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 March 31, 2004
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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
- -------------------------------------------------------------------
(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," "could," "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 and national economic,
competitive, political, legislative and regulatory conditions and
developments; actions by the California Public Utilities Commission,
the California Legislature, the California 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.

PART I FINANCIAL INFORMATION
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
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

NOTE 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, 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 December 31, 2003 income tax liabilities have been reclassified
from Deferred Income Taxes to current Income Taxes Payable and to
Deferred Credits and Other Liabilities to conform to the current
presentation of these items.

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, 2003 (Annual Report).

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.

SDG&E accounts for the economic effects of regulation on utility
operations in accordance with Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types
of Regulation."

NOTE 2. NEW ACCOUNTING STANDARDS

Stock-Based Compensation: On March 31, 2004, the Financial Accounting
Standards Board (FASB) issued a proposed Exposure Draft to amend SFAS
123, "Accounting for Stock-Based Compensation" and SFAS 95, "Statement
of Cash Flows" which provide the current guidance on accounting for
stock options and related items. It proposes that the new rules would
be effective for 2005. The proposed statement would eliminate the
choice of accounting for share-based compensation transactions using
Accounting Principles Board Opinion No. 25, "Accounting for Stock
Issued to Employees," and instead generally would require that such
transactions be accounted for using a fair-value-based method. The
Draft would prohibit retroactive application and require that expense
be recognized only for those options that actually vest.

SFAS 132 (revised 2003), "Employers Disclosures about Pensions and
Other Postretirement Benefits": This statement revises employers'
disclosures about pension plans and other postretirement benefit plans.
It requires disclosures beyond those in the original SFAS 132 about the
assets, obligations, cash flows and net periodic benefit cost of
defined benefit pension plans and other defined postretirement plans.
In addition, the revised statement requires interim-period disclosures
regarding the amount of net periodic benefit cost recognized and the
total amount of the employers' contributions paid and expected to be
paid during the current fiscal year. It does not change the measurement
or recognition of those plans.

The following table provides the components of benefit costs for the
quarters ended March 31:

Note 6 of the notes to Consolidated Financial Statements in the Annual
Report discusses the company's expected contribution to its pension
plan and other postretirement benefit plans in 2004. For the quarter
ended March 31, 2004, $1 million of contributions have been made to its
other postretirement benefit plans. There was no contribution made to
its pension plan for the quarter ended March 31, 2004.

SFAS 143, "Accounting for Asset Retirement Obligations": SFAS 143
requires entities to record the fair value of liabilities for legal
obligations related to asset retirements in the period in which they
are incurred. It also requires the reclassification of estimated
removal costs, which have historically been recorded in accumulated
depreciation, to a regulatory liability. At March 31, 2004 and December
31, 2003, the estimated removal costs recorded as a regulatory
liability were $857 million and $846 million, respectively.

The change in the asset retirement obligations for the quarter ended
March 31, 2004 is as follows (dollars in millions):

Balance as of January 1, 2004 $ 326
Accretion expense 6
Payments (3)
------
Balance as of March 31, 2004 $ 329*
======
* The current portion of the obligation is included in Other Current
Liabilities on the Consolidated Balance Sheets.

SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities": Effective July 1, 2003, SFAS 149 amended and
clarified accounting for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging
activities under SFAS 133. Under SFAS 149 natural gas forward contracts
that are subject to unplanned netting generally do not qualify for the
normal purchases and normal sales exception. ("Netting" refers to
contract settlement by paying or receiving the monetary difference
between the contract price and the market price at the date on which
physical delivery would have occurred.) In addition, effective January
1, 2004, power contracts that are subject to unplanned netting and that
do not meet the normal purchases and normal sales exception under SFAS
149 will continue to be marked to market. Implementation of SFAS 149
did not have a material impact on reported net income. Additional
information on derivative instruments is provided in Note 4.

SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of Liabilities and Equity": The company adopted SFAS
150 beginning July 1, 2003 by reclassifying $24 million of mandatorily
redeemable preferred stock to Deferred Credits and Other Liabilities
and to Other Current Liabilities on the Consolidated Balance Sheets.

