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, 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
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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 No X
----- -----

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

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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 and other
regulatory bodies in the United States; capital market conditions,
inflation rates, interest rates and exchange rates; energy and trading
markets, including the timing and extent of changes in commodity
prices; the availability of natural gas; weather conditions and
conservation efforts; war and terrorist attacks; business, regulatory,
environmental and legal decisions and requirements; 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.

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PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS.

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

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

5

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

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

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

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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 changes in classification have been
made to prior presentations to conform to the current financial
statement presentation. Specifically, 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) and the Quarterly Reports on Form 10-Q
for the first and second quarters of 2004.

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. The proposed statement
would eliminate the choice of accounting for share-based compensation
transactions using Accounting Principles Board (APB) Opinion No. 25,
Accounting for Stock Issued to Employees, whereby no expense is
recorded for most stock options, and instead would require that such
transactions be accounted for using a fair-value-based method, whereby
expense is recorded for stock options. It would also prohibit
application by restating prior periods and would require that expense
ultimately be recognized only for those options that actually vest. A

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final statement is expected to be issued in the fourth quarter of 2004
and be effective July 1, 2005.

SFAS 132 (revised 2003), "Employers' Disclosures about Pensions and
Other Postretirement Benefits": This statement revises required
disclosures about employers' pension plans and other postretirement
benefit plans, effective in 2004. It requires disclosures beyond those
in the original SFAS 132 related to the assets, obligations, cash flows
and net periodic benefit cost of defined benefit pension plans and
other defined postretirement benefit plans. In addition, it 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
three and nine months ended September 30:

Note 6 of the notes to Consolidated Financial Statements in the Annual
Report discusses the company's expected contribution to its pension

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plan and other postretirement benefit plans in 2004. $3 million and $5
million of contributions have been made to its other postretirement
benefit plan for the three and nine months ended September 30, 2004,
respectively. There was no contribution made to its pension plan for
the nine months ended September 30, 2004.

FASB Staff Position (FSP) 106-2, "Accounting and Disclosure
Requirements Related to the Medicare Prescription Drug, Improvement and
Modernization Act of 2003": In December 2003, the Medicare Prescription
Drug, Improvement and Modernization Act of 2003 (the "Act") was
enacted. The Act establishes a prescription drug benefit under
Medicare, known as "Medicare Part D," and a tax-exempt federal subsidy
to sponsors of retiree health care benefit plans that provide a benefit
that actuarially is at least equivalent to Medicare Part D.

In May 2004, the FASB issued FSP 106-2 which requires that the effects
of the federal subsidy be considered an actuarial gain and be
recognized in the same manner as other actuarial gains and losses. In
addition, FSP 106-2 requires certain disclosures for employers that
sponsor postretirement health care plans that provide prescription drug
benefits. During the third quarter of 2004, the company adopted FSP
106-2 retroactive to the beginning of the year. The company and its
actuarial advisors determined that benefits provided to certain
participants will actuarially be at least equivalent to Medicare Part
D, and, accordingly, the company will be entitled to an expected tax-
exempt subsidy that reduces the company's accumulated postretirement
benefit obligation under the plan at January 1, 2004 by $3 million and
net periodic benefit cost for 2004 by an immaterial amount.

SFAS 143, "Accounting for Asset Retirement Obligations": Beginning in
2003, SFAS 143 requires entities to record liabilities for future costs
expected to be incurred when assets are retired from service, if the
retirement process is legally required. It also requires the
reclassification of estimated removal costs, which have historically
been recorded in accumulated depreciation, to a regulatory liability.
At September 30, 2004 and December 31, 2003, the estimated removal
costs recorded as a regulatory liability were $882 million and $846
million, respectively.

The change in the asset retirement obligations for the nine months
ended September 30, 2004 is as follows (dollars in millions):

Balance as of January 1, 2004 $ 326
Accretion expense (interest) 17
Payments (9)
------
Balance as of September 30, 2004 $ 334*
======

* The current portion of the obligation is included in Other Current
Liabilities on the Consolidated Balance Sheets.

In June 2004, the FASB issued a proposed interpretation, Accounting for
Conditional Asset Retirement Obligations, an interpretation of FASB
Statement No. 143. The interpretation would clarify that a legal
obligation to perform an asset retirement activity that is conditional
on a future event is within the scope of SFAS 143. Accordingly, the

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interpretation would require an entity to recognize a liability for a
conditional asset retirement obligation if the liability's fair value
can be reasonably estimated. The proposed interpretation would be
effective for the company on December 31, 2005.

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 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, whereby
derivatives are not required to be marked to market when the contract
is usually settled by the physical delivery of natural gas. ("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.) The company has
determined that all natural gas contracts are subject to unplanned
netting and as such, these contracts are 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 are 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.

FASB Interpretation No. (FIN) 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees": The company has a residual
value guarantee under a fleet lease arrangement. As of September 30,
2004, the company had no liabilities recorded for the fleet lease
guarantee due to the immaterial amount of the estimated fair value of
such guarantee.

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.
As permitted by the interpretation, SDG&E is continuing 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.

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NOTE 3. 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) 2004 2003 2004 2003
- -----------------------------------------------------------------
Net income $ 62 $ 121 $ 144 $ 210

Minimum pension liability
adjustments -- -- -- (6)*
-----------------------------------
Comprehensive income $ 62 $ 121 $ 144 $ 204
- -----------------------------------------------------------------

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

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 hedged items 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. Any 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 or paid 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.

Contracts that meet the definition of normal purchases 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

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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 September 30, 2003 generally do not
qualify for the normal purchases and sales exception and, accordingly,
are marked to market. However, the effect of this is minimal.

