $142.1 million and $135.6 million, respectively, rather than
the $149.5 million and $143.7 million requested. The settlement
contemplates that SDG&E will fully recover its cancelled Valley-Rainbow
Project costs of $19 million over a ten-year amortization period
without interest. The transmission rate formula is to be in effect
through June 30, 2007. A final decision is not expected before late
November 2003.

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 for
transmission line losses and grid management charges related to its
Southwest Powerlink. SDG&E had previously been recovering these costs
by charging them through the Transmission Revenue Balancing Account,
but Opinion No. 458 rejected this approach and required SDG&E to refund
the cost differentials so recovered. SDG&E's request for rehearing was
denied. As a result, SDG&E is incurring unreimbursed costs of $4
million to $8 million per year. SDG&E has petitioned the United States
Court of Appeals for review of these FERC orders and has submitted to
the FERC a refund plan which would refund $21 million to transmission
customers via the Transition Cost Balancing Account. This refund
arrangement is subject to FERC acceptance, which is pending. 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. On October 27, 2003, an independent arbitrator found in SDG&E's
favor on this matter. The ISO has the right to appeal this result 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 costs. 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

Refund Proceedings

The FERC is investigating prices charged to buyers in the California
Power Exchange (PX) and ISO markets by various electric suppliers. The
FERC 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 the California PX and ISO owe power suppliers $1.2 billion (the
$3.0 billion that the California PX and ISO still owe energy companies
less $1.8 billion that the energy companies charged California
customers in excess of the preliminarily determined competitive market
clearing prices). 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
obligations from $1.8 billion to more than $3 billion. The FERC
recently released its final instructions, and the ISO and PX have five
months to recalculate the precise number through their settlement
models. California is seeking $8.9 billion in refunds and has appealed
the FERC's preliminary findings and requested rehearing of the March 26
order.

Manipulation Investigation

The FERC is also investigating whether there was manipulation of short-
term energy markets in the West that would constitute violations of
applicable tariffs and warrant disgorgement of associated profits. In
this proceeding, the FERC's authority is not confined to 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 in violation of the PX and ISO tariffs
(generally 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. 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 and/or PX tariffs. SDG&E agreed to pay $28
thousand into a FERC-established fund on behalf of customers in order
to bring its case to closure. FERC approval is pending.

On June 25, 2003, the FERC also determined that it was appropriate to
initiate an investigation into possible physical and economic
withholding in the California ISO and PX markets. For this purpose,
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 and have provided responses. 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. On August 1, 2003, FERC staff issued an
initial report that determined there was no need to further investigate
particular entities for physical withholding of generation.

Price Reporting Practices

On September 26, 2003, FERC sent a survey to 266 companies concerning
natural gas and electric price reporting practices. The survey is
being conducted in support of FERC's "Policy Statement on Natural Gas
and Electric Price Indices" issued in July 2003, to measure industry
progress in voluntary reporting of energy trade data to publishers of
energy price indices. Responses to the survey were provided on behalf
of SDG&E. A second survey is expected to be conducted in March 2004 in
FERC's continuing effort to monitor energy price reporting.

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. The Price-Anderson Act provides for up to $10.6 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 $201 million under the Price-Anderson Act. SDG&E's share
would be $40 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, Congress could impose 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, SDG&E could be assessed up to $7.4 million if losses at
any covered facility exceed the insurance company's surplus and
reinsurance funds.

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

LITIGATION

During the third quarter of 2003, the company recorded additional
charges against income for litigation costs and possible resolution of
certain cases. Management believes that none of these matters will have
further material adverse effect on the company's financial condition or
results of operations. Except for the matters referred to below,
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.

Antitrust 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 $1.5
billion settlement, of which $125 million is allocated to customers of
the California Utilities. The proceeding against Sempra Energy and the
California Utilities has not been settled and continues to be
litigated.

Natural Gas Cases: Similar lawsuits have been filed by the Attorney
General of Arizona and the Attorney General of Nevada alleging that El
Paso and certain Sempra Energy subsidiaries unlawfully sought to
control the natural gas market in their respective states. In April
2003, Sierra Pacific Resources and its utility subsidiary Nevada Power
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, breach of
contract and wire fraud.

Electricity Cases: 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 Appeals and a decision is expected in the
first quarter of 2004. Similar suits filed in Washington and Oregon
were voluntarily dropped by the plaintiffs without court intervention
in June 2003.

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 Revenue
Ruling dealing with utility balancing accounts, and 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 resolved before
year end and estimates that favorable resolution could increase
reported earnings by in excess of $60 million.