Emerging Issues Task Force (EITF) 03-11, "Reporting Realized Gains and
Losses on Derivative Instruments that are Subject to FASB Statement No.
133, Accounting for Derivative Instruments and Hedging Activities and
Not 'Held for Trading Purposes' as Defined in EITF Issue No. 02-3,
Issues Involved in Accounting for Derivative Contracts Held for Trading
Purposes and Contracts Involved in Energy Trading and Risk Management
Activities": During 2003, the EITF reached a consensus that determining
whether realized gains and losses on physically settled derivative
contracts not held for trading purposes should be reported in the
income statement on a gross or net basis is a matter of judgment that
depends on the relevant facts and circumstances. Adoption of EITF 03-11
in 2003 did not have and is not expected to have a significant impact
on the company's financial statements.

FASB Staff Position (FSP) 106-1, "Accounting and Disclosure
Requirements Related to the Medicare Prescription Drug, Improvement and
Modernization Act of 2003": Issued January 12, 2004, FSP 106-1 permits
a sponsor of a postretirement health care plan that provides a
prescription drug benefit to make a one-time election to defer
accounting for the effects of the Medicare Prescription Drug,
Improvement and Modernization Act of 2003 (the Act). The company has
elected to defer the effects of the Act as provided by FSP 106-1 until
authoritative guidance on the accounting for the federal subsidy is
issued. Any measure of the accumulated postretirement benefit
obligation or net periodic postretirement benefit cost in the financial
statements or the accompanying notes does not reflect the impact of the
Act on the plans. At this time, specific authoritative guidance on the
accounting for the federal subsidy provided by the Act is pending and
that guidance could require the company to change previously reported
information.

FASB Interpretation No. (FIN) 46, "Consolidation of Variable Interest
Entities an interpretation of Accounting Research Bulletin (ARB) No.
51": FIN 46 requires the primary beneficiary of a variable interest
entity's activities to consolidate the entity. Contracts under which
SDG&E acquires power from generation facilities otherwise unrelated to
SDG&E could result in a requirement for SDG&E to consolidate the entity
that owns the facility. SDG&E is in the process of determining whether
it has any such situations and, if so, gathering the information that
would be needed to perform the consolidation. The effects of this, if
any, are not expected to significantly affect the financial position of
SDG&E and there would be no effect on results of operations or
liquidity.

NOTE 3. COMPREHENSIVE INCOME

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

Quarters
ended
March 31,
-----------------
(Dollars in millions) 2004 2003
- ------------------------------------------------
Net income $ 51 $ 47

Minimum pension liability
adjustments -- (6)
-----------------
Comprehensive income $ 51 $ 41
- ------------------------------------------------

NOTE 4. FINANCIAL INSTRUMENTS

As described in Note 8 of the notes to Consolidated Financial
Statements in the Annual Report, the company follows the guidance of
SFAS 133 as amended by SFAS 138 and 149 (collectively SFAS 133) to
account for its derivative instruments and hedging activities.
Derivative instruments and related hedges are recognized as either
assets or liabilities on the balance sheet, measured at fair value.

SFAS 133 provides for hedge accounting treatment when certain criteria
are met. For derivative instruments designated as fair value hedges,
the gain or loss is recognized in earnings in the period of change
together with the offsetting gain or loss on the hedged item
attributable to the risk being hedged. For derivative instruments
designated as cash flow hedges, the effective portion of the derivative
gain or loss is included in other comprehensive income, but not
reflected in the Statements of Consolidated Income until the
corresponding hedged transaction is settled. The ineffective portion is
reported in earnings immediately.

The company utilizes natural gas and energy derivatives to manage
commodity price risk associated with servicing its load requirements.
These contracts allow the company to predict with greater certainty the
effective prices to be received by the company and the prices to be
charged to its customers. The company also periodically enters into
interest-rate swap agreements to moderate exposure to interest-rate
changes and to lower the overall cost of borrowing. The use of
derivative financial instruments is subject to certain limitations
imposed by company policy and regulatory requirements. The company
classifies its forward contracts as follows:

Contracts that meet the definition of normal purchase and sales
generally are long-term contracts that are settled by physical delivery
and, therefore, are eligible for the normal purchases and sales
exception of SFAS 133. The contracts are accounted for under accrual
accounting and recorded in Revenues or Cost of Sales on the Statements
of Consolidated Income when physical delivery occurs. Due to the
adoption of SFAS 149, the company has determined that its natural gas
contracts entered into after June 30, 2003 generally do not qualify for
the normal purchases and sales exception. However, the effect of this
is minimal.

