EXHIBIT 12 Sempra Energy Ratios

-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, GoIzgjGYfd0PbVOFDtq9TDmLeamFD2HsPH7t8a+MNw0u/tm2fKaEjHuJlPNdfo+E HuvawUvXZL0cbQubJqQieA== 0000086521-04-000011.txt : 20040429 0000086521-04-000011.hdr.sgml : 20040429 20040429155521 ACCESSION NUMBER: 0000086521-04-000011 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 20040331 FILED AS OF DATE: 20040429 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SEMPRA ENERGY CENTRAL INDEX KEY: 0001032208 STANDARD INDUSTRIAL CLASSIFICATION: GAS & OTHER SERVICES COMBINED [4932] IRS NUMBER: 330732627 STATE OF INCORPORATION: CA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-14201 FILM NUMBER: 04764947 BUSINESS ADDRESS: STREET 1: 101 ASH STREET STREET 2: P O BOX 129400 CITY: SAN DIEGO STATE: CA ZIP: 92101 BUSINESS PHONE: 6196962000 MAIL ADDRESS: STREET 1: 101 ASH STREET STREET 2: P O BOX 129400 CITY: SAN DIEGO STATE: CA ZIP: 92101 FORMER COMPANY: FORMER CONFORMED NAME: MINERAL ENERGY CO DATE OF NAME CHANGE: 19970205 10-Q 1 se10q033104.txt FORM 10-Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q [ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 2004 ------------------------------------- Commission file number 1-14201 --------------------------------------------- Sempra Energy ---------------------------------------------------------- (Exact name of registrant as specified in its charter) California 33-0732627 - ------------------------------- ------------------- (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 101 Ash Street, San Diego, California 92101 - ------------------------------------------------------------------- (Address of principal executive offices) (Zip Code) (619) 696-2034 ---------------------------------------------------------- (Registrant's telephone number, including area code) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ----- ----- Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes X No ----- ----- Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Common stock outstanding on March 31, 2004: 229,757,604 --------------------- 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, national and international 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, environmental and other regulatory bodies in countries other than the United States, and the Federal Energy Regulatory Commission; capital market conditions, inflation rates, interest rates and exchange rates; energy and trading markets, including the timing and extent of changes in commodity prices; weather conditions and conservation efforts; war and terrorist attacks; business, regulatory and legal decisions; the status of deregulation of retail natural gas and electricity delivery; the timing and success of business development efforts; and other uncertainties, all of which are difficult to predict and many of which are beyond the control of the company. Readers are cautioned not to rely unduly on any forward- looking statements and are urged to review and consider carefully the risks, uncertainties and other factors which affect the company's business described in this report and other reports filed by the company from time to time with the Securities and Exchange Commission. PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS. SEMPRA ENERGY STATEMENTS OF CONSOLIDATED INCOME (Dollars in millions, except per share amounts)

SEMPRA ENERGY CONSOLIDATED BALANCE SHEETS (Dollars in millions)

SEMPRA ENERGY CONSOLIDATED BALANCE SHEETS (Dollars in millions)

SEMPRA ENERGY CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (Dollars in millions)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1. GENERAL This Quarterly Report on Form 10-Q is that of Sempra Energy (the company), a California-based Fortune 500 holding company. Sempra Energy's subsidiaries include San Diego Gas & Electric Company (SDG&E), Southern California Gas Company (SoCalGas) (collectively referred to herein as the California Utilities); Sempra Energy Global Enterprises (Global), which is the holding company for Sempra Energy Trading (SET), Sempra Energy Resources (SER), Sempra Energy International (SEI), Sempra Energy Solutions (SES) and other, smaller businesses; Sempra Energy Financial (SEF); and additional smaller businesses. The financial statements herein are the Consolidated Financial Statements of Sempra Energy and its consolidated subsidiaries. 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). 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. The company follows the guidance of Statement of Financial Accounting Standards (SFAS) 142, "Goodwill and Other Intangible Assets." The carrying amount of goodwill (included in Noncurrent Sundry Assets on the Consolidated Balance Sheets) was $188 million as of December 31, 2003 and March 31, 2004. The California Utilities account for the economic effects of regulation on utility operations in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." NOTE 2. NEW ACCOUNTING STANDARDS Stock-Based Compensation: On March 31, 2004, the Financial Accounting Standards Board (FASB) issued a proposed Exposure Draft to amend SFAS 123, "Accounting for Stock-Based Compensation" and SFAS 95, "Statement of Cash Flows" which provide the current guidance on accounting for stock options and related items. It proposes that the new rules would be effective for 2005. The proposed statement would eliminate the choice of accounting for share-based compensation transactions using Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and instead generally would require that such transactions be accounted for using a fair-value-based method. The Draft would prohibit retroactive application and require that expense be recognized only for those options that actually vest. The following table provides the pro forma effects that would have resulted if stock options were expensed. Quarters ended March 31, --------------------- (Dollars in millions, except for per share amounts) 2004 2003 - -------------------------------------------------------------------- Net income as reported $ 197 $ 88 Stock-based employee compensation expense reported in net income, net of tax 5 7 Total stock-based employee compensation under fair value method for all awards, net of tax (6) (9) --------------------- Pro forma net income $ 196 $ 86 ===================== Earnings per share: Basic--as reported $ 0.86 $ 0.43 ===================== Basic--pro forma $ 0.86 $ 0.42 ===================== Diluted--as reported $ 0.85 $ 0.42 ===================== Diluted--pro forma $ 0.85 $ 0.41 ===================== - -------------------------------------------------------------------- SFAS 132 (revised 2003), "Employers Disclosures about Pensions and Other Postretirement Benefits": This statement revises employers' disclosures about pension plans and other postretirement benefit plans. It requires disclosures beyond those in the original SFAS 132 about the assets, obligations, cash flows and net periodic benefit cost of defined benefit pension plans and other defined postretirement plans. In addition, the revised statement requires interim-period disclosures regarding the amount of net periodic benefit cost recognized and the total amount of the employers' contributions paid and expected to be paid during the current fiscal year. It does not change the measurement or recognition of those plans. The following table provides the components of benefit costs for the quarters ended March 31:

Note 8 of the notes to Consolidated Financial Statements in the Annual Report discusses the company's expected contribution to its pension plans and other postretirement benefit plans in 2004. For the quarter ended March 31, 2004, $1 million and $14 million of contributions have been made to its pension plans and other postretirement benefit plans, respectively. SFAS 143, "Accounting for Asset Retirement Obligations": SFAS 143 requires entities to record the fair value of liabilities for legal obligations related to asset retirements in the period in which they are incurred. It also requires the reclassification of estimated removal costs, which have historically been recorded in accumulated depreciation, to a regulatory liability. At March 31, 2004 and December 31, 2003, the estimated removal costs recorded as a regulatory liability were $1.4 billion at both dates for SoCalGas and $857 million and $846 million, respectively, for SDG&E. The change in the asset retirement obligations for the quarter ended March 31, 2004 is as follows (dollars in millions): Balance as of January 1, 2004 $ 337 Accretion expense 6 Payments (3) ------ Balance as of March 31, 2004 $ 340* ====== * The current portion of the obligation is included in Other Current Liabilities on the Consolidated Balance Sheets. SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities": Effective July 1, 2003, SFAS 149 amended and clarified accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS 133. Under SFAS 149 natural gas forward contracts that are subject to unplanned netting generally do not qualify for the normal purchases and normal sales exception. ("Netting" refers to contract settlement by paying or receiving the monetary difference between the contract price and the market price at the date on which physical delivery would have occurred.) In addition, effective January 1, 2004, power contracts that are subject to unplanned netting and that do not meet the normal purchases and normal sales exception under SFAS 149 will continue to be marked to market. Implementation of SFAS 149 did not have a material impact on reported net income. Additional information on derivative instruments is provided in Note 5. SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity": The company adopted SFAS 150 beginning July 1, 2003 by reclassifying $200 million of mandatorily redeemable trust preferred securities to Deferred Credits and Other Liabilities and $24 million of mandatorily redeemable preferred stock of subsidiaries to Deferred Credits and Other Liabilities and to Other Current Liabilities on the Consolidated Balance Sheets. On December 31, 2003, the $200 million of mandatorily redeemable trust preferred securities were reclassified to Due to Affiliates due to the adoption of FIN 46 as discussed below. Emerging Issues Task Force (EITF) 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities": In accordance with the EITF's rescission of Issue 98-10 by the release of Issue 02-3, the company no longer recognizes energy-related contracts under mark-to-market accounting unless the contracts meet the requirements stated under SFAS 133 and SFAS 149, which is the case for a substantial majority of the company's contracts. On January 1, 2003, the company recorded the initial effect of Issue 98-10's rescission as a cumulative effect of a change in accounting principle, which reduced after-tax earnings by $29 million. Neither the cumulative nor the ongoing effect impacts the company's cash flow or liquidity. Additional information on derivative instruments is provided in Note 5. EITF 03-11, "Reporting Realized Gains and Losses on Derivative Instruments that are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities and Not 'Held for Trading Purposes' as Defined in EITF Issue No. 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities": During 2003, the EITF reached a consensus that determining whether realized gains and losses on physically settled derivative contracts not held for trading purposes should be reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. Adoption of EITF 03-11 in 2003 did not have and is not expected to have a significant impact on the company's financial statements. FASB Interpretation No. (FIN) 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees": As of March 31, 2004, substantially all of the company's guarantees were intercompany, whereby the parent issues the guarantees on behalf of its consolidated subsidiaries. The only significant guarantees for which disclosure is required are the mandatorily redeemable trust preferred securities and $25 million related to debt issued by Chilquinta Energia Finance, LLC, an unconsolidated affiliate. The mandatorily redeemable trust preferred securities were also affected by FIN 46, as described below. 