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

See notes to Consolidated Financial Statements.

See notes to Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS

See notes to Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

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 should be read in conjunction with the Annual Report on Form 10-K for the year ended December 31, 2005 (the Annual Report).

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

SDG&E accounts for the economic effects of regulation on utility operations in accordance with Statement of Financial Accounting Standards (SFAS) 71, Accounting for the Effects of Certain Types of Regulation.

Following are the changes in asset-retirement obligations, as defined in SFAS 143, Accounting for Asset Retirement Obligations and Financial Accounting Standards Board (FASB) Interpretation (FIN) No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of SFAS 143, for the three months ended March 31, 2006 and 2005. FIN 47 was adopted prospectively on January 1, 2006.

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

In accordance with FIN 47, the company has determined that the amount of asbestos-containing materials could not be determined and, therefore, no liability has been recognized for the related removal obligations. Since substantially all of the cost of removing such materials is expected to be recovered in rates, the effect of not recognizing these liabilities is not material to the company's financial condition or results of operations.

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 three months ended March 31:

The company expects to contribute $26 million to its pension plans and $11 million to its other postretirement benefit plans in 2006. For the three months ended March 31, 2006, $0 million and $3 million of contributions have been made to the pension and other postretirement benefit plans, respectively.

In accordance with FASB Staff Position 106-2, the net periodic postretirement benefit costs for the three months ended March 31, 2006 were reduced by $1 million, before regulatory adjustments, to reflect the expected subsidy as a result of the Medicare Prescription Drug, Improvement and Modernization Act of 2003.

During the three months ended March 31, 2006, the amount of unpaid capital expenditures decreased by $8 million.

Certain prior period financial statement items have been reclassified to conform to current period presentation.

The company's Consolidated Statements of Income have been converted from a utility format, where only regulated cost-of-service items, including income taxes on operating income, were reflected in Operating Income, to a commercial format, where nonutility items are reflected as components of Operating Income. Also, in the Consolidated Balance Sheets under the commercial format, nonutility property is included in Property, Plant and Equipment.

SFAS 123 (revised 2004), "Share-Based Payment" (SFAS 123R):

Effective January 1, 2006, Sempra Energy adopted SFAS No. 123 (revised 2004), Share-Based Payment (SFAS 123R), which requires compensation costs related to share-based transactions, including employee stock options, to be recognized in the financial statements based on fair value. SFAS 123R revises SFAS No. 123, Accounting for Stock-Based Compensation, (SFAS 123) and supersedes Accounting Principles Board Opinion (APBO) No. 25, Accounting for Stock Issued to Employees. In March 2005, the Securities and Exchange Commission (the SEC) issued Staff Accounting Bulletin No. 107 (SAB 107) regarding the SEC's interpretation of SFAS 123R and the valuation of share-based payments for public companies. Sempra Energy has applied the provisions of SAB 107 in its adoption of SFAS 123R.

Sempra Energy adopted the provisions of SFAS 123R using the modified prospective transition method. In accordance with this transition method, Sempra Energy's consolidated financial statements for prior periods have not been restated to reflect the impact of SFAS 123R. Under the modified prospective transition method, share-based compensation expense for the first quarter of 2006 includes compensation expense for all share-based compensation awards granted prior to, but for which the requisite service has not yet been performed as of January 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS 123. Share-based compensation expense for all share-based compensation awards granted after January 1, 2006 is based on the grant date fair value estimated in accordance with the provisions of SFAS 123R. Sempra Energy recognizes compensation costs net of an assumed forfeiture rate and recognizes the compensation costs for nonqualified stock options and restri cted shares expected to vest on a straight-line basis over the requisite service period of the award, which is generally four years. Sempra Energy estimated the forfeiture rate for the first quarter of 2006 based on its historical experience.

SFAS 154, "Accounting Changes and Error Corrections, a replacement of Accounting Principles Board Opinion (APBO) 20 and FASB Statement No. 3" (SFAS 154): 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. APBO 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. No such changes have been made by the company in 2006.

SFAS 155, "Accounting for Certain Hybrid Instruments" (SFAS 155): In February 2006, the FASB issued SFAS 155, an amendment of FASB Statements No. 133 (SFAS 133), Accounting for Derivative Instruments and Hedging Activities, and No. 140 (SFAS 140), Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. SFAS 155 amends SFAS 133 to allow financial instruments that have embedded derivatives to be accounted for as a whole, if the holder elects to account for the whole instrument on a fair value basis, and provides additional guidance on the applicability of SFAS 133 and SFAS 140 to certain financial instruments and subordinated concentrations of credit risk. SFAS 155 is effective for all hybrid financial instruments acquired or issued by the company on or after January 1, 2007. The company is currently evaluating the impact SFAS 155 will have on its consolidated financial statements, but does not expect that t he impact will be material.