Fixed-priced Contracts and Other Derivatives

Fixed-priced Contracts and Other Derivatives on the Consolidated
Balance Sheets primarily reflect SDG&E's unrealized gains and losses
related to long-term delivery contracts for purchased power and natural
gas transportation. SDG&E has established offsetting regulatory assets
and liabilities to the extent that these gains and losses are
recoverable through future rates. If gains and losses are not
recoverable or payable through future rates, the company applies hedge
accounting if certain criteria are met. When a contract no longer meets
the requirements of SFAS 133, the unrealized gains and losses and the
related regulatory asset or liability will be amortized over the
remaining contract life.

The changes in Fixed-price Contracts and Other Derivatives on the
Consolidated Balance Sheets for the quarter ended March 31, 2004 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 quarters ended March 31, 2004 and 2003.

NOTE 5. REGULATORY MATTERS

ELECTRIC INDUSTRY REGULATION

The restructuring of California's electric utility industry has
significantly affected the company's electric utility operations. In
addition, the power crisis of 2000-2001 caused the California Public
Utilities Commission (CPUC) to adjust its plan for restructuring the
electricity industry. The backgrounds of these issues are described in
the Annual Report.

The California Department of Water Resources' (DWR) operating agreement
with SDG&E, approved by the CPUC, 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 responsibility associated with
these activities continues to reside with the DWR. Therefore, the
revenues and costs associated with the contracts are not included in the
Statements of Consolidated Income.

SDG&E's 20-year resource plan identifies the near-term need for
capacity resources within its service territory to support transmission
grid reliability. An updated long-term resource plan will be filed
during the summer of 2004 in a CPUC proceeding which will consider
utility resource planning, such as energy efficiency, contracted power,
demand response, qualifying facilities, renewable generation and
distributed generation. However, in order to satisfy SDG&E's recognized
near-term need for grid reliability capacity, in May 2003 SDG&E issued
a Request for Proposals (RFP) for the years 2005-2007 for 69 megawatts
(MW) in 2005 increasing to 291 MWs in 2007.

As a result of its RFP, in October 2003, SDG&E filed a motion
requesting CPUC authorization to enter into five new electric resource
contracts (including two under which SDG&E would take ownership of new
generating assets, one of which is being developed by Sempra Energy
Resources, an affiliate), as more fully described in the Annual Report.
Hearings concluded on February 20, 2004. Two draft decisions were
issued on April 6, 2004, one by the Administrative Law Judge (ALJ) and
an Alternate Draft by the Assigned Commissioner. Both draft decisions
would approve all five proposed contracts. The Assigned Commissioner's
Alternate Draft would also grant SDG&E's cost recovery, ratemaking and
revenue requirement proposals for the proposed resources, including a
return on equity (ROE) for SDG&E's new generation investments that is
50-basis points higher than SDG&E's ROE on distribution assets, an
equity offset for the debt equivalency of purchase power contracts, and
an equity buildup for construction. The CPUC may adopt all or part of
the proposed decisions as written, or amend or modify them. Only when
the CPUC acts does a decision become binding and final. The CPUC is
expected to issue a final decision in the late spring of 2004. Given
the CPUC's prior denial of the company's request for approval of
additional transmission facilities, the company believes that customer
requirements for electricity could not be met without the requested
resources or similar additions.

NATURAL GAS INDUSTRY RESTRUCTURING

As discussed in the Annual Report, in December 2001 the CPUC issued a
decision related to natural gas industry restructuring (GIR), with
implementation anticipated during 2002. On April 1, 2004, after many
delays and changes, the CPUC issued a decision that adopts tariffs to
implement the 2001 decision. However, by that same decision, the CPUC
stayed implementation of the GIR tariffs until it issues a decision in
Phase I of the Natural Gas Market Order Instituting Ratemaking (OIR)
(see below). At that time, the CPUC will reconcile the GIR market
structure with whatever structure results from the Phase I decision of
the Gas Market OIR.

NATURAL GAS MARKET OIR

The Natural Gas Market OIR was approved on January 22, 2004, and will
be addressed in two concurrent phases. The schedule calls for a Phase I
decision by summer 2004 and a Phase II decision by the end of 2004.
Further discussion of Phase I and Phase II is included in the Annual
Report. The focus of the Gas OIR is 2006 to 2016. Since GIR (see above)
would end in August 2006 and there is overlap between GIR and the Gas
OIR issues, a number of parties (including SoCalGas) advised the CPUC
not to implement GIR.