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. During December 2003, the FASB issued FIN 46 revised (FIN 46R) to defer the implementation date for pre-existing variable interest entities (VIEs) that are special purpose entities (SPEs) until the end of the first interim or annual period ending after December 15, 2003. For VIEs that are not SPEs, companies must apply FIN 46R no later than the end of the first reporting period ending after March 15, 2004. Sempra Energy adopted FIN 46 on December 31, 2003, resulting in the consolidation of two VIEs for which it is the primary beneficiary. One of the VIEs (Mesquite Trust), which is an SPE, was the owner of the Mesquite Power plant for which the company had a synthetic lease agreement, as described in Notes 2 and 5 in the Annual Report. The Mesquite Power plant is a 1,250-megawatt (MW) plant that provides electricity to wholesale energy markets in the Southwest and became fully operational in December 2003. The company recorded an after-tax credit of $9 million in 2003 for the cumulative effect from the change in accounting principle. The company bought out the lease in January 2004. The other variable interest entity is Atlantic Electric & Gas (AEG), which markets power and natural gas commodities to commercial and residential customers in the United Kingdom. Consolidation of AEG resulted in Sempra Energy's recording of 100 percent of AEG's balance sheet and results of operations, whereas it previously recorded only its share of AEG's net operating results. Due to AEG's consolidation, the company recorded an after-tax charge of $26 million in 2003 for the cumulative effect of the change in accounting principle. During the first quarter of 2004 Sempra Energy's Board of Directors approved management's plan to dispose of AEG. Note 4 provides further discussion concerning this matter and the sale of AEG. In accordance with FIN 46R, the company also deconsolidated a wholly owned subsidiary trust from its financial statements at December 31, 2003. The trust has no assets except for its receivable from the company. Due to the deconsolidation of this entity, Sempra Energy reclassified $200 million of mandatorily redeemable trust preferred securities to Due to Affiliates on its Consolidated Balance Sheets. In addition, contracts under which SDG&E acquires power from generation facilities otherwise unrelated to SDG&E could result in a requirement for SDG&E to consolidate the entity that owns the facility. SDG&E is in the process of determining whether it has any such situations and, if so, gathering the information that would be needed to perform the consolidation. The effects of this, if any, are not expected to significantly affect the financial position of SDG&E and there would be no effect on results of operations or liquidity. FASB Staff Position (FSP) 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003": Issued January 12, 2004, FSP 106-1 permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The company has elected to defer the effects of the Act as provided by FSP 106-1 until authoritative guidance on the accounting for the federal subsidy is issued. Any measure of the accumulated postretirement benefit obligation or net periodic postretirement benefit cost in the financial statements or the accompanying notes does not reflect the impact of the Act on the plans. At this time, specific authoritative guidance on the accounting for the federal subsidy provided by the Act is pending and that guidance could require the company to change previously reported information. NOTE 3. COMPREHENSIVE INCOME The following is a reconciliation of net income to comprehensive income. Quarters ended March 31, --------------- (Dollars in millions) 2004 2003 - ----------------------------------------------- Net income $ 197 $ 88 Foreign currency adjustments 4 14 Financial instruments (Note 5) (5) -- Minimum pension liability adjustments -- (6) --------------- Comprehensive income $ 196 $ 96 - ----------------------------------------------- NOTE 4. DISCONTINUED OPERATIONS During the first quarter of 2004, Sempra Energy's Board of Directors approved management's plan to dispose of its interest in AEG, which markets power and natural gas commodities to commercial and residential customers in the United Kingdom. This disposal meets the criteria established for recognition as discontinued operations under SFAS 144, "Accounting for the impairment or Disposal of Long-Lived Assets." On April 27, 2004, the company entered into an agreement to sell AEG for a sales price of $162 million. The net losses from discontinued operations were $24 million for the first quarter of 2004 ($0.10 per basic and diluted share) and $3 million for the first quarter of 2003 ($0.01 per basic and diluted share). Included within the net loss from discontinued operations are AEG's operating results, summarized below: Quarters ended March 31, --------------------------- (Dollars in millions) 2004 2003 - --------------------------------------------------------------------- Operating revenues $ 168 $ 108 * Loss from discontinued operations before income taxes $ (23) $ (3)* - --------------------------------------------------------------------- * During 2003, the company accounted for its investment in AEG under the equity method of accounting. As such, the company recorded its share of AEG's net loss as a $3 million loss in Other Income - Net on the Statements of Consolidated Income. Effective December 31, 2003, AEG was consolidated as a result of the adoption of FIN 46. This is discussed further in the Annual Report. AEG's balance sheet data, excluding intercompany balances (which are significant) eliminated in consolidation, are summarized below: March 31, December 31, (Dollars in millions) 2004 2003 - --------------------------------------------------------------------- Assets: Accounts receivable, net $ 160 $ 137 Other current assets 85 83 ------ ------ Total assets $ 245 $ 220 ------ ------ Liabilities: Accounts payable $ 29 $ 36 Other current liabilities 16 16 ------ ------ Total liabilities $ 45 $ 52 - --------------------------------------------------------------------- NOTE 5. FINANCIAL INSTRUMENTS As described in Note 10 of the notes to Consolidated Financial Statements in the Annual Report, the company follows the guidance of SFAS 133 as amended by SFAS 138 and 149 (collectively SFAS 133) to account for its derivative instruments and hedging activities. Derivative instruments and related hedges are recognized as either assets or liabilities on the balance sheet, measured at fair value. Changes in the fair value of derivatives are recognized in earnings in the period of change unless the derivative qualifies as an effective hedge that offsets certain exposure, except at the California Utilities, where such changes are balanced in the ratemaking process. SFAS 133 provides for hedge accounting treatment when certain criteria are met. For derivative instruments designated as fair value hedges, the gain or loss is recognized in earnings in the period of change together with the offsetting gain or loss on the hedged item attributable to the risk being hedged. For derivative instruments designated as cash flow hedges, the effective portion of the derivative gain or loss is included in other comprehensive income, but not reflected in the Statements of Consolidated Income until the corresponding hedged transaction is settled. The ineffective portion is reported in earnings immediately. The company utilizes derivative instruments to reduce its exposure to unfavorable changes in energy and other commodity prices, which are subject to significant and often volatile fluctuation. The company also uses derivative physical and financial instruments to reduce its exposure to fluctuations in interest rates and foreign currency exchange rates. Derivative instruments include futures, forwards, swaps, options and long-term delivery contracts. These contracts allow the company to predict with greater certainty the effective prices to be received by the company and, in the case of the California Utilities, their 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 company classifies its forward contracts as follows: Contracts that meet the definition of normal purchase and sales generally are long-term contracts that are settled by physical delivery and, therefore, are eligible for the normal purchases and sales exception of SFAS 133. The contracts are accounted for under accrual accounting and recorded in Revenues or Cost of Sales on the Statements of Consolidated Income when physical delivery occurs. Due to the adoption of SFAS 149, the company has determined that its natural gas contracts entered into after June 30, 2003 generally do not qualify for the normal purchases and sales exception. Fixed-priced Contracts and Other Derivatives Fixed-priced Contracts and Other Derivatives on the Consolidated Balance Sheets primarily reflect the California Utilities' unrealized gains and losses related to long-term delivery contracts for purchased power and natural gas transportation. The California Utilities have established offsetting regulatory assets and liabilities to the extent that these gains and losses are recoverable through future rates. If gains and losses at the California Utilities are not recoverable or payable through future rates, the California Utilities will apply hedge accounting if certain criteria are met. When a contract no longer meets the requirements of SFAS 133, the unrealized gains and losses and the related regulatory asset or liability will be amortized over the remaining contract life. The changes in fixed-price contracts and other derivatives on the Consolidated Balance Sheets for the quarter ended March 31, 2004 were primarily due to the settlement of the contingent purchase price obligation arising from the company's acquisition of the proposed Cameron LNG project and the physical deliveries under long-term purchased-power and natural gas transportation contracts. For the quarter ended March 31, 2004, pre-tax income from transactions associated with fixed-price contracts and other derivatives included $13 million for the settlement of the Cameron contingency. The transactions associated with fixed-price contracts and other derivatives had no material impact to the Statements of Consolidated Income for the quarter ended March 31, 2003. Trading Assets and Trading Liabilities Trading Assets and Trading Liabilities primarily arise from the activities of SET. SET derives revenue from market making and trading activities, as a principal, in natural gas, electricity, petroleum products, metals and other commodities, for which it quotes bid and ask prices to other market makers and end users. It also earns trading profits as a dealer by structuring and executing transactions that permit its counterparties to manage their risk profiles. SET utilizes derivative instruments to reduce its exposure to unfavorable changes in market prices, which are subject to significant and often volatile fluctuation. These instruments include futures, forwards, swaps and options, and represent contracts with counterparties under which payments are linked to or derived from energy market indices