SFAS 156, "Accounting for Servicing of Financial Assets" (SFAS 156): In March 2006, the FASB issued SFAS 156, an amendment to SFAS 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, with respect to the accounting for separately recognized servicing assets and servicing liabilities. This statement requires that all separately recognized servicing assets and servicing liabilities be initially measured at fair value, if practicable. It also permits, but does not require, the subsequent measurement of servicing assets and servicing liabilities at fair value. The company will adopt this statement on January 1, 2007 but does not expect that this statement will have a material effect on its consolidated financial statements.

SDG&E and its affiliate, SoCalGas have a combined $600 million five-year syndicated revolving credit facility expiring in 2010, under which each utility individually may borrow up to $500 million, subject to the combined borrowing limit for both utilities of $600 million. At March 31, 2006 and December 31, 2005, SDG&E had no amounts outstanding under this facility. The facility provided support for $61 million of commercial paper outstanding at March 31, 2006.

Additional information concerning these credit facilities is provided in the Annual Report.

The company's weighted average interest rate on the total short-term debt outstanding was 4.9% at March 31, 2006.

For the three months ended March 31, 2006 and 2005, respectively, comprehensive income was equal to net income.

Other Income, Net consists 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. These are described in Note 2 of the notes to Consolidated Financial Statements in the Annual Report.

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 after 2033 for fixed rates. The swaps expire in 2009. For the three months ended March 31, 2006 and 2005, pre-tax income arising from the ineffective portion of the interest-rate cash flow hedges included $3 million and $4 million, respectively, recorded in Other Income, Net on the Statements of Consolidated Income. At March 31, 2006, the balance in Accumulated Other Comprehensive Income (Loss) related to hedge ineffectiveness of the interest-rate cash flow hedges was zero.

Energy Contracts

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. The company records transactions for natural gas and electric energy contracts in Cost of Natural Gas and Cost of Electric Fuel and Purchased Power, respectively, in 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 would be retroactive to January 1, 2004. A draft decision was issued in March 2006 that would grant an increase of $5 million for each of 2004 and 2005. SDG&E filed comments in April 2006 pointing out several errors in the draft, the correction of which would increase the $5 million to $9 million. Final resolution is expected by the end of the second quarter of 2006.

In 2004 Southern California Edison Company (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). As provided for in the SONGS Operating Agreement, SDG&E initially elected not to participate in the steam generator replacement project.

However, SDG&E and Edison have since reached a settlement agreement, whereby SDG&E would participate in the steam generator replacement project and retain its 20% ownership share of SONGS. On April 14, 2006, SDG&E filed an application with the CPUC requesting: that SDG&E be allowed to participate in the replacement project, rate recovery of the cost of the project, full cost recovery via balancing account treatment of SDG&E's SONGS-related operating and maintenance costs, and an increased return on equity (11.6%) for SONGS-related capital costs. A CPUC decision on SDG&E's application is expected by the end of 2006.

ELECTRIC RESOURCES

On March 30, 2006, control and ownership of the 550-megawatt (MW) Palomar generating plant was transferred from Sempra Generation, which built the plant, to SDG&E. The CPUC has approved the revenue requirement for the plant as proposed by SDG&E.

SDG&E and Calpine Corp. (Calpine) are continuing discussions for SDG&E's possible purchase of the Otay Mesa power plant. If SDG&E determines that the plant's construction can be completed at a cost that is reasonable and can be recovered in rates, it will seek to reach agreement with Calpine for SDG&E's purchase of the plant and would proceed to complete the plant's construction, by as early as the summer of 2008.

SDG&E has proposed the construction of the Sunrise Powerlink, a 500-kV transmission line between the San Diego region and the Imperial Valley that is estimated to cost $1 billion to $1.4 billion and to deliver 1,000 MW by 2010. The purpose of the project is to enhance reliability, provide access to renewable resources and lower the cost of certain delivered energy. SDG&E and the Imperial Irrigation District (IID) have entered into a Memorandum of Agreement (MOA) to build the project jointly. SDG&E's share of the project is estimated to be between $700 million and $1.1 billion. In March 2006, SDG&E announced details of the transmission line's proposed route and will continue its outreach efforts to obtain public support for the project and its proposed route. SDG&E will file an update on the project in July 2006 covering, among other things, the MOA, a detailed environmental assessment and updated benefits of the project. SDG&E's objective is to have a CPUC decis ion by the third quarter of 2007.