The California Utilities have made comprehensive filings in the Gas OIR
outlining a proposed market structure that will help create access to
new natural gas supply sources (such as LNG) for California. In the
Phase I filing, SoCalGas and SDG&E proposed a framework to provide firm
tradable access rights for intrastate natural gas transportation;
provide SoCalGas with continued balancing account protection for
intrastate transmission and distribution revenues, thereby eliminating
throughput risk; and integrate the transmission systems of SoCalGas and
SDG&E so as to have common rates and rules. The California Utilities
have proposed that the investments necessary to access new sources of
supply be included in rate base. The estimated costs of these system
enhancements to access as much as 2 billion cubic feet per day of new
supplies are $200 million.

In addition, the California Utilities have filed a recommended
methodology and framework to be used by the CPUC for granting pre-
approval of new interstate transportation agreements. They expect to
receive a CPUC decision approving a methodology during the third
quarter of 2004.

COST OF SERVICE FILINGS

In 2002, the California Utilities filed Cost of Service applications
with the CPUC, seeking rate increases reflecting forecasts of 2004
capital and operating costs, as further discussed in the Annual Report.
SDG&E is requesting revenue increases of $76 million. On December 19,
2003, settlements were filed with the CPUC for SDG&E that, if approved,
would resolve most of the cost of service issues. A CPUC decision is
likely in the second quarter of 2004. The SDG&E settlement would reduce
its electric rate revenues by $19.6 million from 2003 rate revenues and
increase its natural gas rate revenues by $1.8 million from 2003 rate
revenues. A CPUC order has provided that the new rates will be
retroactive to January 1, 2004. Beginning in the first quarter of 2004,
SDG&E is recognizing revenues consistent with the proposed settlements.

SDG&E is also awaiting the CPUC decision on the Cost of Service
application of Southern California Edison (Edison). This decision will
set rates for San Onofre Nuclear Generating Station (SONGS), 20 percent
of which is owned by SDG&E. As discussed in the Annual Report, SDG&E's
SONGS ratebase restarted at $0 on January 1, 2004 and, therefore,
SDG&E's earnings from SONGS will generally be limited to a return on
new capital additions. Edison has applied for permission to replace
SONGS' steam generator, which would increase the total cost of SONGS by
an estimated $800 million ($160 million for SDG&E). SDG&E has raised
objections at the CPUC and at the San Diego Superior Court, intended to
compel Edison to declare an operating impairment as the basis for the
expenditure. Under the terms of the ownership agreement, determination
that an operating impairment exists will allow SDG&E to not participate
in the project, which would proceed without SDG&E, and SDG&E's
ownership percentage in SONGS would be reduced. A pre-hearing
conference is scheduled for May 18, 2004.

SDG&E has also filed for continuation through 2004 of existing
performance-based regulation (PBR) mechanisms for service quality and
safety that would otherwise expire at the end of 2003. In January 2004,
the CPUC issued a decision that extended 2003 service and safety
targets through 2004, but deferred action on applying any rewards or
penalties for performance relative to these targets to a decision to be
issued later in 2004 in a second phase of these applications. On April
2, 2004, the CPUC's Office of Ratepayers Advocates (ORA) filed its
report recommending that a Consumer Price Index with no productivity
factor or customer growth factor be used to change the California
Utilities' base margin, as opposed to the proposed Margin per Customer
proposal of the California Utilities, and that the pending decision be
in effect for five years. The ORA also proposed the possibility of
performance penalties, without the possibility of performance awards.
Hearings are scheduled for June 2004 with a final decision expected by
November 2004.

PERFORMANCE-BASED REGULATION

To promote efficient operations and improved productivity and to move
away from reasonableness reviews and disallowances, the CPUC adopted
PBR for SDG&E effective in 1994. As further described in the Annual
Report, under PBR, regulators require future income potential to be
tied to achieving or exceeding specific performance and productivity
goals, rather than relying solely on expanding utility plant to
increase earnings. PBR and demand-side management (DSM) rewards are not
included in the company's earnings before CPUC approval is received.
The cumulative amount of rewards subject to refund based on the outcome
of the Border Price Investigation described below is $6.7 million at
March 31, 2004.

At March 31, 2004, the following performance incentives were pending
CPUC approval and, therefore, were not included in the company's
earnings (dollars in millions):

Program
-----------------------------------
DSM/Energy Efficiency* $ 35.6
2003 Distribution PBR 8.2
Natural gas PBR Year 10** 1.9
-----------------------------------
Total $ 45.7
-----------------------------------
* Dollar amounts shown do not include interest, franchise fees or
uncollectible amounts.