Fixed-price Contracts and Other Derivatives

Fixed-price Contracts and Other Derivatives on the Consolidated Balance
Sheets primarily reflect the company's unrealized gains and losses
related to long-term delivery contracts for purchased power and natural
gas transportation. The company has established offsetting regulatory
assets and liabilities to the extent that these gains and losses are
included in the calculation of future rates. If gains and losses are
not recoverable or payable through future rates, the company applies
hedge accounting if certain criteria are met. If 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 nine months ended September 30,
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 nine months ended September 30, 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 energy crisis of 2000-2001 caused the California Public
Utilities Commission (CPUC) to adjust its plan for restructuring the
electricity industry. The background of these issues is described in
the Annual Report.

At September 30, 2004, the AB 265 Undercollection had been reduced to
$23 million and SDG&E expects that the undercollection will be
eliminated by the end of 2004.

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.

In October 2003, the CPUC initiated a proceeding to consider a
permanent methodology for allocating the DWR's revenue requirement
beginning in 2004 through the remaining life of the DWR contracts. An
interim allocation based on the current 2003 methodology was utilized

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beginning January 1, 2004, and will remain in effect until a decision
is reached on a permanent methodology. In April 2004, Southern
California Edison (Edison), Pacific Gas & Electric (PG&E) and a
northern California consumer advocacy group proposed a limited joint
settlement to allocate the DWR revenue requirement among the investor-
owned utilities (IOUs). This settlement proposes to shift more than $1
billion in additional costs to SDG&E customers and would have a
negative impact on customers' commodity costs over the remaining eight-
year life of the DWR contracts. On July 19, 2004, the CPUC issued a
proposed decision and an alternate decision recommending permanent
allocations of DWR contract costs to the IOUs. These proposals were
revised and third and fourth alternate decisions were issued on
September 9, 2004. None of the proposed or alternate decisions would
adopt the settlement; instead, they would permanently allocate a
percentage of the fixed or above market costs of the contracts to SDG&E
for the remaining life of the contracts (2004-2013). The CPUC is
expected to address this matter at its meeting on November 19, 2004.

The judge's proposed decision and Commissioner Lynch's alternate
decision would allocate 12.5 percent of the fixed costs of the
contracts for the remaining term, resulting in a total shift of $1
billion to SDG&E customers. Commissioner Brown's alternate decision
determines SDG&E's share of the above-market costs for all contracts
for all years to be 9.9 percent, resulting in a total shift of $787
million. Commissioner Peevey's alternate decision would allocate 10.3
percent of the fixed costs of the contracts to SDG&E, resulting in a
total shift of $425 million.

Although these proposed decisions would have no effect on SDG&E's net
income, they could adversely affect its customer rates and SDG&E's cash
flows. In the near term the effect on SDG&E's cash flows would be
minor, but could become significant in the later years unless rate
ceilings, imposed by Assembly Bill 1X, which freeze total rates for
most residential customers at the February 2001 level, were increased
to provide more-contemporaneous recovery. Until January 1, 2006, state
law provides SDG&E with a recovery triggering mechanism when an over or
undercollection exceeds approximately $30 million. If the triggering
mechanism is not extended, the CPUC will have discretion on when to act
on over and undercollections.

SDG&E's long-term resource plan identifies the forecasted needs for
capacity resources within its service territory to support transmission
grid reliability. An updated 10-year resource plan was filed on July 9,
2004, in a CPUC proceeding to consider utility resource planning,
including energy efficiency, contracted power, demand response,
qualifying facilities, renewable generation and distributed generation.
SDG&E's updated long-term resource plan incorporates the resources
approved by the CPUC that are discussed below, and recognizes updated
goals to reach a 20-percent renewable resources target by 2010. The
updated plan recommends a 500-kV transmission line addition in 2010,
which would be processed for approval in a subsequent CPUC proceeding.

In order to satisfy SDG&E's recognized near-term need for grid
reliability and capacity, in May 2003 SDG&E issued a Request for
Proposals for the years 2005-2007 for at least 69 MW of electric
capacity in 2005 increasing to 291 MW in 2007.

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On June 9, 2004, the CPUC approved SDG&E's entering into five new
electric resource contracts (including two under which SDG&E would take
ownership, on a turnkey basis, of new generating assets, including a
550-MW plant (Palomar) being developed by Sempra Energy Resources, an
affiliate, for completion in 2006), as more fully described in the
Annual Report. An additional, demand-response contract was also
approved. The decision authorized SDG&E to recover the costs of both
contracted resources and turnkey resources, but did not adopt SDG&E's
specific cost recovery, ratemaking and revenue requirement proposals
for the proposed turnkey resources. On July 15, 2004, three parties
filed requests for rehearing of the decision. SDG&E filed its response
on July 30, 2004, opposing the requests. The CPUC is expected to rule
on the requests in the next few months. In September 2004, SDG&E filed
its revenue requirement and ratemaking proposals for the 45-MW
combustion turbine which SDG&E will acquire as a turnkey project (Ramco
facility) and filed for the Palomar facility in November 2004. The
decision did not approve SDG&E's proposals for a return on equity (ROE)
for SDG&E's new generation investments higher than SDG&E's ROE on
distribution assets, an equity offset for the debt equivalency of
purchase power contracts or an equity buildup for construction. These
matters may be re-introduced for consideration in future CPUC
proceedings.