or on terms predetermined by the contract, which may or may not be financially settled by SET. Sempra Energy guarantees many of SET's transactions. Trading instruments are recorded by SET on a trade-date basis and the majority of such derivative instruments are adjusted daily to current market value with gains and losses recognized in Other Operating Revenues on the Statements of Consolidated Income. Trading Assets or Trading Liabilities include amounts due from commodity clearing organizations, amounts due to or from trading counterparties, unrealized gains and losses from exchange-traded futures and options, derivative over-the-counter (OTC) swaps, forwards and options. Unrealized gains and losses on OTC transactions reflect amounts that would be received from or paid to a third party upon settlement of the contracts. Unrealized gains and losses on OTC transactions are reported separately as assets and liabilities unless a legal right of setoff exists under an enforceable netting arrangement. Other derivatives which qualify as hedges are accordingly recorded under hedge accounting. Futures and exchange-traded option transactions are recorded as contractual commitments on a trade-date basis and are carried at fair value based on closing exchange quotations. Commodity swaps and forward transactions are accounted for as contractual commitments on a trade- date basis and are carried at fair value derived from dealer quotations and underlying commodity exchange quotations. OTC options purchased and written are recorded on a trade-date basis. OTC options are carried at fair value based on the use of valuation models that utilize, among other things, current interest, commodity and volatility rates, as applicable. Energy commodity inventory is being recorded at the lower of cost or market; however metals inventories continue to be recorded at fair value in accordance with Accounting Research Bulletin 43, "Restatement and Revision of Accounting Research Bulletins." The carrying values of SET's trading assets and trading liabilities approximate the following: March 31, December 31, (Dollars in millions) 2004 2003 - -------------------------------------------------------------------------- Trading Assets Unrealized gains on swaps and forwards $ 1,193 $ 1,043 OTC commodity options purchased 573 459 Due from trading counterparties 1,817 2,183 Due from commodity clearing organizations and clearing brokers 106 134 Resale agreements 7 1 Commodities owned 1,348 1,420 ------- ------- Total $ 5,044 $ 5,240 ======= ======= - -------------------------------------------------------------------------- Trading Liabilities Unrealized losses on swaps and forwards $ 1,136 $ 1,095 OTC commodity options written 303 226 Due to trading counterparties 2,090 2,195 Repurchase obligations 854 866 Commodities not yet purchased -- 56 ------- ------- Total $ 4,383 $ 4,438 ======= ======= - -------------------------------------------------------------------------- At SET, market risk arises from the potential for changes in the value of physical and financial instruments resulting from fluctuations in prices and basis for natural gas, electricity, petroleum, petroleum products, metals and other commodities. Market risk is also affected by changes in volatility and liquidity in markets in which these instruments are traded. SET's credit risk from physical and financial instruments as of March 31, 2004 is represented by their positive fair value after consideration of collateral. Options written do not expose SET to credit risk. Exchange traded futures and options are not deemed to have significant credit exposure since the exchanges guarantee that every contract will be properly settled on a daily basis. The following table summarizes the counterparty credit quality and exposure for SET at March 31, 2004 and December 31, 2003, expressed in terms of net replacement value. These exposures are net of collateral in the form of customer margin and/or letters of credit of $572 million and $569 million at March 31, 2004 and December 31, 2003, respectively. March 31, December 31, (Dollars in millions) 2004 2003 - ---------------------------------------------------------------------------- Counterparty credit quality* Commodity exchanges $ 106 $ 134 AAA 3 5 AA 240 310 A 416 463 BBB 464 345 Below investment grade 553 357 ------- ------- Total $ 1,782 $ 1,614 ======= ======= * As determined by rating agencies or internal models intended to approximate rating-agency determinations. NOTE 6. REGULATORY MATTERS ELECTRIC INDUSTRY REGULATION The restructuring of California's electric utility industry has significantly affected the company's electric utility operations. In addition, the power crisis of 2000-2001 caused the California Public Utilities Commission (CPUC) to adjust its plan for restructuring the electricity industry. The backgrounds of these issues are described in the Annual Report. The California Department of Water Resources' (DWR) operating agreement with SDG&E, approved by the CPUC, provides that SDG&E is acting as a limited agent on behalf of the DWR in undertaking energy sales and natural gas procurement functions under the DWR contracts allocated to SDG&E's customers. Legal and financial responsibility associated with these activities continues to reside with the DWR. Therefore, the revenues and costs associated with the contracts are not included in the Statements of Consolidated Income. SDG&E's 20-year resource plan identifies the near-term need for capacity resources within its service territory to support transmission grid reliability. An updated long-term resource plan will be filed during the summer of 2004 in a CPUC proceeding which will consider utility resource planning, such as energy efficiency, contracted power, demand response, qualifying facilities, renewable generation and distributed generation. However, in order to satisfy SDG&E's recognized near-term need for grid reliability capacity, in May 2003 SDG&E issued a Request for Proposals (RFP) for the years 2005-2007 for 69 megawatts (MW) in 2005 increasing to 291 MWs in 2007. As a result of its RFP, in October 2003, SDG&E filed a motion requesting CPUC authorization to enter into five new electric resource contracts (including two under which SDG&E would take ownership of new generating assets, one of which is being developed by SER), as more fully described in the Annual Report. Hearings concluded on February 20, 2004. Two draft decisions were issued on April 6, 2004, one by the Administrative Law Judge (ALJ) and an Alternate Draft by the Assigned Commissioner. Both draft decisions would approve all five proposed contracts. The Assigned Commissioner's Alternate Draft would also grant SDG&E's cost recovery, ratemaking and revenue requirement proposals for the proposed resources, including a return on equity (ROE) for SDG&E's new generation investments that is 50-basis points higher than SDG&E's ROE on distribution assets, an equity offset for the debt equivalency of purchase power contracts, and an equity buildup for construction. The CPUC may adopt all or part of the proposed decisions as written, or amend or modify them. Only when the CPUC acts does a decision become binding and final. The CPUC is expected to issue a final decision in the late spring of 2004. Given the CPUC's prior denial of the company's request for approval of additional transmission facilities, the company believes that customer requirements for electricity could not be met without the requested resources or similar additions. NATURAL GAS INDUSTRY RESTRUCTURING As discussed in the Annual Report, in December 2001 the CPUC issued a decision related to natural gas industry restructuring (GIR), with implementation anticipated during 2002. On April 1, 2004, after many delays and changes, the CPUC issued a decision that adopts tariffs to implement the 2001 decision. However, by that same decision, the CPUC stayed implementation of the GIR tariffs until it issues a decision in Phase I of the Natural Gas Market Order Instituting Ratemaking (OIR) (see below). At that time, the CPUC will reconcile the GIR market structure with whatever structure results from the Phase I decision of the Gas Market OIR. The stayed decision, if implemented, would unbundle the costs of SoCalGas' backbone transmission system from rates and result in revising noncore balancing account treatment to exclude the balancing of SoCalGas' backbone transmission costs and place SoCalGas at risk for throughput. The decision would create firm tradable rights for the transmissions system. Other noncore costs/revenues would continue to be fully balanced until the decision in the next Biennial Cost Allocation Proceeding (BCAP) (see below). NATURAL GAS MARKET OIR The Natural Gas Market OIR was approved on January 22, 2004, and will be addressed in two concurrent phases. The schedule calls for a Phase I decision by summer 2004 and a Phase II decision by the end of 2004. Further discussion of Phase I and Phase II is included in the Annual Report. The focus of the Gas OIR is 2006 to 2016. Since GIR (see above) would end in August 2006 and there is overlap between GIR and the Gas OIR issues, a number of parties (including SoCalGas) advised the CPUC not to implement GIR. The California Utilities have made comprehensive filings in the Gas OIR outlining a proposed market structure that will help create access to new natural gas supply sources (such as LNG) for California. In the Phase I filing, SoCalGas and SDG&E proposed a framework to provide firm tradable access rights for intrastate natural gas transportation; provide SoCalGas with continued balancing account protection for intrastate transmission and distribution revenues, thereby eliminating throughput risk; and integrate the transmission systems of SoCalGas and SDG&E so as to have common rates and rules. The California Utilities have proposed that the investments necessary to access new sources of supply be included in rate base. The estimated costs of these system enhancements to access as much as 2 billion cubic feet per day of new supplies are $200 million. In addition, the California Utilities have filed a recommended methodology and framework to be used by the CPUC for granting pre- approval of new interstate transportation agreements. They expect to receive a CPUC decision approving a methodology during the third quarter of 2004. COST OF SERVICE FILINGS In 2002, the California Utilities filed Cost Of Service applications with the CPUC, seeking rate increases reflecting forecasts of 2004 capital and operating costs, as further discussed in the Annual Report. The California Utilities are requesting revenue increases of $121 million. On December 19, 2003, settlements were filed with the CPUC for SoCalGas and SDG&E that, if approved, would resolve most of the cost of service issues. A CPUC decision is likely in the second quarter of 2004. The SoCalGas settlement would reduce rate revenues by $33 million from 2003 rate revenues. The SDG&E settlement would reduce its electric rate revenues by $19.6 million from 2003 rate revenues and increase its natural gas rate revenues by $1.8 million from 2003 rate revenues. A CPUC order has provided that the new rates will be retroactive to January 1, 2004. Beginning in the first quarter of 2004, the California Utilities are recognizing revenues consistent with the proposed settlements. SDG&E is also awaiting the CPUC decision on the Cost of Service application of Southern California Edison (Edison). This decision will set rates for San Onofre Nuclear Generating Station (SONGS), 20 percent of which is owned by SDG&E. As discussed in the Annual Report, SDG&E's SONGS ratebase restarted at $0 on January 1, 2004 and, therefore, SDG&E's