**On March 15, 2004, the ORA recommended a modified reward of
$1.5 million.

COST OF CAPITAL

Effective January 1, 2003, SDG&E's authorized rate of return on equity
(ROE) is 10.9 percent and its return on ratebase is 8.77 percent, for
SDG&E's electric distribution and natural gas businesses. The electric-
transmission cost of capital is determined under a separate FERC
proceeding discussed below. As discussed in the Annual Report, these
rates will continue to be effective until market interest-rate changes
are large enough to trigger an automatic adjustment or until the CPUC
orders a periodic review. The double-A utility bond yield must average
less than 6.24 percent or greater than 8.24 percent during the April-
September timeframe of any given year to trigger an automatic
adjustment. The double-A utility bond yield averaged 6.30 percent
during the first three weeks of April 2004.

BIENNIAL COST ALLOCATION PROCEEDING

The BCAP determines the allocation of authorized costs between
customer classes for natural gas transportation service provided by
the company and adjusts rates to reflect variances in customer demand
as compared to the forecasts previously used in establishing
transportation rates. SDG&E filed with the CPUC its 2005 BCAP
application in September 2003, requesting updated transportation rates
effective January 1, 2005. In November 2003, an Assigned Commissioner
Ruling delayed the BCAP applications until a decision is issued in the
GIR implementation proceeding. As a result of the April 1, 2004
decision on GIR implementation as described in "Natural Gas Industry
Restructuring," the ALJ in the 2005 BCAP issued a ruling suspending
the BCAP schedule pending CPUC dismissal of the applications. It is
not known at this time when the California Utilities would be required
to file new BCAP applications.

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 border between March 2000 and May
2001. If the investigation determines that the conduct of any party to
the investigation, including the California Utilities, contributed to
the natural gas price spikes, the CPUC may modify the party's natural
gas procurement incentive mechanism, reduce the amount of any
shareholder award for the period involved, and/or order the party to
issue a refund to ratepayers. Hearings are scheduled to begin on June
14, 2004. At a later date, the CPUC will hold a second round of
hearings to consider whether Sempra Energy or any of its non-utility
subsidiaries contributed to the price spikes. Decisions are expected
by late 2004. The company believes that the CPUC will find that the
California Utilities acted in the best interests of its core customers
and that none of the Sempra Energy companies was responsible for the
price spikes.

CPUC INVESTIGATION OF COMPLIANCE WITH AFFILIATE RULES

In February 2003, the CPUC opened an investigation of the business
activities of SDG&E, SoCalGas and Sempra Energy to determine if they
have complied with statutes and CPUC decisions in the management,
oversight and operations of their companies. In September 2003, the
CPUC suspended the procedural schedule until it completes an
independent audit to evaluate energy-related holding company systems
and affiliate activities undertaken by Sempra Energy within the service
territories of SDG&E and SoCalGas. The audit, covering years 1997
through 2003, is expected to be completed by March 2005. The scope of
the audit will be broader than the annual affiliate audit. 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.

CPUC INVESTIGATION OF ENERGY-UTILITY HOLDING COMPANIES

The CPUC has initiated an investigation into the relationship between
California's investor-owned utilities (IOUs) and their parent holding
companies. The CPUC broadly determined that it would require the
holding company to provide cash to a utility subsidiary to cover its
operating expenses and working capital to the extent they are not
adequately funded through retail rates. This would be in addition to
the requirement of holding companies to cover their utility
subsidiaries' capital requirements, as the IOUs previously acknowledged
in connection with the holding companies' formations. In January 2002
the CPUC ruled on jurisdictional issues, deciding that the CPUC had
jurisdiction to create the holding company system and, therefore,
retains jurisdiction to enforce conditions to which the holding
companies had agreed. The company's request for rehearing on the issues
was denied by the CPUC and the company subsequently filed appeals in
the California Court of Appeal. Oral argument was held on March 5, 2004
before the First District Court of Appeal and a written opinion from
the Court is expected by June 2004.