NATURAL GAS MARKET OIR

The CPUC's Natural Gas Market Order Instituting Rulemaking (OIR) was
instituted on January 22, 2004, and will be addressed in two phases. A
decision on Phase I was issued on September 2, 2004 and the schedule
for Phase II calls for a 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 the period from 2006 to 2016. Since Natural
Gas Industry Restructuring (GIR), as discussed in the Annual Report,
would end in August 2006 and there is overlap between GIR and the OIR
issues, a number of parties (including SoCalGas) have requested the
CPUC not to implement GIR.

The California Utilities have made comprehensive filings in the OIR
outlining a proposed market structure that is intended to create access
to new natural gas supply sources (such as liquefied natural gas (LNG))
for California. In their Phase I and Phase II filings, 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 also proposed that the
capital expenditures necessary to access new sources of supply be
included in ratebase and that the total amount of the expenditures
would be $200 million to $300 million.

The California Utilities also proposed a methodology and framework to
be used by the CPUC for granting pre-approval of new interstate
transportation agreements. The Phase I decision approves the California
Utilities' transportation capacity pre-approval procedures with some
modifications. SoCalGas' existing pipeline capacity contract with
Transwestern Pipeline Company expires in November 2005 and its primary
contracts with El Paso Natural Gas Company expire in August 2006.

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Discussions are underway pursuant to the framework approved by the CPUC
to acquire replacement capacity. The Phase 1 decision also directs the
California Utilities to file, by December 2, 2004, an application to
implement proposals for transmission system integration, firm access
rights, and off-system delivery services. The CPUC has determined that
project developers, not the utilities, will be presumed to pay for the
costs for access-related infrastructure, subject to future applications
to be filed when more is known about the particular projects. Phase II
of the Gas Market OIR will review the CPUC's ratemaking policies on
throughput risk to better align these with its objectives of promoting
energy conservation and adequate infrastructure. Phase II will also
investigate the need for emergency natural gas storage reserves and the
role of the utility in backstopping the noncore market.

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 requested revenue increases of $64 million. As previously
reported, in December 2003 SDG&E filed with the CPUC a proposed
settlement of its cost of service proceeding. The settlement, if
approved by the CPUC, would reduce the company's annual rate revenues
by an aggregate net amount of approximately $13 million from the rates
in effect during 2003. The CPUC's Office of Ratepayer Advocates (ORA)
and most other major parties to the cost of service proceedings have
recommended that the CPUC approve the settlement.

On September 28, 2004, the CPUC's Administrative Law Judge (ALJ) and
the CPUC Commissioner assigned to the cost of service proceedings
issued differing proposed decisions for consideration by the CPUC. Both
of these proposed decisions recommend that the CPUC reject the proposed
settlement. The ALJ's proposed decision would, if adopted by the CPUC,
increase annual rate revenues by $16 million from that contemplated by
the settlement but would also adopt a one-way balancing account
requiring that any reductions in operating labor costs from those
estimated in establishing rates be refunded to customers. CPUC
Commissioner Wood's alternate proposed decision, which does not include
a one-way labor balancing account, would, if adopted by the CPUC,
increase the annual rate reduction by an additional $32 million from
that contemplated by the proposed settlement.

The company believes that a factual error relating to its nuclear
electric rate revenues was applied in the proposed decisions of both
the ALJ and Commissioner Wood. The company also believes that
Commissioner Wood's proposed decision contains a depreciation error. If
these errors and other, minor factual errors are corrected, they would
increase the annual rate revenues that would be provided by the ALJ's
proposed decision to $47 million above that contemplated by the
settlement and would increase the annual rate revenues that would be
provided by Commissioner Wood's alternative proposed decision to $16
million above that contemplated by the settlement. Both proposed
decisions would approve balancing accounts for pension costs similar to
those contemplated by the settlement and various other cost balancing
accounts not contemplated by the settlement. All the proposals
contemplate that the rates resulting from the cost of service

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proceedings would remain effective through 2007 subject to annual
attrition adjustments.

The company previously reported that it expects that another CPUC
commissioner will issue an additional proposed decision that, if
adopted by the CPUC, would essentially approve the proposed
settlements. Subsequently, on October 28, 2004, the CPUC at its
regularly scheduled meeting deferred acting on the cost of service
proceedings at the request of Commissioner Brown, who stated that he
would issue an additional proposed decision.

The CPUC may adopt any one of the proposed decisions or reject all of
them and adopt a different outcome. The company expects that a CPUC
decision will be issued by year end.

The CPUC previously ordered that any changes in rates resulting from
the cost of service proceedings would be effective retroactively to
January 1, 2004. Consequently, during 2004 the company has, in general,
recorded revenue and resulting net income in a manner consistent with
the reduced rates contemplated by the proposed settlement, except for
the favorable effect of the recovery of pension costs contemplated by
the proposed settlement and provided by the proposed decisions. To the
extent that the revenues provided by the CPUC's decision in the cost of
service proceedings differ from those previously recorded, a
reconciling adjustment to revenues and resulting net income would be
recorded in the latest quarter for which financial statements had not
been published.

Other ratemaking issues are included in Phase II of the cost of service
proceeding. In addition to recommending changes in the performance-
based regulation (PBR) formulas, the ORA also proposed the possibility
of performance penalties for service quality, safety and electric
service reliability, without the possibility of performance awards.
Hearings took place in June 2004. On July 21, 2004, all of the active
parties in Phase II who dealt with post test year ratemaking and
performance incentives filed for adoption by the CPUC of an all-party
settlement agreement for most of the Phase II issues, including annual
inflation adjustments and revenue sharing. The agreement does not cover
performance incentives. For the interim years of 2005-2007, the
Consumer Price Index would be used to adjust the escalatable authorized
base rate revenues within identified floors and ceilings. It is not
likely that the CPUC will address this matter in its decision related
to Phase II of this proceeding before year-end 2004. Consequently, to
ensure that the results of Phase II would be applicable for a full year
in 2005, SoCalGas and SDG&E filed with the CPUC on September 29, 2004,
a petition to modify a prior decision that provided for the differences
between 2004's rates and the amounts determined in the cost of service
decision to be collected or refunded in future rates, to also apply to
similar differences occurring in 2005 prior to implementation of the
cost of service decision.