2004 REASONABLENESS REVIEW

In April 2006, the CPUC issued a decision finding that SDG&E's administration of power purchase agreements and procurement of least-cost dispatch power activities were reasonable and prudent during the period October 1, 2003 through December 31, 2004, and that SDG&E's procurement-related revenue and expenses during that period were reasonable and prudent.

CPUC INVESTIGATION OF COMPLIANCE WITH AFFILIATE RULES

In November 2004, the CPUC initiated the independent audit to evaluate energy-related holding company systems and affiliate activities undertaken by Sempra Energy within the service territories of the California Utilities. The final audit report covering years 1997 through 2003 was made available on February 28, 2006. The scope of the audit is broader than the annual affiliate audit. The results of the audit are being reviewed by the CPUC and a hearing is scheduled for August 2006.

The annual affiliate audit reports of the California Utilities' transactions with other Sempra Energy affiliates covering calendar year 2004 were also submitted in the Affiliate Order Instituting Investigation proceeding and all affiliate-related issues in both proceedings will be coordinated and the remaining issues in the Border Price Investigation are stayed. Additional information regarding the Border Price Investigation is provided in Note 6 herein. The 2005 annual audit report was filed with the CPUC in April 2006.

CPUC RULEMAKING REGARDING ENERGY UTILITIES, THEIR HOLDING COMPANIES AND NON-REGULATED AFFILIATES

In April 2006, the CPUC issued a draft decision to amend the scope and schedule of the CPUC's October 2005 Holding Company Order Instituting Rulemaking. The draft decision, if adopted by the CPUC, sets forth proposed affiliate transaction rule changes that would be subject to a comment process beginning in late May 2006. Among other changes, the proposed affiliate transaction rule modifications would apply the affiliate transaction rules to the parent company, further limit shared services for corporate support (specifying financial planning, regulatory affairs, legal and risk management activities), prohibit utility procurement from affiliates without prior CPUC approval, and increase the public disclosure requirements and the CPUC's access to information regarding various matters. After consideration of the filed comments, the CPUC would issue another draft decision for additional comments and oral argument, with the final decision tentatively scheduled for the third quarter of 2006. The draft decision is currently on the agenda for the CPUC's May 11, 2006, business meeting.

ADVANCED METERING INFRASTRUCTURE

In March 2005, SDG&E submitted proposals to the CPUC for installing advanced meters with integrated two-way communications functionality. This $450 million advanced metering infrastructure has several features that would encourage customers to conserve electricity and shift usage away from time periods of high prices or capacity constraints, and would also result in various operational efficiency improvements. The proposal calls for the replacement of SDG&E's 1.4 million electric customer meters with smart meters and would include SDG&E's 900,000 natural gas meters. It includes installation of a communications network, information systems and system integration. CPUC hearings are planned for July 2006 and a CPUC decision is expected by the end of 2006. If the program is approved as proposed by the CPUC in 2006, meter installations are expected to commence in mid-2008 and be completed by 2010.

GAIN ON SALE RULEMAKING

A CPUC rulemaking was issued in September 2004 to standardize the treatment of gains on sales of utility property. This rulemaking may result in the adoption of a general ratemaking policy for allocation between utility shareholders and ratepayers of any gain or loss on sale of utility property. The CPUC will consider adopting a standard percentage allocation, rather than resolving such allocations on a case-by-case basis, as is now its practice. In unusual circumstances the CPUC would be able to depart from the standard allocation to be adopted. The CPUC intends to apply this standard percentage to sales of both depreciable and non-depreciable property. Among other things, the rulemaking states that the new policy would replace the CPUC's current policy of allocating to shareholders all gains or losses on the sale of utility plant to a municipality. Two draft decisions have been issued, with differing allocations of gains and losses. The matter is expected to be addressed by the CPUC in the second quarter of 2006.

COST OF CAPITAL

SDG&E has filed a motion with the CPUC to extend to 2007 its option to file a request to adjust its existing cost of capital decision.

NATURAL GAS INDUSTRY RESTRUCTURING

In April 2006, the CPUC voted to approve the California Utilities' proposal to combine the natural gas transmission costs for both companies, so that their customers will pay the same rate for delivering natural gas at any receipt point once re-gasified liquefied natural gas deliveries begin at the Otay Mesa interconnection.

LITIGATION

At March 31, 2006, the company's reserves for litigation matters were $77 million, primarily reserves of $76 million related to the agreements reached, subject to court approval, to settle certain litigation arising out of the 2000 - 2001 California energy crisis. The uncertainties inherent in complex legal proceedings 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 adversely affect the company's business, cash flows, results of operations and financial condition.

