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 State Legislature, the California Department of Water Resources, and the Federal Energy Regulatory Commission and other regulatory bodies in the United States; capital markets 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; the resolution of litigati on; 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. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

See notes to Consolidated Financial Statements.

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

See notes to Consolidated Financial Statements.

See notes to Consolidated Financial Statements.

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

See notes to Consolidated Financial Statements.

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

See notes to Consolidated Financial Statements.

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.

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, 2004 (the Annual Report) and the Quarterly Reports on Form 10-Q for the quarters ended March 31, 2005 and June 30, 2005.

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) 71, Accounting for the Effects of Certain Types of Regulation.

Changes in asset-retirement obligations, as defined in SFAS 143, Accounting for Asset Retirement Obligations, for the nine months ended September 30, 2005 and 2004 are as follows (dollars in millions):

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

In accordance with SFAS 132 (revised), Employers' Disclosures about Pensions and Other Postretirement Benefits, the following tables provide the components of benefit costs for the periods ended September 30:

The company expects to contribute $21 million to its pension plans and $5 million to the other postretirement benefit plans in 2005. For the nine months ended September 30, 2005, $10 million and $5 million of contributions have been made to the pension and other postretirement benefit plans, respectively, including $5 million and $2 million recorded in pension and other postretirement benefits plans, respectively, for the three months ended September 30, 2005.

Stock-Based Compensation: In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS 123 (revised), a revision of SFAS 123, Accounting for Stock-Based Compensation, which establishes the accounting for transactions in which an entity exchanges its equity instruments for goods or services received. This statement requires companies to measure and record the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award and provides for alternative transition methods. Sempra Energy has not determined the transition method it will use. The effective date of this statement is January 1, 2006 for Sempra Energy.

FASB Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143": Issued in March 2005, FIN 47 clarifies that the term "conditional asset-retirement obligation" as used in SFAS 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset-retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 requires companies to recognize a liability for the fair value of a conditional asset-retirement obligation if the fair value of the obligation can be reasonably estimated. FIN 47 is effective for the company's 2005 annual report. The company is in the process of evaluating the effect of FIN 47 on its financial position and results of operations.

Statement of Financial Accounting Standards No. 154 (SFAS 154), "Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3:" This statement applies to all voluntary changes in accounting principles and to changes required by an accounting pronouncement in instances where the pronouncement does not include specific transition provisions. Accounting Principles Board Opinion (APBO) No. 20 previously required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. SFAS 154 requires retrospective application to prior periods' financial statements of changes in accounting principle, unless it is impracticable to do so. This statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005.

In August 2005, SDG&E and its affiliate, SoCalGas, amended their combined revolving credit facility to increase the amount of borrowings available from $500 million to $600 million. The term of the facility was renewed and extended from an original term of three years expiring in May 2007 to a new term of five years expiring in August 2010. Under the amended facility, each utility may borrow up to $500 million, subject to a combined borrowing limit of $600 million. The facility requires each utility to maintain at the end of each quarter a ratio of total indebtedness to total capitalization (as defined in the facility) of no more than 65%. Borrowings under the facility, none of which are outstanding, are individual obligations of the borrowing utility and a default by one utility would not constitute a default or preclude borrowings by the other.

For the three months and nine months ended September 30, 2005 and 2004, comprehensive income was equal to net income.

Other Income and Deductions

Other income and deductions consist of the following:

The company periodically enters into interest-rate swap agreements to moderate its exposure to interest-rate changes and to lower its overall cost of borrowing.

In September 2004, SDG&E entered into interest-rate swaps to exchange the floating rates on its $251 million Chula Vista Series 2004 bonds maturing from 2034 through 2039 for fixed rates. The swaps expire in 2009. For the three and nine months ended September 30, 2005, pre-tax income arising from the ineffective portion of the interest-rate cash flow hedges included $4.4 million and $5.0 million, respectively, recorded in Other Income and Deductions on the Statements of Consolidated Income. The effect of the interest-rate cash flow hedges on other comprehensive income (loss) was immaterial for the three months and nine months ended September 30, 2005. At September 30, 2005, the balance in Accumulated Other Comprehensive Income (Loss) related to interest-rate cash flow hedges was reduced to zero due to the hedge ineffectiveness.

At SDG&E, the use of derivative instruments is subject to certain limitations imposed by company policy and regulatory requirements. These instruments allow the company to estimate with greater certainty the effective prices to be received by the company and the prices to be charged to its customers. SDG&E records transactions for natural gas and electric energy contracts in Cost of Natural Gas and Cost of Electric Fuel and Purchased Power, respectively, on the Statements of Consolidated Income. Unrealized gains and losses related to these derivatives are offset by regulatory assets and liabilities on the Consolidated Balance Sheets to the extent derivative gains and losses will be recoverable or payable in future rates.