SDG&E had filed for continuation of existing 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 did not determine the applicability of
rewards or penalties. As part of the proposed Phase II Settlement
Agreement, Revenue Sharing, under which IOUs return to customers a

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percentage of earnings above specified levels, would be suspended for
2004 and resume for 2005 through 2007. The proposed revenue sharing
mechanism also provides the utility the option to file for suspension
of the earnings sharing mechanism if earnings for two consecutive years
fall 175 basis points or more below its authorized rate of return;
however, if earnings are 300 or more basis points above the utility's
authorized rate of return, the revenue sharing mechanism would be
automatically suspended and trigger a formal regulatory review by the
CPUC to determine whether modification of the ratemaking mechanism is
required.

Edison's CPUC decision on its cost of service application sets 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 are now generally limited to a return on new
capital additions. Edison has applied for permission to replace SONGS'
steam generators, which would increase the total cost of SONGS by an
estimated $800 million ($160 million for SDG&E). SDG&E has the option
of not participating in the project and has informed Edison of its
intention to exercise this option. Doing so would reduce SDG&E's
ownership percentage in SONGS by an amount to be determined in
arbitration and will be subject to CPUC review and approval. Such
approval is expected to occur during late 2005. If the proposed
reduction of SDG&E's ownership percentage resulting from the
arbitration is unacceptable, SDG&E may elect to participate in the
replacement project.

During the current SONGS Unit 3 refueling outage, Edison reported that
it had performed inspections of two pressurizer sleeves and found
evidence of degradation. Degradation of the pressurizer sleeves has
been a concern in the nuclear industry for some time. Edison had been
planning to replace all of the sleeves in Units 2 and 3 during the next
refueling for each unit in 2005 and 2006, but has reported its
intention to move the planned replacement of Unit 3's pressurizer
sleeves forward from 2006 to the current outage. This extra work will
lengthen the current outage from 55 days to a range of 95 to 110 days,
but allows Edison to move the 2006 refueling outage out of the peak
summer period to the fall or winter of 2006. Edison has reported that
it will incur about $9 million of capital expenditures during 2005 that
otherwise would have occurred in 2006. SDG&E's share would be
approximately $2 million. Edison plans to replace the pressurizer
sleeves in Unit 2 during its next scheduled outage in 2005.

Also during the current outage, Edison reported that it had conducted a
planned inspection of the Unit 3 reactor vessel head and found
indications of degradation. Although the degradation is far below the
level at which leakage would occur, Edison plans to make repairs during
the current outage. While Edison reports that this is the first
experience at SONGS of this kind of degradation to the reactor vessel
heads, the detection and repair of similar degradation at other plants
are now common in the industry. Edison reports that it plans to replace
the Unit 2 and Unit 3 reactor vessel heads during refueling outages in
2009-2010.

19

PERFORMANCE-BASED REGULATION

As further described in the Annual Report, under PBR, the CPUC requires
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 only incentive reward approved during the nine months ended
September 30, 2004 consisted of $1.5 million related to SDG&E's Year 10
natural gas PBR, which was approved on August 22, 2004. This reward was
awarded by the CPUC subject to refund based on the outcome of the
Border Price Investigation, as discussed below. The cumulative amount
of rewards subject to refund based on the outcome of the Border Price
Investigation is $8.2 million, all of which has been included in net
income.

At September 30, 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* $ 37.7
2003 Distribution PBR 8.2
-----------------------------------
Total $ 45.9
-----------------------------------

* Dollar amounts shown do not include interest, franchise fees or
uncollectible amounts.

SOUTHERN CALIFORNIA FIRES

Several major wildfires that began on October 26, 2003 severely damaged
SDG&E's infrastructure, causing a significant number of customers to be
without utility services. On October 27, 2003, then governor Gray Davis
declared a State of Emergency for the State of California. The
declaration authorized the establishment of catastrophic event
memorandum accounts (CEMA) to record all incremental costs (costs not
already included in rates) associated with the repair of facilities and
the restoration of service. Incremental electric distribution and
natural gas related costs are recovered through the CEMA. Electric
transmission related costs are recovered through the annual FERC true-
up proceeding. Incremental costs incurred related to the wildfires and
recoverable through the CEMA were $38 million.

On June 28, 2004, SDG&E filed its CEMA application with the CPUC to
recover incremental operating and maintenance and capital costs of its
natural gas and electric distribution systems associated with the
fires. In that application, SDG&E is requesting a 2005 revenue
requirement of $20 million, representing the operating and maintenance
costs of $12 million plus the 2004 and 2005 ongoing annual amounts of
$4 million to recover the $26 million of capital costs and the
authorized return thereon. The company expects no significant effect on

20

earnings from the fires. The ALJ indicated that he expects to issue a
proposed decision by the end of the first quarter of 2005.