earnings from SONGS will generally be limited to a return on new capital additions. Edison has applied for permission to replace SONGS' steam generator, which would increase the total cost of SONGS by an estimated $800 million ($160 million for SDG&E). SDG&E has raised objections at the CPUC and at the San Diego Superior Court, intended to compel Edison to declare an operating impairment as the basis for the expenditure. Under the terms of the ownership agreement, determination that an operating impairment exists will allow SDG&E to not participate in the project, which would proceed without SDG&E, and SDG&E's ownership percentage in SONGS would be reduced. A pre-hearing conference is scheduled for May 18, 2004. The California Utilities have also filed for continuation through 2004 of existing performance-based regulation (PBR) mechanisms for service quality and safety that would otherwise expire at the end of 2003. In January 2004, the CPUC issued a decision that extended 2003 service and safety targets through 2004, but deferred action on applying any rewards or penalties for performance relative to these targets to a decision to be issued later in 2004 in a second phase of these applications. On April 2, 2004, the CPUC's Office of Ratepayers Advocates (ORA) filed its report recommending that a Consumer Price Index with no productivity factor or customer growth factor be used to change the California Utilities' base margin, as opposed to the proposed Margin per Customer proposal of the California Utilities, and that the pending decision be in effect for five years. The ORA also proposed the possibility of performance penalties, without the possibility of performance awards. Hearings are scheduled for June 2004 with a final decision expected by November 2004. PERFORMANCE-BASED REGULATION To promote efficient operations and improved productivity and to move away from reasonableness reviews and disallowances, the CPUC adopted PBR for SDG&E effective in 1994 and for SoCalGas effective in 1997. As further described in the Annual Report, under PBR, regulators require future income potential to be tied to achieving or exceeding specific performance and productivity goals, rather than relying solely on expanding utility plant to increase earnings. PBR, demand-side management (DSM) and Gas Cost Incentive Mechanism (GCIM) rewards are not included in the company's earnings before CPUC approval is received. The only incentive reward approved during the first quarter of 2004 was $6.3 million related to SoCalGas' Year 9 GCIM, which was approved on February 26, 2004. This reward is subject to refund based on the outcome of the Border Price Investigation described below. The cumulative amount of rewards so subject is $61.2 million at March 31, 2004. At March 31, 2004, the following performance incentives were pending CPUC approval and, therefore, were not included in the company's earnings (dollars in millions): Program SoCalGas SDG&E Total - ----------------------------------------------------------- DSM/Energy Efficiency* $ 9.8 $ 35.6 $ 45.4 2003 Distribution PBR -- 8.2 8.2 GCIM/natural gas PBR -- 1.9** 1.9 2003 safety .5 -- .5 - ----------------------------------------------------------- Total $ 10.3 $ 45.7 $ 56.0 - ----------------------------------------------------------- * Dollar amounts shown do not include interest, franchise fees or uncollectible amounts. **On March 15, 2004, the ORA recommended a modified reward of $1.5 million. COST OF CAPITAL Effective January 1, 2003, SoCalGas' authorized rate of return on common equity (ROE) is 10.82 percent and its return on ratebase (ROR) is 8.68 percent. Effective January 1, 2003, SDG&E's authorized ROE is 10.9 percent and its ROR is 8.77 percent, for SDG&E's electric distribution and natural gas businesses. The electric-transmission cost of capital is determined under a separate FERC proceeding discussed below. As discussed in the Annual Report, these rates will continue to be effective until market interest-rate changes are large enough to trigger an automatic adjustment or until the CPUC orders a periodic review. In SDG&E's case, the double-A utility bond yield must average less than 6.24 percent or greater than 8.24 percent during the April- September timeframe of any given year to trigger an automatic adjustment. The double-A utility bond yield averaged 6.30 percent during the first three weeks of April 2004. SoCalGas' automatic adjustment occurs when the 12-month trailing average of 30-year Treasury bond rates and the Global Insight forecast of the 30-year Treasury bond rate 12 months ahead vary by greater than 150 basis points from the benchmark, which is currently 5.38 percent. The 12- month trailing average was 4.93 percent at March 31, 2004. It would have to exceed 6.88 percent or fall below 3.88 percent for an automatic adjustment to occur. BIENNIAL COST ALLOCATION PROCEEDING The BCAP determines the allocation of authorized costs between customer classes for natural gas transportation service provided by the California Utilities and adjusts rates to reflect variances in customer demand as compared to the forecasts previously used in establishing transportation rates. SoCalGas and SDG&E filed with the CPUC their 2005 BCAP applications in September 2003, requesting updated transportation rates effective January 1, 2005. In November 2003, an Assigned Commissioner Ruling delayed the BCAP applications until a decision is issued in the GIR implementation proceeding. As a result of the April 1, 2004 decision on GIR implementation as described in "Natural Gas Industry Restructuring," the ALJ in the 2005 BCAP issued a ruling suspending the BCAP schedule pending CPUC dismissal of the applications. It is not known at this time when the California Utilities would be required to file new BCAP applications. As a result of the deferrals and the forecasted significant decline in noncore gas throughput on SoCalGas' system, in December 2002 the CPUC issued a decision approving 100 percent balancing account protection for SoCalGas' risk on local transmission and distribution revenues from January 1, 2003 until the CPUC issues its next BCAP decision. SoCalGas is seeking to continue this balancing account protection in the Gas OIR proceeding. BORDER PRICE INVESTIGATION In November 2002, the CPUC instituted an investigation into the Southern California natural gas market and the price of natural gas delivered to the California-Arizona border between March 2000 and May 2001. If the investigation determines that the conduct of any party to the investigation, including the California Utilities, contributed to the natural gas price spikes, the CPUC may modify the party's natural gas procurement incentive mechanism, reduce the amount of any shareholder award for the period involved, and/or order the party to issue a refund to ratepayers. Hearings are scheduled to begin on June 14, 2004. At a later date, the CPUC will hold a second round of hearings to consider whether Sempra Energy or any of its non-utility subsidiaries contributed to the price spikes. Decisions are expected by late 2004. The company believes that the CPUC will find that the California Utilities acted in the best interests of its core customers and that none of the Sempra Energy companies was responsible for the price spikes. The ORA recently filed testimony supporting the GCIM and the actions of SoCalGas during this period. CPUC INVESTIGATION OF COMPLIANCE WITH AFFILIATE RULES In February 2003, the CPUC opened an investigation of the business activities of SDG&E, SoCalGas and Sempra Energy to determine if they have complied with statutes and CPUC decisions in the management, oversight and operations of their companies. In September 2003, the CPUC suspended the procedural schedule until it completes an independent audit to evaluate energy-related holding company systems and affiliate activities undertaken by Sempra Energy within the service territories of SDG&E and SoCalGas. The audit, covering years 1997 through 2003, is expected to be completed by March 2005. The scope of the audit will be broader than the annual affiliate audit. In accordance with existing CPUC requirements, the California Utilities' transactions with other Sempra Energy affiliates have been audited by an independent auditing firm each year, with results reported to the CPUC, and there have been no material adverse findings in those audits. CPUC INVESTIGATION OF ENERGY-UTILITY HOLDING COMPANIES The CPUC has initiated an investigation into the relationship between California's investor-owned utilities (IOUs) and their parent holding companies. The CPUC broadly determined that it would require the holding company to provide cash to a utility subsidiary to cover its operating expenses and working capital to the extent they are not adequately funded through retail rates. This would be in addition to the requirement of holding companies to cover their utility subsidiaries' capital requirements, as the IOUs previously acknowledged in connection with the holding companies' formations. In January 2002 the CPUC ruled on jurisdictional issues, deciding that the CPUC had jurisdiction to create the holding company system and, therefore, retains jurisdiction to enforce conditions to which the holding companies had agreed. The company's request for rehearing on the issues was denied by the CPUC and the company subsequently filed appeals in the California Court of Appeal. Oral argument was held on March 5, 2004 before the First District Court of Appeal and a written opinion from the Court is expected by June 2004. RECOVERY OF CERTAIN DISALLOWED TRANSMISSION COSTS In August 2002 the Federal Energy Regulatory Commission (FERC) issued Opinion No. 458, which effectively disallowed SDG&E's recovery of the differentials between certain payments to SDG&E by its co-owners of the Southwest Powerlink (SWPL) under the Participation Agreements and charges assessed to SDG&E under the California Independent System Operator (ISO) FERC tariff for transmission line losses and grid management charges related to energy schedules of Arizona Public Service Co. (APS) and the Imperial Irrigation District (IID), its SWPL co-owners. As a result, SDG&E is incurring unreimbursed costs of $4 million to $8 million per year. On November 17, 2003, SDG&E petitioned the United States Court of Appeals for review of this FERC order and argued that the disallowed costs should be allowed for recovery through the Transmission Revenue Balancing Account Adjustment. On February 12, 2004, on the FERC's motion, the court remanded the case back to the FERC for further consideration, "based on the FERC's representation that it intends to act expeditiously on remand." The FERC has not yet issued further orders in this matter. On July 6, 2001, in a separate matter related to ISO charges giving rise to most of the cost differentials described above, SDG&E filed an arbitration claim against the ISO, claiming the ISO should not charge SDG&E for the transmission losses attributable to energy schedules on the APS and the IID shares of the SWPL. On October 23, 2003, the independent arbitrator found in SDG&E's favor, awarding to SDG&E all amounts claimed, which totaled $22 million, including interest, as of the time of the award. The ISO appealed this result to the FERC and a FERC decision is expected in 2004. SDG&E has also commenced a private arbitration to reform the Participation Agreements to remove prospectively SDG&E's obligation to provide services giving rise to unreimbursed ISO tariff charges. On April 6, 2004, the ISO filed its reply brief to SDG&E's brief and the matter was submitted to the FERC. In addition, APS, IID and Edison filed briefs in support of SDG&E's