SAN ONOFRE NUCLEAR GENERATING STATION (SONGS)

On May 5, 2005, the California Public Utilities Commission (CPUC) granted SDG&E a rehearing to resolve what SDG&E has contended was a computational error in the CPUC's setting of revenue for SDG&E's share of the operating costs of SONGS. Any adjustment will be retroactive to January 1, 2004. If SDG&E is fully successful, its revenue for the period in which the rehearing is concluded would be increased by $10 million for each of 2004 and 2005. Final resolution is expected by the end of 2005 or early 2006.

With the end of the Incremental Cost Incentive Mechanism in 2003, 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.

In 2004 Southern California Edison (Edison), the operator of SONGS, applied for CPUC approval to replace the steam generators at SONGS, stating that the work needed to be done in 2009 and 2010 for Units 2 and 3, respectively, and would require an estimated capital expenditure of $680 million (in 2004 dollars). SDG&E intervened in this application and requested that the CPUC either deny Edison's application as premature, direct Edison to purchase the new steam generators but defer the replacement until it is warranted, or direct Edison to purchase SDG&E's share in the facility and offer back a long-term Power Purchase Agreement in an amount equal to SDG&E's current share, 430 megawatts (MW). Hearings before the CPUC on Edison's application were completed in February 2005, and a final decision addressing the cost effectiveness of the steam generator project is expected in late 2005 or early 2006. SDG&E elected not to participate in the steam generator replacement project, which triggered a dispute under the SONGS operating agreement over the extent to which SDG&E's ownership share and its related share of SONGS' output would be reduced from its existing 20% interest if SDG&E does not participate in this project.

UTILITY RATEMAKING INCENTIVE AWARDS

Performance-Based Regulation (PBR) and demand-side management (DSM) awards are not included in the company's earnings until CPUC approval of the award is received. During the nine months ended September 30, 2005, the incentive rewards approved and included in earnings consisted of $0.2 million related to SDG&E's Year 11 natural gas PBR, none of which occurred in the quarter ended September 30, 2005.

On October 27, 2005, the CPUC approved the settlement agreement between the California Utilities and the CPUC's Office of Ratepayers Advocates (ORA), resolving all outstanding shareholder earnings claims associated with DSM, energy efficiency and low-income energy efficiency programs through various dates, depending on the program. The decision provides for $73 million in awards, including interest, franchise fees, uncollectible amounts and awards earned in prior years that had not yet then been requested. Approximately $40 million of the $73 million award will be included in fourth quarter 2005 income.

On October 27, 2005, the CPUC also approved $8.2 million in PBR incentive awards for SDG&E's 2003 Distribution PBR performance report, relating to employee safety, customer service and electric reliability. This award is subject to refund in the event the current investigation of Edison's service quality incentive awards warrants a further investigation of PBR incentives for other utilities, including SDG&E. The CPUC's Consumer Protection and Safety Division is conducting an ongoing investigation of Edison's PBR incentive data reporting.

The cumulative amount of these awards subject to refund based on the outcome of the Border Price Investigation discussed in "Litigation" below is $8.4 million, substantially all of which has been included in net income.

ELECTRIC RESOURCES

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, commodity costs associated with long-term contracts allocated to SDG&E from the DWR (and the revenues to recover those costs) 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 (2013). On June 30, 2005, the CPUC reversed its prior decision and assigned SDG&E customers $422 million of the costs (instead of the $790 million per the prior decision). Such allocation does not affect SDG&E's net income, but does affect its customers' commodity rates. In August 2005, Edison, The Utility Reform Network and the California Large Energy Consumers Association filed a Petition for Modification, not disputing the allocation of the DWR decision, but rather the schedule for reallocation.

In June 2004, the CPUC approved a request by SDG&E to enter into new electric resource contracts to meet its short- and long-term grid reliability needs, including the ten-year 573-MW Otay Mesa Power Purchase Agreement (OMPPA) with Calpine. The OMPPA would begin January 1, 2008. In June 2005, the CPUC granted limited rehearing of its approval of the OMPPA. While the CPUC found that SDG&E needs the power to be supplied by the OMPPA, it determined that the record did not contain sufficient evidence to demonstrate that the OMPPA is beneficial to ratepayers. The CPUC's Office of Ratepayer Advocates (ORA) contends that the OMPPA will be more costly to ratepayers than alternatives such as purchases from other sources, delaying the start date or rebidding the requirement. A hearing on this matter commenced on October 31, 2005, and a CPUC decision is expected in early 2006. In July 2005, the CPUC also approved SDG&E's request for the construction (CPCN application) of $209 million in transmission faci lities needed, in part, to provide full dispatchability of Calpine's Otay Mesa power plant. In August 2005, the ORA moved to stay the CPUC's approval of this CPCN application, but the Administrative Law Judge (ALJ) rejected the motion and SDG&E has commenced construction of the OMPPA transmission upgrade project.