COST OF CAPITAL

Effective January 1, 2005, SDG&E's authorized return on rate base (ROR)
and return on equity (ROE) will be 8.18 percent and 10.37 percent,
respectively, for its electric distribution and natural gas businesses,
down from 8.77 percent and 10.9 percent, respectively. The decrease is
a result of the CPUC's automatic triggering mechanism, which resets
these rates whenever Moody's Aa utility bond yield as published by
Mergent Bond Record changes by more than a specified amount. The new
benchmark will be 6.19 percent and another automatic adjustment would
be triggered if the Mergent Aa utility bond yield were to average less
than 5.19 percent or greater than 7.19 percent during the April -
September timeframe of any given year. If the cost of service
proceeding described above is decided by the CPUC along the lines of
the settlement, the effect of the changes in ROR and ROE would be to
decrease net income in 2005 by $10 million from what it would have been
if the rates had not changed. The electric-transmission cost of capital
is determined under a FERC proceeding.

BIENNIAL COST ALLOCATION PROCEEDING (BCAP)

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 sales volumes 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 application 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 in the Annual Report, on May 27, 2004 the ALJ in the
2005 BCAP issued a decision dismissing the BCAP application. The
company is required to file a new BCAP application after the stay of
the GIR implementation decision is lifted.

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. The California Utilities are the parties to the first phase
of the investigation. If the investigation were to determine that the
conduct of either of the California Utilities contributed to the
natural gas price spikes that occurred during the investigation
period, 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. At September 30, 2004, the cumulative amount of
shareholder awards, all of which has been included in net income, was
$8.2 million. The first phase of this investigation was reopened for
one day on October 25, 2004, for additional testimony and supplemental
opening and reply briefs. While the ALJ stated that a proposed
decision is not imminent, the company expects that a proposed decision

21

will be issued before year end for consideration by the CPUC. Although
the proposed decision may be adverse to it, the company believes it is
unlikely that the full CPUC would adopt any such adverse decision and
would instead conclude that the California Utilities were not
responsible for any natural gas price spikes. A final CPUC decision in
the first phase of the investigation is not expected until 2005.

CPUC INVESTIGATION OF ENERGY-UTILITY HOLDING COMPANIES

The CPUC has initiated an investigation into the relationship between
California's IOUs and their parent holding companies. The CPUC broadly
determined that it could, in appropriate circumstances, 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 provide for their utility
subsidiaries' capital requirements, as the IOUs previously acknowledged
in connection with the holding companies' formations. In January 2002,
the CPUC ruled that it had jurisdiction to create the holding company
system and, therefore, retains jurisdiction to enforce conditions to
which the holding companies had agreed.

In an opinion issued May 21, 2004, the California Court of Appeal
upheld the CPUC's assertion of limited enforcement jurisdiction, but
concluded that the CPUC's interpretation of the "first priority"
condition (that the holding companies could be required to infuse cash
into the utilities as necessary to meet the utilities' obligation to
serve) was not ripe for review. In September 2004, the California
Supreme Court declined to review the California Court of Appeal's
decision.

RECOVERY OF CERTAIN DISALLOWED TRANSMISSION COSTS

The Federal Court of Appeals scheduled completion of briefing by
February 9, 2005, and set oral argument for April 14, 2005, concerning
SDG&E's recovery of the differentials between certain payments to SDG&E
by its co-owners of the Southwest Powerlink (SWPL) and charges assessed
to SDG&E under the California Independent System Operator (ISO) FERC
tariff for transmission line losses, and grid management and other
charges related to energy schedules of its SWPL co-owners. The parties
in the related private arbitration have agreed to hold the arbitration
in abeyance pending resolution of the FERC tariff proceeding.

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

22

extent any such refunds are actually realized by SDG&E, they would be
refunded to ratepayers.

In December 2002, a FERC ALJ issued preliminary findings indicating
that the California PX and ISO owe power suppliers $1.2 billion for the
October 2, 2000 through June 20, 2001 period (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 adopted its ALJ's findings, but changed the
calculation of the refund by basing it on a different estimate of
natural gas prices. 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 for the same time
period. Pending in the Ninth Circuit are various parties' appeals on
aspects of the FERC's order.

In a series of orders in 2004, the FERC has provided further direction
and clarifications regarding the methodology to be used by the ISO and
PX to recalculate the precise refund obligations and entitlements
through their settlement models.

Manipulation Investigation

The FERC is separately investigating whether there was manipulation of
short-term energy markets in the western United States 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 periods 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 (generally described as manipulating or
"gaming" the California energy markets) in violation of the PX and ISO
tariffs.

On June 25, 2003, the FERC issued several orders requiring various
entities to show cause why they should not be found to have violated
California ISO and PX tariffs. The FERC directed 43 entities, including
SDG&E, to show cause why they should not disgorge profits from certain
transactions between January 1, 2000 and June 20, 2001 that are
asserted to have constituted gaming and/or anomalous market behavior
under the California ISO and/or PX tariffs. SDG&E and the FERC resolved
the matter through a settlement, which documents the ISO's finding that
SDG&E did not engage in market activities in violation of the ISO or PX
tariffs, and in which SDG&E agreed to pay $27,792 into a FERC-
established fund.

NOTE 6. CONTINGENCIES

NUCLEAR INSURANCE

SDG&E and the other owners of SONGS have insurance to respond to
nuclear liability claims related to SONGS. Detail of the coverage is
provided in the Annual Report. As of September 30, 2004, the secondary
financial protection provided by the Price-Anderson Act is $10.5
billion if the liability loss exceeds the insurance limit of $300
million. In addition, the maximum SDG&E could be assessed is $8.8

23

million should there be a retrospective premium call under the risk
sharing arrangements of the nuclear property, decontamination and
debris removal insurance policy.

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. For certified acts of terrorism, the individual policy
limits stated above apply.