The litigation that is the subject of the settlement agreements is frequently referred to as the Continental Forge litigation, although the settlements also include other cases. The Continental Forge litigation, consisting of class-action and individual antitrust and unfair competition lawsuits consolidated in San Diego Superior Court, alleged that Sempra Energy and the California Utilities, along with El Paso Natural Gas Company and several of its affiliates, unlawfully sought to control natural gas and electricity markets and claimed damages of $23 billion after applicable trebling. A second settlement agreement relates to class-action litigation brought by the Nevada Attorney General in Nevada Clark County District Court and involved virtually identical allegations to those in the Continental Forge litigation.

To settle the California and Nevada litigation, Sempra Energy would make cash payments in installments aggregating $377 million, of which $347 million relates to the Continental Forge and California class action price reporting litigation and $30 million relates to the Nevada antitrust litigation.

Additional consideration for the California settlement includes an agreement that Sempra LNG would sell to the California Utilities, subject to CPUC approval, re-gasified liquefied natural gas from its liquefied natural gas terminal being constructed in Baja California, Mexico at the California border index price minus $0.02. The California Utilities also would seek approval from the CPUC to integrate their natural gas transmission facilities and to develop both firm, tradable natural gas receipt point rights for access to their combined intrastate transmission system and SoCalGas' underground natural gas storage system. In addition, Sempra Generation voluntarily would reduce the price that it charges for power and limit the places at which it would deliver power under its contract with the Department of Water Resources (DWR). The price reductions would be reduced by any amounts in excess of $150 million that Sempra Generation is ordered to pay or incurs as a monetary award, any reduction in future revenu es or profits, or any increase in future costs in connection with arbitration proceedings involving the DWR contract.

The California settlement is subject to the approval of the San Diego Superior Court, which has preliminarily approved the settlement, and notice of the settlement has been provided to the plaintiff class. The Los Angeles City Council has not yet voted to approve the City of Los Angeles's participation in the settlement and it may elect to continue pursuing its individual case against Sempra Energy and the California Utilities. If the City of Los Angeles decides not to participate, Sempra Energy may, at its option, either proceed with the settlement of the class action and other individual cases or terminate the entire agreement. The California Attorney General, the DWR, the California Energy Oversight Board, Edison, Pacific Gas & Electric Company and various other parties have filed objections to the settlement based, among other things, on their concerns that the releases in the settlement may encompass other proceedings against Sempra Energy and its subsidiaries to which they are parties. A hearing on the final approval of the Continental Forge settlement is scheduled for June 8, 2006. The Nevada settlement is subject to approval by the Nevada Clark County District Court, which has not yet approved notice to the class or scheduled a final approval hearing. Both the California and Nevada settlements must be approved for either settlement to take effect, but Sempra Energy is permitted to waive this condition. The settlements are not conditioned upon approval by the CPUC, the DWR, or any other governmental or regulatory agency to be effective. The company expects both settlements to be approved.

Additional details are provided in Note 11 of the notes to Consolidated Financial Statements in the Annual Report.

On November 21, 2005, the California Attorney General and the CPUC filed a lawsuit in San Diego County Superior Court alleging that in 1998 Sempra Energy and the California Utilities had intentionally misled the CPUC in obtaining its approval to use the utilities' California natural gas pipeline capacity to enable Sempra Energy's non-utility subsidiaries to deliver natural gas to a power plant in Mexico. The lawsuit further alleges that, as a result of insufficient utility pipeline capacity to serve both the power plant and California customers, SDG&E curtailed natural gas service to electric generators and large California commercial and industrial customers 17 times in 2000 - 2001, which resulted in increased air pollution and higher electricity prices for California consumers from the use of oil as an alternate fuel source by electric generating plants. The lawsuit seeks statutory penalties of not less than $1 million, $2,500 for each of an unspecified number of instances of unfair business practic es, and unspecified amounts of actual and punitive damages. It also seeks an injunction to require divestiture by Sempra Energy of non-utility subsidiaries to an extent to be determined by the court.

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, and included Sempra Energy, the California Utilities and Sempra Commodities, seeking recovery of damages alleged to aggregate in excess of $150 million (before trebling). The U.S. District Court dismissed the case in November 2004, determining that the Federal Energy Regulatory Commission (FERC) had exclusive jurisdiction to resolve claims. In January 2005, plaintiffs filed an appeal with the Ninth Circuit Court of Appeals.