State law requires SDG&E to achieve a 20% renewable energy portfolio no later than 2017 and this requirement could be accelerated to 2010. SDG&E continues to pursue additional renewable resources with the goal of achieving a 20% portfolio of renewable resources by 2010. In response to its request for offers issued in July 2004, SDG&E entered into contracts with four developers for purchase of energy from projects to begin operation between 2007 and 2016. SDG&E has entered into a 20-year contract with Stirling Energy Systems to develop a 300 MW solar project in the Imperial Valley area of California. The first phase of this project is scheduled for commercial operation in 2008 - 2010. SDG&E has an option for an additional 300 MW and the right of first refusal for 300 MW more. SDG&E has entered into a 20-year contract with Pacific Wind for development of a 205.5 MW wind project to be located in Southern California. This project is scheduled for commercial operation in 2007 - 2008. 1 0-year and 15-year contracts were signed for a total of 18.75 MW of energy and capacity from landfill gas projects to be located in SDG&E's service area.

Together the four projects will raise SDG&E's overall renewable portfolio to 13.3 % in 2010. The Stirling Energy System project is contingent upon successful completion of a new transmission line from the Imperial Valley region to San Diego. Because the Pacific Wind project is outside of SDG&E's service territory, it is contingent upon the construction of new transmission facilities by an unrelated party to allow for delivery of the output of the project to SDG&E.

These contracts are subject to CPUC approval. In September 2005, SDG&E issued an additional request for offers for renewable energy.

RECOVERY OF CERTAIN DISALLOWED TRANSMISSION COSTS

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. This proceeding was suspended in September 2003 pending the results of an independent audit.

In November 2004, the CPUC initiated the independent audit (known as the GDS audit) to evaluate energy-related holding company systems and affiliate activities undertaken by Sempra Energy within the service territories of SDG&E and SoCalGas. A final audit report covering years 1997 through 2003 is now expected to be provided to the CPUC on or before December 1, 2005. The scope of the audit is broader than the annual affiliate audit.

As reported in the company's Form 10-Q for the quarter ended June 30, 2005, the California Utilities filed with the CPUC on May 2, 2005 the results of the annual independent audit of the California Utilities' transactions with other Sempra Energy affiliates covering calendar year 2004. In response to a finding of the auditor that utility procurement information was improperly provided to an affiliated risk management consulting firm employed by Sempra Energy, the California Utilities have adopted the auditor's recommendation to perform risk management functions themselves rather than utilizing Sempra Energy's Risk Management Department.

The two following sections ("Natural Gas Market OIR" and "CPUC Investigation of Energy-Utility Holding Companies") also discuss issues related to affiliate relationships.

NATURAL GAS MARKET OIR

The CPUC's Natural Gas Market Order Instituting Rulemaking (OIR) was instituted in January 2004 and is being addressed in two phases. A decision on Phase I was issued in September 2004; evidentiary hearings on Phase II were held in August 2005 and addressed a variety of issues including the adequacy of the utilities' transmission and storage facilities. A proposed decision is expected by the end of 2005. Natural gas quality standards and interconnection requirements are being addressed in separate phases. Further discussion of Phase I and Phase II is included in the Annual Report.

The focus of the Natural Gas Market OIR is the period from 2006 to 2016. The Comprehensive Settlement Agreement (CSA) was entered into and approved as part of the Natural Gas Industry Restructuring (GIR) proceeding, as discussed in the Annual Report. Since the CSA 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 implement the CSA.

A separate application, to provide system integration, firm access rights and off-system deliveries, has been bifurcated into two phases, with evidentiary hearings on the first phase (system integration) held in September 2005 to consider whether the transmission component of the natural gas transportation rates of SDG&E and SoCalGas should be equalized. System integration would allow customers in the SDG&E and SoCalGas service territories to access upstream supplies of natural gas on an equal basis. In the second phase, to be addressed in mid-2006, the CPUC will consider establishing a system of firm access rights into the utilities' system and off-system deliveries.