SPENT NUCLEAR FUEL

SONGS owners have responsibility for the interim storage of spent
nuclear fuel generated at SONGS until it is accepted by the DOE for
final disposal. Spent nuclear fuel is stored in the SONGS Units 1, 2
and 3 Spent Fuel Pools (SFP) and the SONGS Independent Spent Fuel
Storage Installation (ISFSI). Movement of Unit 1 spent fuel from the
Unit 3 SFP to the ISFSI was completed in late 2003. Movement of Unit 1
spent fuel from the Unit 1 SFP to the ISFSI is scheduled to be
completed by the end of 2004 and from the Unit 2 SFP to the ISFSI by
late 2005. With these moves, there will be sufficient space in the Unit
2 and 3 SFPs to meet plant requirements through mid-2007 and mid-2008,
respectively.

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.

Energy Crisis Litigation

In 2000 and 2001, California experienced a severe energy crisis
characterized by dramatic increases in the prices of electricity and
natural gas. Many, often duplicative, lawsuits have been filed against
numerous energy companies seeking overlapping damages aggregating in
the tens of billions of dollars for allegedly unlawful activities
asserted to have caused or contributed to the energy crisis. In
addition, the energy crisis has generated numerous governmental
investigations and regulatory proceedings. The company is cooperating
in various investigations, including an investigation being conducted
by the California Attorney General into possible anti-competitive
behavior. The material regulatory proceedings arising out of the energy
crisis that involve the company are briefly summarized, along with

24

other proceedings, in Note 5 and this Note 6. The lawsuits arising out
of the energy crisis to which the company is a defendant are briefly
summarized below.

Natural Gas Cases

Class-action and individual antitrust and unfair competition lawsuits
filed in 2000 and thereafter, and currently consolidated in San Diego
Superior Court seek damages, alleging that Sempra Energy, SoCalGas and
SDG&E, along with El Paso Natural Gas Company (El Paso) and several of
its affiliates, unlawfully sought to control natural gas and
electricity markets. In December 2003, the Court approved a settlement
whereby the applicable El Paso entities (including cases involving
unrelated claims not applicable to Sempra Energy, SoCalGas or SDG&E)
will pay approximately $1.7 billion to resolve these claims. The
proceeding against Sempra Energy and the California Utilities has not
been settled and continues to be litigated. During the third quarter of
2004, the court denied motions by Sempra Energy and the California
Utilities for summary judgment in their favor. Sempra Energy and the
California Utilities have requested the Court of Appeal to review these
denials; however, such an interim review pending a final decision on
the merits of the case is entirely at the discretion of the appellate
court. In October 2004, certain of the plaintiffs issued a news release
asserting that they could recover as much as $24 billion from Sempra
Energy and the California Utilities if their allegations were upheld at
trial. The trial of the case was previously set for September 2004 but
has been postponed and the newly assigned judge has yet to schedule a
new trial date. (The original judge is retiring at year end.)

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. The claims against the Sempra Energy
defendants in the Arizona lawsuit were settled in September 2004 for
$150,000 and have been dismissed with prejudice.

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 recovery
of damages alleged to aggregate in excess of $150 million (before
trebling) 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 to resolve.
However, the court granted plaintiffs' request to amend their
complaint, which they have done and Sempra Energy has filed another
motion to dismiss, which is scheduled to be heard on November 29, 2004.

In July 2004, the City and County of San Francisco, the County of Santa
Clara and the County of San Diego brought actions, alleging that energy
prices were unlawfully manipulated by defendants' reporting
artificially inflated natural gas prices to trade publications and by
entering into wash trades and by engaging in "churning" transactions
with Reliant Energy, in San Diego Superior Court against various
entities, including Sempra Energy, SET, SoCalGas and SDG&E.

25

Electricity Cases

Various antitrust lawsuits, which seek class-action certification,
allege that numerous entities, including Sempra Energy and certain
subsidiaries, including SDG&E, that participated in the wholesale
electricity markets unlawfully manipulated those markets. Collectively,
these lawsuits allege damages against all defendants in an aggregate
amount in excess of $16 billion (before trebling). In January 2003, the
federal court granted a motion to dismiss one of these lawsuits, filed
by Snohomish County, Washington Public Utility District, 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
was appealed to the Ninth Circuit U.S. Court of Appeals.

Other Litigation

The Utility Consumers' Action Network (UCAN), a consumer-advocacy group
which had requested a CPUC rehearing of a CPUC decision concerning the
allocation of certain power contract gains between SDG&E customers and
the company, appealed the CPUC's rehearing denial to the California
Court of Appeal. On July 12, 2004, the Court of Appeal affirmed the
CPUC's decision. On August 20, 2004, UCAN filed a Petition for Review
in the California Supreme Court. The Supreme Court has not yet
determined whether it will grant review.

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" and "Risk Factors" contained in the Annual Report.

RESULTS OF OPERATIONS

Revenues and Cost of Sales

Electric revenues decreased to $1.3 billion for the nine months ended
September 30, 2004 from $1.4 billion for the same period in 2003, and
the cost of electric fuel and purchased power decreased to $425 million
in 2004 from $428 million in 2003. Additionally, electric revenues
decreased to $449 million for the quarter ended September 30, 2004 from
$579 million for the same period in 2003, and the cost of electric fuel
and purchased power increased to $143 million in 2004 from $128 million
in 2003. The decreases in revenues were due to the recognition of $116
million related to the approved settlement of intermediate-term
purchase power contracts in the third quarter of 2003, more power being
provided to SDG&E's customers by the DWR in 2004 as discussed in Note 5
of the notes to Consolidated Financial Statements, and higher earnings
from PBR awards in 2003. The decrease in the cost of electric fuel and
purchased power for the nine-month period was mainly due to more power
being provided by the DWR, while the increase for the three-month
period was due to higher electric commodity costs partially offset by

26

more power being provided by the DWR. Under the current regulatory
framework, changes in commodity costs normally do not affect net
income. Performance awards are discussed in Note 5 of the notes to
Consolidated Financial Statements.