arbitration award. In addition, on January 23, 2004, the FERC denied rehearing of its Opinion No. 463, which upheld the ISO's grid management charges billed to SDG&E for the APS and IID SWPL energy schedules. This rehearing order did require the ISO to refund amounts of such charges covered by SDG&E self-supply of imbalance energy. Pursuant to this order, the ISO issued its refund report on February 23, 2004, calculating the refunds due SDG&E at $320,000. On March 15, 2004, SDG&E protested the ISO's refund report, claiming refunds of $3.3 million, before interest. A FERC decision on the refunds is expected later in 2004. In addition, on March 22, 2004, SDG&E petitioned the United States Court of Appeals for review of these FERC orders and will argue that the ISO lacks authority under its tariff to assess grid management charges on the subject SWPL schedules. The court has not yet scheduled briefing or argument in this matter. FERC ACTIONS DWR Contract On June 25, 2003, the FERC issued orders upholding the company's long- term energy supply contract with the DWR, as well as contracts between the DWR and other power suppliers. The order affirmed a previous FERC conclusion that those advocating termination or alteration of the contract would have to satisfy a "heavy" burden of proof, and cited its long-standing policy to recognize the sanctity of contracts. In the order, the FERC noted that FERC and court precedent clearly establish that allegations that contracts have become uneconomic by the passage of time do not render them contrary to the public interest under the Federal Power Act. The FERC pointed out that the contracts were entered into voluntarily in a market-based environment. The FERC found no evidence of unfairness, bad faith or duress in the original contract negotiations. It said there was no credible evidence that the contracts placed the complainants in financial distress or that ratepayers will bear an excessive burden. In December 2003, appeals of this matter filed by a number of parties, including the California Energy Oversight Board and the CPUC, were consolidated and assigned to the Ninth Circuit Court of Appeals (the Court). The company expects that the Court will affirm the FERC decision. Information regarding court proceedings and arbitration involving this contract is included under "Litigation" below. 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, such as SET, are required to provide refunds. To the extent any such refunds are actually realized by SDG&E, they would reduce SDG&E's rate-ceiling balancing account. To the extent that SET is required to provide refunds, they could result in payments by SET after adjusting for any amounts still owed to SET for power supplied during the relevant period (or receipts if refunds are less than amounts owed to SET). In December 2002, a FERC ALJ issued preliminary findings indicating that the California PX and ISO owe power suppliers $1.2 billion (the $3.0 billion that the California PX and ISO still owe energy companies less $1.8 billion that the energy companies charged California customers in excess of the preliminarily determined competitive market clearing prices). On March 26, 2003, the FERC largely adopted the ALJ's findings, but expanded the basis for refunds by adopting a staff recommendation from a separate investigation to change the natural gas proxy component of the mitigated market clearing price that is used to calculate refunds. The March 26 order estimates that the replacement formula for estimating natural gas prices will increase the refund obligations from $1.8 billion to more than $3 billion. The FERC recently released additional instructions, and ordered the ISO and PX to recalculate the precise number through their settlement models. California is seeking $8.9 billion in refunds from its electricity suppliers and has appealed the FERC's preliminary findings and requested rehearing of the March 26 order. In March 2004, the Attorney General of California requested the Ninth Circuit Court of Appeals to compel the FERC to comply with the Court's earlier orders, contending that the FERC had violated an August 2002 court order that should have resulted in larger refunds to California and that the FERC had failed to properly weigh evidence of market manipulation by power companies when deciding the refunds due California ratepayers. SET and other power suppliers have joined in appeal of the FERC's preliminary findings and requested rehearing. SET had established reserves of $29 million for its likely share of the original $1.8 billion. SET is unable to determine its possible share of the additional refund amount. Accordingly, it has not recorded any additional reserves but the company does not believe that any additional amounts that SET may be required to pay would be material to the company's financial position or liquidity. Manipulation Investigation The FERC is also investigating whether there was manipulation of short- term energy markets in the West that would constitute violations of applicable tariffs and warrant disgorgement of associated profits. In this proceeding, the FERC's authority is not confined to the October 2, 2000 through June 20, 2001 period relevant to the refund proceeding. In May 2002, the FERC ordered all energy companies engaged in electric energy trading activities to state whether they had engaged in various specific trading activities in violation of the PX and ISO tariffs (generally described as manipulating or "gaming" the California energy markets). On June 25, 2003, the FERC issued several orders requiring various entities to show cause why they should not be found to have violated California ISO and PX tariffs. First, FERC directed 43 entities, including SET and 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. Second, the FERC directed more than 20 entities, including SET, to show cause why their activities during the period January 1, 2000 to June 20, 2001 did not constitute gaming and/or anomalous market behavior in violation of the tariffs. Remedies for confirmed violations could include disgorgement of profits and revocation of market-based rate authority. The FERC has encouraged the entities to settle the issues and on October 31, 2003, SET agreed to pay $7.2 million in full resolution of these investigations. The entire amount has been recorded as of December 31, 2003. The entire proceeding, including the settlement, is subject to final approval by the FERC, which is expected later in 2004. SDG&E and the FERC resolved the matter by SDG&E's paying $28 thousand into a FERC-established fund. On June 25, 2003, the FERC also determined that it was appropriate to initiate an investigation into possible physical and economic withholding in the California ISO and PX markets. For the purpose of investigating economic withholding, the FERC used an initial screen of all bids exceeding $250 per megawatt between May 1, 2000 and October 2, 2001. Both SDG&E and SET have received data requests from the FERC staff and have provided responses. The FERC staff will prepare a report to the FERC, which will be the basis to decide whether additional proceedings are warranted. SET and SDG&E believe that their bids and bidding procedures were consistent with ISO and PX tariffs and protocols and applicable FERC price caps. On August 1, 2003, the FERC staff issued an initial report that determined there was no need to further investigate particular entities, including SET, for physical withholding of generation. NOTE 7. CONTINGENCIES NUCLEAR INSURANCE SDG&E and the other owners of SONGS have insurance to respond to nuclear liability claims related to SONGS. The insurance policy provides $300 million in coverage, which is the maximum amount available. In addition to this primary financial protection, the Price- Anderson Act provides for up to $10.5 billion of secondary financial protection if the liability loss exceeds the insurance limit. Should any of the licensed/commercial reactors in the United States experience a nuclear liability loss which exceeds the $300 million insurance limit, all utilities owning nuclear reactors could be assessed under the Price-Anderson Act to provide the secondary financial protection. SDG&E and the other co-owners of SONGS could be assessed up to $201 million under the Price-Anderson Act. SDG&E's share would be $40 million unless a default was to occur by any other SONGS owner. In the event the secondary financial protection limit were insufficient to cover the liability loss, the Price-Anderson Act provides for Congress to enact further revenue-raising measures to pay claims. These measures could include an additional assessment on all licensed reactor operators. SDG&E and the other owners of SONGS have $2.75 billion of nuclear property, decontamination and debris removal insurance. The coverage also provides the SONGS owners up to $490 million for outage expenses/replacement power incurred because of accidental property damage. This coverage is limited to $3.5 million per week for the first 52 weeks, and $2.8 million per week for up to 110 additional weeks. There is a deductible waiting period of 12 weeks prior to receiving indemnity payments. The insurance is provided through a mutual insurance company owned by utilities with nuclear facilities. Under the policy's risk sharing arrangements, insured members are subject to retrospective premium assessments if losses at any covered facility exceed the insurance company's surplus and reinsurance funds. Should there be a retrospective premium call, SDG&E could be assessed up to $8.5 million. Both the nuclear liability and property insurance programs subscribed to by members of the nuclear power generating industry include industry aggregate limits for non-certified acts, as defined by the Terrorism Risk Insurance Act, of terrorism-related SONGS losses, including replacement power costs. An industry aggregate limit of $300 million exists for liability claims, regardless of the number of non-certified acts affecting SONGS or any other nuclear energy liability policy or the number of policies in place. An industry aggregate limit of $3.24 billion exists for property claims, including replacement power costs, for non-certified acts of terrorism affecting SONGS or any other nuclear energy facility property policy within twelve months from the date of the first act. These limits are the maximum amount to be paid to members who sustain losses or damages from these non-certified terrorist acts. ARGENTINE INVESTMENTS As a result of the devaluation of the Argentine peso at the end of 2001 and subsequent declines in the value of the peso, SEI had reduced the carrying value of its investment downward by a cumulative total $194 million as of March 31, 2004, ($197 million as of December 31, 2003). These non-cash adjustments continue to occur based on fluctuations in the Argentine peso. They do not affect net income, but increase or decrease other comprehensive income (loss) and accumulated other comprehensive income (loss). A decision is expected in early 2005 on SEI's arbitration proceedings under the 1994 Bilateral Investment Treaty between the United States and Argentina for recovery of the diminution of the value of its investments that has resulted from Argentine governmental actions. Sempra Energy also has a $48.5 million political-risk insurance policy under which it filed a claim to recover a portion of the investments' diminution in value. LITIGATION Except for the matters referred to below, neither the company nor its subsidiaries 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. DWR Contract In 2003, SER was awarded judgment in its favor in the state civil action between SER and the DWR, in