RECOVERY OF CERTAIN DISALLOWED TRANSMISSION COSTS

In August 2002 the Federal Energy Regulatory Commission (FERC) issued
Opinion No. 458, which effectively disallowed SDG&E's recovery of the
differentials between certain payments to SDG&E by its co-owners of the
Southwest Powerlink (SWPL) under the Participation Agreements and
charges assessed to SDG&E under the California Independent System
Operator (ISO) FERC tariff for transmission line losses and grid
management charges related to energy schedules of Arizona Public
Service Co. (APS) and the Imperial Irrigation District (IID), its SWPL
co-owners. As a result, SDG&E is incurring unreimbursed costs of $4
million to $8 million per year. On November 17, 2003, SDG&E petitioned
the United States Court of Appeals for review of this FERC order and
argued that the disallowed costs should be allowed for recovery through
the Transmission Revenue Balancing Account Adjustment. On February 12,
2004, on the FERC's motion, the court remanded the case back to the
FERC for further consideration, "based on the FERC's representation
that it intends to act expeditiously on remand." The FERC has not yet
issued further orders in this matter.

On July 6, 2001, in a separate matter related to ISO charges giving
rise to most of the cost differentials described above, SDG&E filed an
arbitration claim against the ISO, claiming the ISO should not charge
SDG&E for the transmission losses attributable to energy schedules on
the APS and the IID shares of the SWPL. On October 23, 2003, the
independent arbitrator found in SDG&E's favor, awarding to SDG&E all
amounts claimed, which totaled $22 million, including interest, as of
the time of the award. The ISO appealed this result to the FERC and a
FERC decision is expected in 2004. 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. On April 6, 2004, the ISO filed its
reply brief to SDG&E's brief and the matter was submitted to the FERC.
In addition, APS, IID and Edison filed briefs in support of SDG&E's
arbitration award.

In addition, on January 23, 2004, the FERC denied rehearing of its
Opinion No. 463, which upheld the ISO's grid management charges billed
to SDG&E for the APS and IID SWPL energy schedules. This rehearing
order did require the ISO to refund amounts of such charges covered by
SDG&E self-supply of imbalance energy. Pursuant to this order, the ISO
issued its refund report on February 23, 2004, calculating the refunds
due SDG&E at $320,000. On March 15, 2004, SDG&E protested the ISO's
refund report, claiming refunds of $3.3 million, before interest. A
FERC decision on the refunds is expected later in 2004. In addition, on
March 22, 2004, SDG&E petitioned the United States Court of Appeals for
review of these FERC orders and will argue that the ISO lacks authority
under its tariff to assess grid management charges on the subject SWPL
schedules. The court has not yet scheduled briefing or argument in
this matter.

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 additional instructions, and ordered the ISO and PX
to recalculate the precise number through their settlement models.
California is seeking $8.9 billion in refunds from its electricity
suppliers and has appealed the FERC's preliminary findings and
requested rehearing of the March 26 order. In March 2004, the Attorney
General of California requested the Ninth Circuit Court of Appeals to
compel the FERC to comply with the Court's earlier orders, contending
that the FERC had violated an August 2002 court order that should have
resulted in larger refunds to California and that the FERC had failed
to properly weigh evidence of market manipulation by power companies
when deciding the refunds due California ratepayers.

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 and the FERC resolved
the matter by SDG&E's paying $28 thousand into a FERC-established fund.

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 the purpose of
investigating economic withholding, the FERC used an initial screen of
all bids exceeding $250 per megawatt between May 1, 2000 and October 2,
2001. SDG&E has received data requests from the FERC staff and has
provided responses. The FERC staff will prepare a report to the FERC,
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, the FERC staff issued an initial report
that determined there was no need to further investigate particular
entities for physical withholding of generation.

NOTE 6. CONTINGENCIES

NUCLEAR INSURANCE

SDG&E and the other owners of SONGS have insurance to respond to
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 $10.5 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 a default was to occur by any other SONGS owner. In the
event the secondary financial protection limit were 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 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/replacement power 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.
There is a deductible waiting period of 12 weeks prior to receiving
indemnity payments. 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
$8.5 million.

Both the nuclear liability and property insurance programs subscribed
to by members of the nuclear power generating industry include industry
aggregate limits for non-certified acts, as defined by the Terrorism
Risk Insurance Act, of terrorism-related SONGS losses, including
replacement power costs. An industry aggregate limit of $300 million
exists for liability claims, regardless of the number of non-certified
acts affecting SONGS or any other nuclear energy liability policy or
the number of policies in place. An industry aggregate limit of $3.24
billion exists for property claims, including replacement power costs,
for non-certified acts of terrorism affecting SONGS or any other
nuclear energy facility property policy within twelve months from the
date of the first act. These limits are the maximum amount to be paid
to members who sustain losses or damages from these non-certified
terrorist acts.