Natural gas revenues increased to $407 million for the nine months
ended September 30, 2004 from $371 million for the corresponding period
in 2003, and the cost of natural gas increased to $233 million in 2004
from $199 million in 2003. Additionally, natural gas revenues were $101
million for the quarter ended September 30, 2004 compared to $88
million for the corresponding period in 2003, and the cost of natural
gas was $61 million in 2004 compared to $47 million in 2003. These
increases were primarily attributable to natural gas cost increases,
which are passed on to customers.

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
and in Note 5 of the notes to Consolidated Financial Statements. In
accordance with generally accepted accounting principles, SDG&E is
generally recognizing 2004 revenue in a manner consistent with the
reduced rates contemplated by the proposed settlements, except for the
favorable effect of the recovery of pension costs contemplated by the
proposed settlements and provided by both proposed decisions. To the
extent that the revenues provided by the CPUC's decision in the cost of
service proceedings differ from those previously recorded, a
reconciling adjustment to revenues and resulting net income would be
recorded in the latest quarter for which financial statements had not
been published. To date, the impacts of accounting consistent with the
settlement have not had a material effect on the financial statements.

The tables below summarize the electric and natural gas volumes and
revenues by customer class for the nine months ended September 30, 2004
and 2003.

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

27

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.

Beginning in 2004, off-system sales are accounted for as a reduction of
the cost of purchased power.

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

Other Operating Expenses

Other operating expenses decreased to $426 million for the nine-month
period ended September 30, 2004 from $428 million for the same period
in 2003 and decreased to $135 million for the quarter ended September
30, 2004 from $160 million for the same period in 2003 due to
litigation charges in the third quarter of 2003 offset partially by
increases in other operating expenses in 2004.

Interest Income

Interest income increased to $24 million for the nine months ended
September 30, 2004 from $4 million for the same period of 2003, and
increased to $18 million for the quarter ended September 30, 2004 from
$1 million for the same period of 2003. The changes were due primarily
to interest on income tax receivables during the first and third
quarters of 2004.

Income Taxes

Income tax expense decreased to $128 million for the nine months ended
September 30, 2004 from $181 million for the same period of 2003. The
corresponding effective income tax rates were 47.1 percent and 46.3

28

percent, respectively. Additionally, income tax expense decreased to
$55 million for the third quarter of 2004 compared to $108 million for
the third quarter of 2003, and the corresponding effective income tax
rates were 47.0 percent and 47.2 percent, respectively. The changes
were due primarily to lower taxable income in 2004.

Net Income

SDG&E recorded net income of $144 million and $210 million for the
nine-month periods ended September 30, 2004 and 2003, respectively, and
net income of $62 million and $121 million for the quarters ended
September 30, 2004 and 2003, respectively. The decreases were primarily
due to income of $65 million after-tax in 2003 related to the approved
settlement of intermediate-term purchase power contracts, the 2003
Incremental Cost Incentive Pricing for SONGS, higher performance awards
in 2003 and higher depreciation expense in 2004 partially offset by
higher electric transmission and distribution revenues (excluding the
effects of the settlement, which are included in Revenues) in 2004, and
by higher operating expenses in 2003 including litigation charges in
the third quarter.

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, 2004, the company had $10 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. Rating agencies and others that
evaluate a company's liquidity generally consider a company's capital
expenditures and working capital requirements in comparison to cash from
operations, available credit lines and other sources available to meet
liquidity requirements.

CASH FLOWS FROM OPERATING ACTIVITIES

Net cash provided by operating activities totaled $324 million and $465
million for the nine months ended September 30, 2004 and 2003,
respectively. The decrease was mainly due to lower net income and a
decrease in accounts payable in 2004 compared to an increase in 2003.

For the nine months ended September 30, 2004, the company contributed $5
million to other postretirement benefit plans but made no contribution
to the pension plan.

CASH FLOWS FROM INVESTING ACTIVITIES

Net cash used in investing activities totaled $202 million and $246
million for the nine months ended September 30, 2004 and 2003,

29

respectively. The change was primarily due to higher repayments of an
intercompany loan by Sempra Energy in 2004.

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 debt issuances.

In September 2004, the CPUC approved a proposed framework for the
contracting of interstate pipeline capacity for core customers.
Discussions are underway for the California Utilities to acquire
pipeline capacity to replace capacity contracts expiring over the next
two years. The CPUC also approved requests to establish receipt points
to accept new supplies, including imported LNG, to the California
Utilities' service area. Approval for a point of receipt to import
natural gas from Mexico to Southern California via pipelines at Otay
Mesa was also obtained. As a result, the California Utilities expect to
install capital facilities starting in 2005, in order to receive natural
gas supplies from new delivery locations. The CPUC has determined that
project developers, not the utilities, will be presumed to pay for the
costs for access-related infrastructure, subject to future applications
to be filed when more is known about the particular projects. Note 5 of
the notes to Consolidated Financial Statements herein provides further
details.