Apart from the claims that will be settled in connection with the Continental Forge settlement, there remain pending 13 antitrust actions that were filed and have been coordinated in San Diego Superior Court against Sempra Energy and one or more of its affiliates (the California Utilities and Sempra Commodities, depending on the lawsuit) and various, unrelated energy companies, alleging that energy prices were unlawfully manipulated by the reporting of artificially inflated natural gas prices to trade publications and by entering into wash trades. On June 29, 2005, the court denied the defendants' motion to dismiss on preemption and Filed Rate Doctrine grounds. Pending in the federal court system are five cases against Sempra Energy, Sempra Commodities, the California Utilities and various other companies, which make similar allegations to those in the state proceedings, four of which also include conspiracy allegations similar to those made in the Continental Forge litigation. The District Court has dismissed four of these actions on the grounds that the claims asserted in these suits were preempted under federal law and the Filed Rate Doctrine. The remaining case is stayed. Plaintiffs have appealed the dismissals and the matters are pending oral argument in the Ninth Circuit Court of Appeals.

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 the Snohomish County, Washington Public Utility District against Sempra Energy and certain non-utility subsidiaries, among others, on the grounds that the claims were subject to the Filed Rate Doctrine and were preempted by the Federal Power Act. In September 2004, the Ninth Circuit U.S. Court of Appeals affirmed the district court's ruling. In June 2005, the U.S. Supreme Court declined to review the decision. The company believes that this decision provides a precedent for the dismissal of the other lawsuits against the Se mpra Energy companies claiming manipulation of the electricity markets. On October 4, 2005, on the basis of federal preemption and Filed Rate grounds, the San Diego Superior Court dismissed with prejudice the initial consolidated cases that claimed that energy companies, such as the Sempra Energy companies, manipulated the wholesale electricity markets. In December 2005, plaintiffs filed an appeal in that case. Initial briefs on appeal have not yet been filed.

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. In December 2004, the CPUC rejected the Administrative Law Judge's (ALJ) proposed decision.

The portion of this investigation relating to the California Utilities is still open. 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 March 31, 2006, the cumulative amount of these shareholder awards, substantially all of which has been included in income, was $8.5 million.

The CPUC may hold additional hearings to consider whether other companies, including other California investor-owned utilities, contributed to the natural gas price spikes, or issue an order terminating the investigation. Discovery is ongoing and initial testimony was filed in November 2005. Hearings are expected to begin in August 2006, in conjunction with the CPUC's investigation of compliance with affiliate rules.

The FERC is investigating prices charged to buyers in the California Power Exchange (PX) and Independent System Operator (ISO) markets by various electric suppliers. In December 2002, a FERC ALJ issued preliminary findings indicating that the 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). In March 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 2003 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 April 2005, the Ninth Circuit heard oral argument on issues relating to the scope of the refund proceeding and whether the FERC had jurisdiction to order refunds from governmental entities. The Ninth Circuit determined in September 2005 that FERC did not have jurisdiction to order refunds from governmental entities. The California investor-owned utilities, including SDG&E, have now filed claims with the various governmental entities to recoup monies paid over and above the just and reasonable rate for power in the 2000 - 2001 time frame. A decision on the remaining issues argued before the Court in April 2005 remains pending.

NUCLEAR INSURANCE

SDG&E and the other owners of SONGS have insurance to respond to nuclear liability claims related to SONGS. The insurance provides coverage of $300 million, 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 up to $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 incurred because of accidental property damage. This coverage is limited to $3.5 million per week for the first 52 weeks and $2.8 million per week for up to 110 additional weeks, 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).

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. There are industry aggregate limits of $300 million for liability claims and $3.24 billion for property claims, including replacement power costs, for non-certified acts of terrorism. 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.

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.

To assist the reader in understanding the trend of earnings, the following table summarizes the major unusual factors affecting net income and operating income for the three month periods ended March 31, 2006 and 2005. These factors are discussed elsewhere in this Quarterly Report and/or the Annual Report, and this summary should be read in conjunction with those discussions.

Electric revenues increased for the three months ended March 31, 2006, compared to the corresponding period in 2005 primarily due to higher purchased-power costs and higher volumes. During the three months ended March 31, 2006, natural gas revenues increased compared to the corresponding period in 2005 as a result of higher natural gas costs, which are passed on to customers.

Under the current regulatory framework, the cost of natural gas purchased for customers and the variations in that cost are passed through to the customers on a substantially concurrent basis. However, SDG&E's natural gas procurement performance-based regulation mechanism allows the company to share in the savings or costs from buying natural gas for customers below or above market-based monthly benchmarks. Further discussion is provided in Notes 1 and 10 of the notes to Consolidated Financial Statements in the Annual Report.

The tables below summarize the electric and natural gas volumes and revenues by customer class for the three month periods ended March 31.

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

Although 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, the associated volumes and distribution revenues are included in the above table.

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