LITIGATION

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

Antitrust Litigation

Class-action and individual lawsuits filed in 2000 and currently
consolidated in San Diego Superior Court seek 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 (whose cases involved
additional issues not applicable to Sempra Energy, SoCalGas or SDG&E)
announced that they had reached a $1.5 billion settlement, of which
$125 million is allocated to customers of the California Utilities. The
Court approved that settlement in December 2003. The proceeding
against Sempra Energy and the California Utilities has not been
settled, is currently in discovery and continues to be litigated.

Natural Gas Cases: Similar lawsuits have been filed by the Attorneys
General of Arizona and Nevada, alleging that El Paso and certain Sempra
Energy subsidiaries unlawfully sought to control the natural gas market
in their respective states. In October 2003, the Nevada state court
denied defendants' motion to dismiss the complaint. On April 12, 2004,
the Sempra Energy defendants filed a motion for reconsideration. 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 Sempra Energy 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. On January 27, 2004, the U.S. District Court
dismissed the Sierra Pacific Resources case against all of the
defendants, determining that this is a matter for the FERC. Plaintiffs
have asked the court to reconsider its decision.

Electricity Cases: Various lawsuits, which seek class-action
certification, allege that Sempra Energy and certain 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. Oral argument has not yet been scheduled by
the Court. SDG&E and two other subsidiaries of Sempra Energy, along
with all other sellers in the western power market, have been named
defendants in a complaint filed at the FERC by the California Attorney
General's office seeking refunds for electricity purchases based on
alleged violations of FERC tariffs. The FERC has dismissed the
complaint. The California Attorney General has filed an appeal in the
Ninth Circuit of Appeals. The matter was argued before the Ninth
Circuit Court in October 2003. No decision has yet been rendered.

Other

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. The Utility
Consumers' Action Network, a consumer-advocacy group which had requested
the CPUC rehearing, appealed the decision to the California Court of
Appeals and the court agreed to hear the case. Oral argument has not yet
been scheduled by the Court. The company expects that the Court of
Appeals will affirm the CPUC's decision.

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 decreased to $385 million in 2004 from $397 million
in 2003, and the cost of electric fuel and purchased power decreased to
$127 million in 2004 from $163 million in 2003. These changes were
mainly due to decreases in electric commodity costs partially offset by
higher volumes. Under the current regulatory framework, changes in
commodity costs normally do not affect net income. During 2004 and
2003, revenues and costs associated with long-term contracts allocated
to SDG&E from the DWR were not included in the income statement, since
the DWR retains legal and financial responsibility for these contracts.

Natural gas revenues increased $195 million in 2004 from $165 million
in 2003, and the cost of natural gas distributed increased to $109
million in 2004 from $85 million in 2003. These changes were primarily
attributable to natural gas cost increases, which are passed on to
customers.

Under the current regulatory framework, the cost of natural gas
purchased for customers and the variations in that cost are passed
through to the customers on a substantially concurrent basis. However,
SDG&E's natural gas procurement Performance-Based Regulation (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 quarters ended March 31, 2004 and
2003.

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

Although commodity-related revenues 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)

Other operating expenses increased to $140 million in 2004 from $126
million in 2003 due to higher labor and employee benefit costs and
nuclear refueling costs at SONGS.

Net income for SDG&E increased to $51 million in 2004 compared to $47
million in 2003, primarily due to higher transmission and distribution
revenue offset partially by higher operating costs and the absence of
the 2003 Incremental Cost Incentive Pricing for SONGS and performance-
based regulation gains.

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 March 31, 2004, the company had $71 million in cash and $300 million
in available unused, committed lines of credit.

Management believes that cash flows from operations and debt issuances
will be adequate to finance capital expenditure requirements and other
commitments. Management continues to regularly monitor the company's
ability to finance the needs of its operating, financing and investing
activities in a manner consistent with its intention to maintain strong,
investment-quality credit ratings.

CASH FLOWS FROM OPERATING ACTIVITIES

Net cash provided by operating activities totaled $141 million and $106
million for the quarters ended March 31, 2004 and 2003, respectively.
The increase was mainly due to lower accounts receivable in 2004 and
higher tax payments in 2003, partially offset by lower accounts payable
in 2004.

For the quarter ended March 31, 2004, the company made no pension plan
contributions for the 2004 plan year.