which the DWR sought to void its 10-year contract under which the company sells energy to the DWR. The DWR filed an appeal of this ruling in January 2004. A decision by the appellate court is expected sometime during 2005. The DWR continues to accept all scheduled power from SER and, although it has disputed billings in an immaterial amount and the manner of certain deliveries, it has paid all amounts that have been billed under the contract. In February 2004, the DWR commenced an arbitration proceeding, disputing SER's performance on four operational matters. On April 20, 2004, SER filed a motion for a preliminary injunction to stay arbitration of three of the matters. Among other proposed remedies, the DWR has requested a declaration by the arbitration panel that SER's performance on certain of these issues constitutes a material breach of the agreement permitting it to terminate the contract. SER believes these claims are without merit. Antitrust Litigation Class-action and individual lawsuits filed in 2000 and currently consolidated in San Diego Superior Court seek damages, alleging that Sempra Energy, SoCalGas and SDG&E, along with El Paso Energy Corp. (El Paso) and several of its affiliates, unlawfully sought to control natural gas and electricity markets. In March 2003, plaintiffs in these cases and the applicable El Paso entities (whose cases involved additional issues not applicable to Sempra Energy, SoCalGas or SDG&E) announced that they had reached a $1.5 billion settlement, of which $125 million is allocated to customers of the California Utilities. The Court approved that settlement in December 2003. The proceeding against Sempra Energy and the California Utilities has not been settled, is currently in discovery and continues to be litigated. Natural Gas Cases: Similar lawsuits have been filed by the Attorneys General of Arizona and Nevada, alleging that El Paso and certain Sempra Energy subsidiaries unlawfully sought to control the natural gas market in their respective states. In October 2003, the Nevada state court denied defendants' motion to dismiss the complaint. On April 12, 2004, the Sempra Energy defendants filed a motion for reconsideration. In April 2003, Sierra Pacific Resources and its utility subsidiary Nevada Power filed a lawsuit in U.S. District Court in Las Vegas against major natural gas suppliers, including Sempra Energy, the California Utilities and other company subsidiaries, seeking damages resulting from an alleged conspiracy to drive up or control natural gas prices, eliminate competition and increase market volatility, breach of contract and wire fraud. On January 27, 2004, the U.S. District Court dismissed the Sierra Pacific Resources case against all of the defendants, determining that this is a matter for the FERC. Plaintiffs have asked the court to reconsider its decision. Electricity Cases: Various lawsuits, which seek class-action certification, allege that Sempra Energy and certain subsidiaries (SDG&E, SET and SER, depending on the lawsuit) unlawfully manipulated the electric-energy market. In January 2003, the applicable federal court granted a motion to dismiss a similar lawsuit on the grounds that the claims contained in the complaint were subject to the Filed Rate Doctrine and were preempted by the Federal Power Act. That ruling has been appealed in the Ninth Circuit Court of Appeals. Oral argument has not yet been scheduled by the Court. In addition, in May 2003, the Port of Seattle filed an action alleging that a number of energy companies, including Sempra Energy, SER and SET, unlawfully manipulated the electric energy market and committed wire fraud. That action has been transferred to San Diego Federal District Court and is currently pending a Court-decision on defendants' motion to dismiss 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. SER, SET and SDG&E, along with all other sellers in the western power market, have been named defendants in a complaint filed at the FERC by the California Attorney General's office seeking refunds for electricity purchases based on alleged violations of FERC tariffs. The FERC has dismissed the complaint. The California Attorney General has filed an appeal in the Ninth Circuit of Appeals. The matter was argued before the Ninth Circuit Court in October 2003. No decision has yet been rendered. Price Reporting Practices In the fourth quarter of 2002, Sempra Energy and SoCalGas were named as defendants in a lawsuit filed in Los Angeles Superior Court against various trade publications and other energy companies alleging that energy prices were unlawfully manipulated by defendants' reporting artificially inflated natural gas prices to trade publications. On July 8, 2003, the Superior Court granted the defendants' demurrer 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. Plaintiffs filed an amended complaint, and in September 2003 defendants filed a demurrer to the amended complaint, which was granted in part. In December 2003, the plaintiffs dismissed both Sempra Energy and SoCalGas from the lawsuit. In May 2003 and again in February 2004, similar actions were filed in San Diego Superior Court against Sempra Energy and SET. Both actions have been removed to Federal District Court. Another lawsuit containing identical allegations was filed against Sempra Energy and SET in Federal District Court in November of 2003. In addition, in August 2003, a lawsuit was filed in the Southern District of New York against Sempra Energy and SES, alleging that the prices of natural gas options traded on the NYMEX were unlawfully increased under the Federal Commodity Exchange Act by defendants' manipulation of transaction data to natural gas trade publications. In November of 2003, another suit containing identical allegations was filed and consolidated with the New York action. In December 2003, plaintiffs dismissed Sempra Energy from these cases and in January 2004, SES was also dismissed. On January 20, 2004, plaintiffs filed an amended consolidated complaint that named SET as a defendant in this lawsuit. In March 2004, defendants filed a motion to dismiss the action. No hearing date has been set by the Court. Other On August 21, 2003, the CPUC denied a rehearing requested by opponents of its December 2002 decision that had approved a settlement with SDG&E allocating between SDG&E customers and shareholders the profits from intermediate-term purchase power contracts that SDG&E had entered into during the early stages of California's electric utility industry restructuring. As previously reported, the settlement provided $199 million of these profits to customers, by reductions to balancing account undercollections in prior years. The settlement provided the remaining $173 million of profits to SDG&E shareholders, of which $57 million had been recognized for financial reporting purposes in prior years. As a result of the decision, SDG&E recognized additional after- tax income of $65 million in the third quarter of 2003. The Utility Consumers' Action Network, a consumer-advocacy group which had requested the CPUC rehearing, appealed the decision to the California Court of Appeals and the court agreed to hear the case. Oral argument has not yet been scheduled by the Court. The company expects that the Court of Appeals will affirm the CPUC's decision. In May 2003, a federal judge issued an order finding that the Department of Energy's (DOE) abbreviated assessment of two Mexicali power plants, including SER's Termoelectrica de Mexicali (TDM) plant, failed to evaluate the plants' environmental impact adequately and called into question the U.S. permits they received to build their cross-border transmission lines. In July 2003, the judge ordered the DOE to conduct additional environmental studies and denied the plaintiffs' request for an injunction blocking operation of the transmission lines, thus allowing the continued operation of the TDM plant. The DOE has until May 15, 2004, to demonstrate why the court should not set aside the permits. In 1999, Sempra Energy and PSEG each acquired a 44-percent interest in Luz Del Sur, a Peruvian electric distribution company. Local law required that assets built with government funds be purchased by the local utility and added to rate base. A dispute arose between the government and Luz Del Sur over the amount of compensation due for the 194 projects transferred to Luz Del Sur by the government. The government claims the amount owed was $36 million. Luz Del Sur argued that the amount was less and the matter was settled with the government for approximately $10 million. Following a change in the Peruvian government, a criminal charge was filed against certain government officials, and utility officials as accomplices, including the chief executive officer and chief financial officer of Luz Del Sur, alleging that the settlements were inadequate. In September 2003 a Peruvian court ordered the prosecutor's case to be dismissed. Although the prosecutor has indicated no evidence of wrongdoing in the case, the prosecutor has appealed this decision and the case rests in a higher Peruvian court. A decision is expected during the first half of 2004. At March 31, 2004, SET remains due approximately $100 million from energy sales made in 2000 and 2001 through the ISO and the PX markets. The collection of these receivables depends on the resolution of the financial difficulties experienced by Pacific Gas & Electric and the PX as a result of the California electric industry crisis. SET has submitted relevant claims in the PG&E and PX bankruptcy proceedings. The company believes adequate reserves have been recorded. INCOME TAX ISSUES Section 29 Income Tax Credits In 2003 the Internal Revenue Service (IRS) issued Announcement 2003-46, stating it has reason to question the scientific validity of testing procedures and results related to Section 29 income tax credits. The notice also announced that it would suspend the issuance of new rulings until its review is complete and that rulings could be revoked if the IRS did not determine that the test procedures demonstrate a significant chemical change between the feedstock coal and the synthetic fuel. The IRS completed its review and on October 29, 2003, announced that it would again be issuing private letter rulings based on the previous requirements. Many such rulings have been issued since that date, including one involving operations owned by the company. The Permanent Subcommittee on Investigations of the U.S. Senate's Committee on Governmental Affairs has initiated an investigation on the subject of these income tax credits. In January 2004, the company received a letter from the Committee requesting certain information about its synthetic fuel operations and it is in the process of responding to this inquiry. As part of its audit program for the company for the period 1998-2001, the IRS is nearing completion of examinations of SET's and SEF's credits and the company believes the credits will be sustained. From acquisition of the facilities in 1998 through December 31, 2003, the company has generated Section 29 income tax credits of $251 million. In addition, the company has generated Section 29 tax credits of $24 million for the quarter ended March 31, 2004. The company believes disallowance of Section 29 income tax credits generated during tax years not currently under audit is unlikely. NOTE 8. SEGMENT INFORMATION The company is a holding company, whose subsidiaries are primarily engaged in the energy business. It has four separately managed reportable segments: SoCalGas, SDG&E, SET and SER, which are described in the Annual Report. The accounting policies of the segments are described in the notes to Consolidated Financial