CPUC INVESTIGATION OF ENERGY-UTILITY HOLDING COMPANIES

In January 2002, the CPUC ruled that it had jurisdiction to enforce conditions to which holding companies for the California IOUs had agreed in connection with their formation. In its past investigations into the relationship between California's IOUs and their parent holding companies, the CPUC has 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 it is 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 their holding companies' formations.

On October 27, 2005, the CPUC initiated a proceeding to re-examine the relationships among the California IOUs and their parent holding companies and other non-utility affiliates. It contemplates a review of the capital budgets, capital allocation processes, and dividend and capital retention policies of the utilities and their non-utility affiliates to better understand the amount of capital to be allocated for investment in energy infrastructure to meet California's need for reliable energy. The CPUC may propose additional rules or regulations to ensure that the utilities retain sufficient capital and the ability to access such capital to meet their customers' needs, and to address potential conflicts between the interests of utility ratepayers and those of their non-utility affiliates to ensure that they do not undermine the utilities' ability to meet their public service obligations at the lowest possible cost. A preliminary schedule contemplates that any proposed rules and final rules would be i ssued for comment and final rules be adopted in the first quarter of 2006.  

2005 COST OF CAPITAL

In May 2005, SDG&E submitted a request to the CPUC seeking a return on equity (ROE) of 12.00%, an increase from its current ROE of 10.37%. This application was consolidated with the similar applications of Pacific Gas & Electric (PG&E) and Edison. The request also seeks to increase SDG&E's equity ratio from 49.0% to 51.0% to mitigate the impact on its capital structure associated with the debt equivalence of purchased power contracts. Together, these changes, if adopted, would result in an overall rate of return of 9.00% and increase SDG&E's electric distribution revenue requirement by $29.3 million, or 4.1%, and increase SDG&E's natural gas transportation revenue requirement by $6.6 million, or 2.5%. A CPUC decision is expected by year-end.

ADVANCED METERING INFRASTRUCTURE

In March 2005, SDG&E submitted a proposal to the CPUC for installing advanced electric meters with integrated two-way communications. This advanced metering infrastructure (AMI) has several features that would encourage customers to conserve electricity and shift usage away from time periods of high prices or capacity constraints, and could also result in various efficiency improvements. Installing AMI would require an estimated investment of $450 million for full deployment over four years. A settlement agreement between all parties agreeing to SDG&E's pre-deployment funding proposal was adopted by the CPUC on August 15, 2005. As a result, $9 million of pre-deployment expenditures was authorized through 2006. A Request for Proposals seeks responses by the end of 2005. All issues will be heard by the CPUC in March 2006, with a final decision expected in late 2006.

SOUTHERN CALIFORNIA FIRES

On August 25, 2005, the assigned commissioner's proposed decision granting SDG&E full recovery of incurred costs ($40.8 million) associated with the 2003 Southern California fires was approved by the CPUC.

NUCLEAR INSURANCE

SDG&E and the other owners of SONGS have insurance coverage of $300 million for nuclear liability claims related to SONGS, the maximum amount available. In addition, the Price-Anderson Act provides for up to $10.5 billion of secondary financial protection. 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 to provide the secondary financial protection. SDG&E's total share would be $40 million, subject to an annual maximum assessment of $6 million, unless a default were to occur by any other SONGS owner. In the event the secondary financial protection limit were insufficient to cover the liability loss, SDG&E could be subject to an additional assessment.

SDG&E and the other owners of SONGS have $2.75 billion of nuclear property, decontamination and debris removal insurance and up to $490 million for outage expenses and replacement power costs. 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, after a waiting period of 12 weeks. The insurance is provided through a mutual insurance company, through which insured members are subject to retrospective premium assessments (up to $8.65 million in SDG&E's case).

Further information is provided in the Annual Report.

LITIGATION

The company has expended and continues to expend substantial amounts with respect to the legal proceedings and related investigations and regulatory matters summarized below. At September 30, 2005, the company had accrued $78 million to provide for the estimated costs of these matters, of which $78 million related to matters arising from the 2000-2001 California energy crisis, all of which is recorded in Other Current Liabilities and Deferred Credits and Other on the Consolidated Balance Sheets and almost all of which pertains to litigation that is continuing at October 31, 2005. (The related expenses are recorded in Other Operating Expenses in the Statements of Consolidated Income.) However, the uncertainties inherent in complex legal proceedings and, in particular, jury trial litigation make it difficult to estimate with any degree of certainty the costs and effects of resolving these matters. Accordingly, costs ultimately incurred may differ materially from estimated costs and could materially adversel y affect the company's business, cash flows, results of operations and financial condition. Further background on these matters is provided in the Annual Report.