Under terms of a franchise agreement and Memorandum of Understanding
reached in October 2004 between SDG&E and the City of Chula Vista, the
company has committed to support at the CPUC for undergrounding a part
of the proposed Otay Mesa transmission line through Chula Vista's
bayfront, upon CPUC approval of a substation upgrade, and replacement of
certain other overhead transmission lines with underground facilities.
Other transmission lines are to be undergrounded pursuant to the tariff
Rule 20A undergrounding program. If the Otay Mesa undergrounding
project is approved by the CPUC, the company's expected share of cost
will be $36 million. If the company does not complete the undergrounding
project by April 2010, there will not be an automatic renewal of the
franchise at the end of the initial ten-year term.

CASH FLOWS FROM FINANCING ACTIVITIES

Net cash used in financing activities totaled $260 million and $204
million for the nine months ended September 30, 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 factors 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

30

for the company, 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. 132 (revised
2003), 143, 149 and 150, FASB Staff Position 106-2, and FIN 45 and 46,
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": Beginning in
2003, SFAS 143 requires entities to record liabilities for future costs
expected to be incurred when assets are retired from service, if the
retirement process is legally required. 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.

In June 2004, the FASB issued a proposed interpretation of SFAS 143,
Accounting for Conditional Asset Retirement Obligations, an
interpretation of FASB Statement No. 143. The interpretation would
clarify that a legal obligation to perform an asset retirement activity
that is conditional on a future event is within the scope of SFAS 143.
Accordingly, the interpretation would require an entity to recognize a
liability for a conditional asset retirement obligation if the
liability's fair value can be reasonably estimated. The proposed
interpretation would be effective for the company on December 31, 2005.

SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities": SFAS 149 amends and clarifies accounting for
derivative instruments 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, whereby derivatives are not required to be marked to market
when the contract is usually settled by the physical delivery of
natural gas. The company has determined that all natural gas contracts
are subject to unplanned netting and as such, these contracts are
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 are
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 September 30, 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

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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 evaluated the effectiveness of the design and operation of
the company's disclosure controls and procedures as of September 30,
2004, the end of the period covered by this report. Based on that
evaluation, the company's Chief Executive Officer and Chief Financial
Officer concluded that the company's disclosure controls and procedures
were effective at the reasonable assurance level.

There has been no change in the internal controls over financial
reporting during the company's most recent fiscal quarter that has
materially affected, or is reasonably likely to materially affect, the
company's internal controls over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

SDG&E and the County of San Diego are continuing to negotiate the
remaining terms of a settlement 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. The expected
settlement would involve payments by SDG&E of less than $750,000.

Except as described above and in Notes 5 and 6 of the notes to
Consolidated Financial Statements herein, neither the company nor its
subsidiary is party to, nor is their property the subject of, any
material pending legal proceedings other than routine litigation
incidental to their businesses.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits

Exhibit 10 - Material Contracts

Compensation

10.1 Sempra Energy Employee Stock Incentive Plan
(September 30, 2004 Sempra Energy Form 10-Q
Exhibit 10.1).

10.2 Sempra Energy Amended and Restated Executive Life

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Insurance Plan (September 30, 2004 Sempra Energy
Form 10-Q Exhibit 10.2).

10.3 Sempra Energy Excess Cash Balance Plan
(September 30, 2004 Sempra Energy Form 10-Q
Exhibit 10.3).

10.4 Form of Sempra Energy 1998 Long Term Incentive Plan
Performance-Based Restricted Stock Award
(September 30, 2004 Sempra Energy Form 10-Q
Exhibit 10.4).

10.5 Form of Sempra Energy 1998 Long Term Incentive Plan
Nonqualified Stock Option Agreement
(September 30, 2004 Sempra Energy Form 10-Q
Exhibit 10.5).

10.6 Form of Sempra Energy 1998 Non-Employee Directors' Stock
Plan Nonqualified Stock Option Agreement
(September 30, 2004 Sempra Energy Form 10-Q
Exhibit 10.6).

10.7 Sempra Energy Supplemental Executive Retirement Plan
(September 30, 2004 Sempra Energy Form 10-Q
Exhibit 10.7).

10.8 Neal Schmale Restricted Stock Award Agreement
(September 30, 2004 Sempra Energy Form 10-Q
Exhibit 10.8).

10.9 Severance Pay Agreement between Sempra Energy and
Donald E. Felsinger (September 30, 2004 Sempra Energy
Form 10-Q Exhibit 10.9).

10.10 Severance Pay Agreement between Sempra Energy and
Neal Schmale (September 30, 2004 Sempra Energy
Form 10-Q Exhibit 10.10).

10.11 Sempra Energy Executive Personal Financial Planning Program
Policy Document (September 30, 2004 Sempra Energy
Form 10-Q Exhibit 10.11).

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

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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 reports on Form 8-K were filed after June 30, 2004:

Current Report on Form 8-K filed August 5, 2004, filing as an exhibit
Sempra Energy's press release of August 5, 2004, giving the financial
results for the quarter ended June 30, 2004.

Current Report on Form 8-K filed September 30, 2004, announcing proposed
decisions issued by the CPUC's Administrative Law Judge and the Assigned
CPUC Commissioner on September 28, 2004, in the California Utilities'
Cost of Service Proceedings.

Current Report on Form 8-K filed October 27, 2004, discussing the
current status of the California Utilities' Cost of Service Proceedings
and the Border Price Investigation.

Current Report on Form 8-K filed November 4, 2004, filing as an exhibit
Sempra Energy's press release of November 4, 2004, giving the financial
results for the quarter ended September 30, 2004.

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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 4, 2004 By: /s/ S. D. Davis
------------------------------
S. D. Davis
Sr. Vice President-External Relations
and Chief Financial Officer