Statements in the Annual Report, and segment performance is evaluated by management based on reported income. California utility transactions are based on rates set by the CPUC and FERC. There were no significant changes in segment assets during the quarter ended March 31, 2004. - ------------------------------------------------------------- Quarters ended March 31, ---------------------- (Dollars in millions) 2004 2003 - ------------------------------------------------------------- Operating Revenues: Southern California Gas Company $ 1,148 $ 1,008 San Diego Gas & Electric 580 562 Sempra Energy Trading 301 223 Sempra Energy Resources 277 90 All other 68 50 Intersegment revenues (14) (10) ---------------------- Total $ 2,360 $ 1,923 - ------------------------------------------------------------- Net Income (Loss): Southern California Gas Company $ 56 $ 58 San Diego Gas & Electric* 50 45 Sempra Energy Trading 59 (18) Sempra Energy Resources 37 10 All other (5) (7) ---------------------- Total $ 197 $ 88 - ------------------------------------------------------------- * after preferred dividends ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion should be read in conjunction with the financial statements contained in this Form 10-Q and "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained in the Annual Report. OVERVIEW Sempra Energy Sempra Energy is a Fortune 500 energy services holding company. Its business units provide a wide spectrum of value-added electric and natural gas products and services to a diverse range of customers. Operations are divided between delivery services, comprised of the California utility subsidiaries, and Sempra Energy Global Enterprises (Global). RESULTS OF OPERATIONS Net income and operating income for the quarter were up substantially over the first quarter of 2003. The following table summarizes the major factors affecting the comparisons for the two quarters. Net Operating (Dollars in millions) Income Income - ------------------------------------------------------------------- 2003 Quarter $ 88 $ 215 Change in accounting principle in 2003 29 -- Loss from discontinued operations in 2003 3 -- SONGS incentive pricing (ended 12/31/03) (12) (20) ----------------------- 108 195 Gain on settlement of Cameron liability in 2004 8 13 Loss from discontinued operations in 2004 (24) -- Operations (2004 compared to 2003) 105 124 ----------------------- 2004 Quarter $ 197 $ 332 - ------------------------------------------------------------------- California Utility Revenues and Cost of Sales. Natural gas revenues increased to $1.3 billion in 2004 from $1.2 billion in 2003, and the cost of natural gas distributed increased to $824 million in 2004 from $677 million in 2003. These changes were primarily attributable to natural gas cost increases, which are passed on to customers, and increased volumes. 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, SoCalGas' Gas Cost Incentive Mechanism (GCIM) allows SoCalGas to share in the savings or costs from buying natural gas for customers below or above monthly benchmarks. The mechanism permits full recovery of all costs within a tolerance band above the benchmark price and refunds all savings within a tolerance band below the benchmark price. The costs or savings outside the tolerance band are shared between customers and shareholders. In addition, SDG&E's natural gas procurement Performance- Based Regulation (PBR) mechanism provides an incentive mechanism by measuring SDG&E's procurement of natural gas against a benchmark price comprised of monthly natural gas indices, resulting in shareholder rewards for costs achieved below the benchmark and shareholder penalties when costs exceed the benchmark. Electric revenues decreased to $381 million in 2004 from $395 million in 2003, and the cost of electric fuel and purchased power decreased to $127 million in 2004 from $163 million in 2003. These changes were mainly due to decreases in electric commodity costs partially offset by higher volumes. Under the current regulatory framework, changes in commodity costs normally do not affect net income. During 2004 and 2003, revenues and costs associated with long-term contracts allocated to SDG&E from the DWR were not included in the income statement, since the DWR retains legal and financial responsibility for these contracts. The tables below summarize the natural gas and electric volumes and revenues by customer class for the quarters ended March 31, 2004 and 2003. Gas Sales, Transportation and Exchange (Volumes in billion cubic feet, dollars in millions)

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

Although commodity-related revenues from the DWR's allocated contracts are not included in revenue, the associated volumes and distribution revenue are included herein. Other Operating Revenues Other operating revenues, which consist primarily of revenues from Global, increased to $646 million in 2004 from $366 million in 2003. This change was primarily due to higher revenues at SER resulting from increased volumes associated with contract sales of electricity to the DWR and higher revenues at SET resulting from higher commodity revenue from metals and European power. Other Cost of Sales Other cost of sales, which consists primarily of cost of sales at Global, increased to $327 million in 2004 from $219 million in 2003, primarily due to the higher sales noted above for SER. Other Operating Expenses Other operating expenses increased to $521 million in 2004 from $445 million in 2003, including $343 million and $318 million in 2004 and 2003, respectively, related to the California Utilities. The change was primarily due to increased operating costs at SET related to increased trading activity, as well as higher labor and employee benefit costs at the California Utilities and nuclear refueling costs at SONGS. Other Income (Loss) - Net Other income, which primarily consists of equity earnings from unconsolidated subsidiaries and interest on regulatory balancing accounts, increased to $5 million in 2004 from a net expense of $2 million in 2003. The change was primarily due to the $8 million after- tax settlement of an unpaid portion of the purchase price of the proposed Cameron LNG project for an amount less than the liability (which had been recorded as a derivative), partially offset by higher regulatory interest expense at SoCalGas. Interest Income Interest income increased to $23 million in 2004 from $12 million in 2003 due primarily to interest income earned from the Internal Revenue Service during the 2004 quarter. Income Taxes Income tax expense was $57 million in 2004 and $24 million in 2003. The effective income tax rate was 20.5 percent and 16.7 percent, respectively. The increase in income tax expense was due primarily to higher taxable income and a higher effective income tax rate in 2004 offset by the reduction of certain prior year state income tax liabilities. Further discussion of Section 29 credits is provided in Note 7 of the notes to Consolidated Financial Statements in the Annual Report. Discontinued Operations During the first quarter of 2004 Sempra Energy's Board of Directors approved management's plan to dispose of its interest in Atlantic Electric & Gas Limited (AEG). This disposal meets the criteria established for recognition as discontinued operations under SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." The financial results of AEG are reported separately as discontinued operations for both quarters presented. AEG's losses were $24 million or $0.10 per diluted share in 2004 compared to $3 million or $0.01 per diluted share in 2003. Sempra Energy consolidated AEG in its financial statements at December 31, 2003 as a result of the adoption of FIN 46. On April 27, 2004, the company entered into a sales agreement which is expected to result in no significant gain or loss. Note 4 of the notes to Consolidated Financial Statements provides further details. Net Income Net income increased to $197 million, or $0.85 per diluted share of common stock, in 2004 from $88 million, or $0.42 per diluted share in 2003. Excluding the effects of the cumulative effect of the change in accounting principle ($0.14 per diluted share), which is discussed in Note 2 of the notes to Consolidated Financial Statements, income from continuing operations was $221 million, or $0.96 per diluted share in 2004 compared to $120 million, or $0.58 per diluted share in 2003. The change was primarily due to higher net income from SET and SER as discussed below. The only differences between basic and diluted earnings per share are the effects of common stock options and the Equity Units, which are discussed in Note 12 of the notes to Consolidated Financial Statements in the Annual Report. Net Income by Business Unit Quarters ended March 31, - --------------------------------------------------------------- (Dollars in millions) 2004 2003 - --------------------------------------------------------------- California Utilities Southern California Gas Company $ 56 $ 58 San Diego Gas & Electric 50 45 ------ ------ Total Utilities 106 103 Global Enterprises Sempra Energy Trading 59 10 Sempra Energy Resources 37 10 Sempra Energy International/LNG 17 7 Sempra Energy Solutions (4) -- ------ ------ Total Global Enterprises 109 27 Sempra Energy Financial 10 11 Parent and Other (4) (21) ------ ------ Continuing Operations 221 120 Discontinued Operations (24) (3) Cumulative Effect of Change in Accounting Principle -- (29)* ------ ------ Consolidated Net Income $ 197 $ 88 ====== ====== - --------------------------------------------------------------- * The effects to SET and SES were ($28) million and ($1) million, respectively. SOUTHERN CALIFORNIA GAS COMPANY Net income for SoCalGas decreased to $56 million in 2004 from $58 million in 2003, as higher 2004 revenues were offset by increased operating costs. SAN DIEGO GAS & ELECTRIC Net income for SDG&E increased to $50 million in 2004 compared to $45 million in 2003, primarily due to higher transmission and distribution revenue offset partially by higher operating costs and the absence of the 2003 Incremental Cost Incentive Pricing for SONGS and performance- based regulation gains. SEMPRA ENERGY TRADING SET recorded net income of $59 million in 2004 compared to $10 million in 2003, excluding the cumulative effect of the change in accounting principle of ($28) million. The change in 2004 was primarily attributable to higher trading margin on metals and European power commodities. A summary of SET's unrealized revenues for trading activities for the quarters ended March 31, 2004 and 2003 follows: (Dollars in millions) 2004 2003 - ------------------------------------------------------------------ Balance at December 31 $ 269 $ 180 Cumulative effect adjustment -- (48) Additions 640 299 Realized (448) 11 ------------------------------------- Balance at March 31 $ 461 $ 442 - ------------------------------------------------------------------ The estimated fair values for SET's trading activities as of March 31, 2004, and the periods during which unrealized revenues are expected to be realized, are (dollars in millions):