CASH FLOWS FROM INVESTING ACTIVITIES

Net cash (used in) provided by investing activities totaled $(71)
million and $46 million for the quarters ended March 31, 2004 and 2003,
respectively. The change was primarily due to the repayment of $138
million of an intercompany loan by Sempra Energy in 2003.

Significant capital expenditures in 2004 are expected to be for
additions to the company's natural gas and electric distribution
systems. These expenditures are expected to be financed by cash flows
from operations and security issuances.

In connection with the importation of additional sources of natural gas
into Southern California, for which the California Utilities have made
filings with the CPUC, the California Utilities could incur capital
expenditures estimated at $200 million in order to connect with new
delivery locations. The expenditures would be included in utility rate
bases.

In addition to its normal capital expenditures related to its
distribution and transmission systems and its share of the additional
$200 million referred to above, SDG&E expects to be making significant
capital expenditures for the proposed generation resources referred to
in Note 5 of the notes to Consolidated Financial Statements.

CASH FLOWS FROM FINANCING ACTIVITIES

Net cash used in financing activities totaled $147 million and $70
million for the quarters ended March 31, 2004 and 2003, respectively.
The change was due to higher dividends paid to Sempra Energy in 2004.

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 matters, including the
pending cost of service filings and the CPUC's investigation of
compliance with affiliate rules are discussed in the Annual Report and
in Note 5 of the notes to Consolidated Financial Statements herein.

CRITICAL ACCOUNTING POLICIES AND KEY NON-CASH PERFORMANCE INDICATORS

There have been no significant changes to the accounting policies
viewed by management as critical or key non-cash performance indicators
for the company's subsidiaries, as set forth in the Annual Report.

NEW ACCOUNTING STANDARDS

Relevant pronouncements that have recently become effective and have
had a significant effect on the company are SFAS Nos. 143, 149 and 150,
as discussed in Note 2 of the notes to Consolidated Financial
Statements. Pronouncements that have or are likely to have a material
effect on future earnings are described below.

SFAS 143, "Accounting for Asset Retirement Obligations": SFAS 143
requires entities to record the fair value of liabilities for legal
obligations related to asset retirements in the period in which they
are incurred. It also requires the company to reclassify amounts
recovered in rates for future removal costs not covered by a legal
obligation from accumulated depreciation to a regulatory liability.
Further discussion is provided in Note 2 of the notes to Consolidated
Financial Statements.

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.
Under SFAS 149 natural gas forward contracts that are subject to
unplanned netting do not qualify for the normal purchases and normal
sales exception. The company has determined that all natural gas
contracts are subject to unplanned netting and as such, these contracts
will be marked to market. In addition, effective January 1, 2004, power
contracts that are subject to unplanned netting and that do not meet
the normal purchases and normal sales exception under SFAS 149 will be
further marked to market. Implementation of SFAS 149 on July 1, 2003
did not have a material impact on reported net income.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT 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 March 31, 2004, the total Value at Risk of SDG&E's 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 March 31, 2004 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 over
financial reporting or in other factors that could significantly affect
the internal controls subsequent to the date the company completed its
evaluation.

ITEM 5. OTHER INFORMATION

Effective May 1, 2004, Debra L. Reed, President of SoCalGas and SDG&E,
also will become their Chief Operating Officer. Simultaneously, Steven
D. Davis, who remains Senior Vice President, External Relations, will
succeed her as Chief Financial Officer.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

SDG&E has been advised by the County of San Diego that the county is
considering initiating legal proceedings against SDG&E relating to
alleged environmental law violations by SDG&E and its contractors in
connection with the abatement of asbestos-containing materials during
the demolition of a natural gas storage facility that was completed in
2001. SDG&E disputes the county's allegations and believes that the
abatement of these materials was properly managed. The county has
indicated a willingness to settle this matter for less than $1 million.

Except as described above and in Notes 5 and 6 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 December 31, 2003:

Current Report on Form 8-K filed February 24, 2004, filing as an exhibit
Sempra Energy's press release of February 24, 2004, giving the financial
results for the quarter ended December 31, 2003.

Current Report on Form 8-K filed April 29, 2004, filing as an exhibit
Sempra Energy's press release of April 29, 2004, giving the financial
results for the quarter ended March 31, 2004.

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: April 29, 2004 By: /s/ D.L. Reed
-----------------------------
D.L. Reed
President and
Chief Financial Officer