The company is unable to predict the net effect of the ultimate
resolution of these income tax matters.

RECENT SOUTHERN CALIFORNIA FIRES

Several major wildfires that began on October 26, 2003 severely damaged
some of SDG&E's infrastructure, causing a significant number of
customers to be without utility services. On October 27, 2003, Governor
Gray Davis declared a "state of emergency" for four counties, including
the County of San Diego.

The declaration of a state of emergency invokes Public Utilities Code
Section 454.9, which authorizes a public utility to establish a
catastrophic event memorandum account (CEMA) to record all costs
associated with (1) restoring utility services to customers; (2)
repairing, replacing or restoring damaged utility facilities and (3)
complying with governmental agency orders in connection with events
declared disasters by competent state or federal authorities.

The costs recorded in the CEMA are recoverable in rates separate from
ordinary costs currently recovered in rates. Public Utilities Code
Section 454.9 requires that the CPUC hold expedited hearings in
response to the utilities' request for recovery. SDG&E is recording
fire damage costs and the costs of restoring electric and natural gas
service in the CEMA account. Therefore, the company expects no
significant effect on earnings from the fires.

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" and SFAS 149,
"Amendment of Statement 133 on Derivative Instruments and 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 its 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 nine
months ended September 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 nine months ended September
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 $1.4 billion for the nine months ended
September 30, 2003 from $962 million for the same period in 2002, and
the cost of electric fuel and purchased power increased to $428 million
in 2003 from $221 million in 2002. Additionally, electric revenues
increased to $579 million for the three months ended September 30, 2003
from $358 million for the same period in 2002, and the cost of electric
fuel and purchased power increased to $128 million in 2003 from $81
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, increases
in electric commodity costs, the increase in authorized distribution
revenue and higher volumes in 2003, and, for the quarter, recognition
of $116 million related to the approved settlement of intermediate-term
purchase power contracts and higher earnings from PBR awards. See
discussion of performance awards in Note 3 of the notes to Consolidated
Financial Statements.

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 sales to SDG&E's customers were not
included in the Statements of Consolidated Income as SDG&E was merely
transmitting electricity from the DWR to the customers without taking
title to the electricity. 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 $371 million for the nine months
ended September 30, 2003 from $309 million for the corresponding period
in 2002, and the cost of natural gas increased to $199 million in 2003
from $149 million in 2002. Additionally, natural gas revenues increased
to $88 million for the three months ended September 30, 2003 from $67
million for the corresponding period in 2002, and the cost of natural
gas increased to $47 million in 2003 from $29 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 nine months ended September 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 $210 million and $155 million for the
nine-month periods ended September 30, 2003 and 2002, respectively, and
net income of $121 million and $48 million for the three-month periods
ended September 30, 2003 and 2002, respectively. The increases were
primarily due to income of $65 million after-tax related to the
approved settlement of intermediate-term purchase power contracts,
higher earnings from PBR awards, and higher transportation and
distribution revenue. These factors were partially offset by higher
operating expenses including litigation charges in the third quarter of
2003, and the end of sharing of the merger savings (which positively
impacted earnings by $6 million for the nine-month period and $2
million for the three-month period in 2002). Additionally, for the
nine-month period, the increases were offset by the $25 million benefit
from the favorable resolution of prior years' income-tax issues
recorded in the second quarter of 2002.

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 September 30, 2003, the
company had $174 million in cash and $300 million in unused, committed
lines of credit available. Management believes these amounts and cash
flows from operations and new debt issuances will be adequate to
finance capital expenditure requirements and other commitments.

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 $465 million and $628
million for the nine months ended September 30, 2003 and 2002,
respectively. The decrease was attributable to 2003's lower rate of
recovery of the AB 265 undercollection and higher natural gas inventory
(due to higher natural gas prices).

During the third quarter of 2003, the company made a pension plan
contribution of $17.2 million for the 2003 plan year.

CASH FLOWS FROM INVESTING ACTIVITIES

Net cash used in investing activities totaled $246 million and $619
million for the nine months ended September 30, 2003 and 2002,
respectively. The change was primarily due to the $45 million repayment
by Sempra Energy in 2003 compared to $336 million of advances from
SDG&E 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 $204 million and $90
million for the nine months ended September 30, 2003 and 2002,
respectively. The change was attributable to higher dividends paid to
Sempra Energy in 2003, partially offset by reduced payments on long-
term debt in 2003. During the nine months ended September 30, 2003,
SDG&E repaid $48 million of rate-reduction bonds.

CREDIT RATINGS

On October 7, 2003, Standard & Poor's reduced the corporate credit
ratings of SDG&E from A+ to A. The company's prior ratings for senior
secured debt were affirmed at A+. All ratings were issued with a stable
outlook.

On October 14, 2003 Fitch Ratings affirmed the senior secured debt
ratings of SDG&E at AA, senior unsecured debt ratings at AA-, and
preferred stock ratings at A+.

Moody's senior secured debt ratings of SDG&E remained unchanged at A1,
the senior unsecured debt ratings at A2, and preferred stock ratings at
Baa1. All ratings maintained their prior stable outlook.

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 nine months ended
September 30, 2003, the balance in the balancing account declined from
$215 million to $156 million.

Subsequent to the electric capacity shortages of 2000-2001, SDG&E's
service territory 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 and transmission and 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 a new transmission interconnect by 2008 or as soon
thereafter as practicable; and (4) provide new electric generation to
address the reliability deficiency identified by SDG&E as beginning in
2005. 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 approximately 100 megawatts, and has filed a
proposed plan at the CPUC for meeting these capacity requirements.
SDG&E is currently 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. On October 7, 2003,
SDG&E filed a motion for approval of its RFP results. See Note 3 of the
notes to Consolidated Financial Statements for additional information
regarding the RFP results.

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 company is in the
process of addressing 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 is being addressed 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. On September 29, 2003, the CPUC issued a ruling
indicating that the proceeding will initially only consider
implementation of the original December 2001 decision, but the Assigned
Commissioner said he will informally look at the alternatives proposed
by SoCalGas. The matter has been set for hearing and a CPUC decision is
expected by January 2004. If the December 2001 decision is implemented,
it is not expected to have a material effect on the company's earnings.

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. On September
18, 2003, the Commission suspended 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 will be combined with the annual
affiliate audit and should be completed by the end of 2004. The scope
of the audit will be broader than the annual affiliate audit. In
addition to an evaluation of compliance with CPUC rules and
requirements, this audit will assess the potential for conflicts
between the interests of Sempra Energy and the interests of the
California Utilities and their ratepayers, and examine whether business
activities undertaken by the California Utilities and/or their holding
company and affiliates pose potential problems or unjust or
unreasonable impacts on utility customers.

Cost of Service Filing

As previously reported, the California Utilities have filed cost of
service applications with the CPUC seeking rate increases designed to
reflect forecasts of 2004 capital and operating costs. SDG&E is
requesting revenue increases of approximately $76 million. The ORA
filed its prepared testimony in the applications on August 8, 2003,
recommending rate decreases that would reduce annual revenues by $41
million from their current level. UCAN has proposed rates for SDG&E
that would reduce annual revenues by $88 million from their current
level. Hearings are expected to conclude by the end of this month. The
procedural schedule for the cost of service applications permits a
decision as early as March 2004, and the California Utilities have
filed a petition for interim rate relief for the period from January 1,
2004 until the effective date of the decision. On November 3, 2003, the
CPUC ALJ released a Proposed Decision that would authorize the
California Utilities to create a memorandum account as of January 1,
2004, to record the difference between existing rates and those that
are later authorized in the Commission's final decision in this case.
The difference would then be amortized in rates. The full Commission
can vote on the Proposed Decision as soon as December 4, 2003. The
California Utilities have also filed for continuation through 2004 of
existing PBR mechanisms for service quality and safety that would
otherwise expire at the end of 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. In 2002, merger savings to
shareholders for the three-month and nine-month periods were $2 million
and $6 million, respectively.

NEW ACCOUNTING STANDARDS

Relevant pronouncements that have recently become effective or that are
yet to be effective are SFAS 143, 148, 149 and 150, Interpretations 45
and 46, and EITF 02-3. See discussion in Note 2 of the notes to
Consolidated Financial Statements.

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.

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 September 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 as of the date of this quarterly 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 12 - Computation of ratios

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

Exhibit 31 -- Section 302 Certifications

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 Certifications

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 June 30, 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.

Current Report on Form 8-K filed September 2, 2003, announcing CPUC
approval of certain performance rewards and the CPUC's denial of
rehearing requested by opponents of an approved settlement agreement
with SDG&E.

Current Report on Form 8-K filed November 6, 2003, filing as an exhibit
Sempra Energy's press release of November 6, 2003, giving the financial
results for the three months ended September 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: November 6, 2003 By: /s/ D.L. Reed
-----------------------------
D.L. Reed
President and
Chief Financial Officer