SET's Value at Risk (VaR) amounts are described in Item 3. See also the discussion concerning the CPUC's prohibition of IOUs' procuring electricity from their affiliates in "Electric Industry Regulation" in Note 13 of the notes to Consolidated Financial Statements in the Annual Report. SEMPRA ENERGY RESOURCES SER recorded net income of $37 million in 2004 compared to $10 million in 2003. The change was primarily due to higher volumes associated with contract sales of electricity to the DWR. During March 2004 the El Dorado generating plant, 50% owned by SER, suffered significant damage to a transformer requiring the plant to cease operations temporarily. Temporary/permanent equipment is currently expected to be installed. The plant is anticipated to recommence operations near the end of the second quarter of 2004, but repairs could extend until near the end of the third quarter of 2004. The impact on operating margins will not be significant if the plant returns to service near the end of the second quarter of 2004. SER is expected to be able to meet its contractual obligations for the sale of power. Damage and/or insurance claims will be filed for the cost of repairs, replacement and related project losses during this period. SEMPRA ENERGY INTERNATIONAL/LNG SEI/SELNG recorded net income of $17 million in 2004 compared to $7 million in 2003. The increase was due primarily to the settlement of an unpaid portion of the purchase price of the proposed Cameron LNG project for an amount less than the liability (which had been recorded as a derivative). SEMPRA ENERGY SOLUTIONS SES recorded a net loss of $4 million in 2004 compared to break even results in 2003, excluding the ($1) million cumulative effect of the change in accounting principle. The increase was primarily due to lower net commodity revenues in 2004. SEMPRA ENERGY FINANCIAL SEF recorded net income of $10 million and $11 million for the quarters ended March 31, 2004 and 2003, respectively. PARENT AND OTHER Net losses for Parent and Other were $4 million in 2004 compared to $21 million in 2003. The change was due primarily to increased interest income in 2004 and the reduction of certain prior year state income tax liabilities. CAPITAL RESOURCES AND LIQUIDITY The company's California Utility operations are the major source of liquidity. Funding of other business units' capital expenditures is significantly dependent on the California Utilities' paying sufficient dividends to Sempra Energy and on SET's liquidity requirements, which fluctuate significantly. At March 31, 2004, the company had $653 million in cash and $2.1 billion in available unused, committed lines of credit. Management believes these amounts and cash flows from operations and new security issuances will be adequate to finance capital expenditure requirements, shareholder dividends, any new business acquisitions or start-ups, and other commitments. If cash flows from operations were to be significantly reduced or the company was to be unable to issue new securities under acceptable terms, neither of which is considered likely, the company would be required to reduce non-utility capital expenditures and investments in new businesses. 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. At the California Utilities, cash flows from operations and from new and refunding debt issuances are expected to continue to be adequate to meet utility capital expenditure requirements and provide dividends to Sempra Energy. However, if SDG&E receives CPUC approval of its plans to purchase from SER a 550-megawatt (MW) generating facility to be constructed in Escondido, California, the level of SDG&E's dividends to Sempra Energy is expected to be significantly lower during the construction of the facility to enable SDG&E to increase its equity in preparation for the purchase of the completed facility. In April 2004, a proposed CPUC decision approved SDG&E's plan to buy the generating facility. A final CPUC decision is scheduled for May 2004. SET provides or requires cash as the level of its net trading assets fluctuates with prices, volumes, margin requirements (which are substantially affected by credit ratings and commodity price fluctuations) and the length of its various trading positions. Its status as a source or use of cash also varies with its level of borrowing from its own sources. SET's intercompany borrowings were $279 million at March 31, 2004, down from $359 million at December 31, 2003. SET's external debt was $149 million at March 31, 2004. Company management continuously monitors the level of SET's cash requirements in light of the company's overall liquidity. SELNG will require funding for its planned development of liquefied natural gas (LNG) receiving facilities. While funding from the company is expected to be adequate for these requirements, the company may decide to use project financing if that is believed to be advantageous. SEI is expected to require funding from the company and/or external sources to continue the expansion of its existing natural gas distribution operations in Mexico and its planned development of pipelines to serve LNG facilities expected to be developed in Baja California, Mexico; Hackberry, Louisiana; and Port Arthur, Texas, as discussed in "Cash Flows From Investing Activities," below. SER's projects are expected to be financed through a combination of project financing, SER's borrowings and funds from the company. In the longer term, SEF is expected to again be a net provider of cash through reductions of consolidated income tax payments resulting from its investments in affordable housing and synthetic fuel. However, that was not true in 2003 and will not be true in the near term, while the company is in an alternative minimum tax position. CASH FLOWS FROM OPERATING ACTIVITIES Net cash provided by operating activities totaled $782 million and $691 million for the quarters ended March 31, 2004 and 2003, respectively. The change was attributable to higher net income, the increase in overcollected balancing accounts and lower accounts receivable in 2004. For the quarter ended March 31, 2004, the company made pension plan contributions of $1 million for the 2004 plan year. CASH FLOWS FROM INVESTING ACTIVITIES Net cash provided by (used in) investing activities totaled $149 million and $(319) million for the quarters ended March 31, 2004 and 2003, respectively. The change was attributable to proceeds from the sale of U.S. Treasury obligations which previously securitized the Mesquite synthetic lease. The collateral was no longer necessary as SER bought out the lease in January 2004. Starting in 2003 and through the end of the first quarter of 2004, SET spent $50 million related to the development of Bluewater Gas Storage, LLC. SET owns the rights to develop the facility and to utilize its capacity to store natural gas for customers who buy, sell or transport natural gas to Michigan. The Federal Energy Regulatory Commission (FERC)-regulated, market-based pricing facility is expected to inject cushion gas starting in early May 2004. On April 1, 2004, SEI and PSEG Global, an unaffiliated company, sold a portion of their interests in Luz del Sur S.A.A. (Luz del Sur), a Peruvian electric utility, for a total of $62 million. Prior to the sale, each party had a 44-percent interest in Luz del Sur. SEI expects to recognize an after-tax gain of $5 million as a result of the sale. On April 16, 2004, the company announced the acquisition of land and associated rights for the development of a salt-cavern natural gas storage facility in Evangeline Parish, Louisiana. This facility, operating as the Pine Prairie Energy Center, will consist of three salt caverns with a total capacity of 24 billion cubic feet (bcf) of natural gas per day and is expected to begin operations by the fourth quarter of 2005 and to cost approximately $160 million. The company is currently negotiating contracts to sell the output of this facility. On April 21, 2004, SELNG announced plans to develop and construct a new $600 million LNG receiving terminal near Port Arthur, Texas. The terminal would be capable of processing 1.5 bcf of natural gas per day and could be expanded to 3 bcf per day. The company is currently in the process of obtaining FERC approval for the construction of the terminal. The project is expected to begin construction in 2006 with start-up slated for 2009. The company expects to make capital expenditures and investments of $1.1 billion in 2004. Significant capital expenditures and investments are expected to include $750 million for California utility plant improvements and $110 million for the development of LNG regasification terminals. These expenditures and investments are expected to be financed by cash flows from operations and security issuances. In connection with the importation of additional sources of natural gas into Southern California, for which the California Utilities have made filings with the CPUC, the California Utilities could incur capital expenditures estimated at $200 million in order to connect with new delivery locations. The expenditures would be included in utility rate bases. In addition to its normal capital expenditures related to its distribution and transmission systems and its share of the additional $200 million referred to above, SDG&E expects to be making significant capital expenditures for the proposed generation resources referred to in Note 6 of the notes to Consolidated Financial Statements. On March 15, 2004, Sempra Energy Partners and Carlyle/Riverstone, an energy and power-focused equity fund, announced a joint purchase and sales agreement with American Electric Power (AEP) to acquire AEP's Coleto Creek Power Station, a 632-MW coal-fired power plant in Goliad County, Texas, for $430 million. The transaction also includes the acquisition of five other operating power plants with generating capacity of 1,318 MW and four currently inactive power plants (capable of generating 1,863 MW) in Texas. The transaction is expected to be substantially project financed on a non-recourse basis and to close in July 2004. CASH FLOWS FROM FINANCING ACTIVITIES Net cash used in financing activities totaled $708 million and $24 million for the quarters ended March 31, 2004 and 2003, respectively. In January 2004, SER purchased the assets of Mesquite Trust, the owner of the Mesquite Power plant, thereby extinguishing $630 million of debt outstanding. The increase in cash used in financing activities to repay the Mesquite debt along with SoCalGas' repayment of $175 million of first mortgage bonds and lower long-term debt issuances in 2004 were partially offset by an increase in short-term debt in 2004. FACTORS INFLUENCING FUTURE PERFORMANCE Base results of the company in the near future will depend primarily on the results of the California Utilities, while earnings growth and variability will result primarily from activities at SET, SER, SELNG and SEI. Notes 6 and 7 of the notes to Consolidated Financial Statements herein and Notes 13 through 15 of the notes to Consolidated Financial Statements in the Annual Report describe events in the deregulation of California's electric and natural gas industries and various FERC, SET and income tax issues. California Utilities Note 6 of the notes to Consolidated Financial Statements contains discussions of electric and natural gas restructuring and rates, the pending cost of service filings and the CPUC's investigation of compliance with affiliate rules. Sempra Energy Global Enterprises Electric-Generation Assets As discussed in more detail in "Cash Flows From Investing Activities," the company is involved in the development of several electric- generation projects that will significantly impact the company's future performance, including the AEP-related acquisition noted above. Investments As discussed in "Cash Flows From Investing Activities," the company's investments will significantly impact the company's future performance. SELNG is in the process of developing Energia Costa Azul, an LNG receiving terminal in Baja California, Mexico, the Cameron LNG receiving terminal in Hackberry, Louisiana, and the Port Arthur LNG receiving terminal near Port Arthur, Texas. The viability and future profitability of this business unit is dependent upon numerous factors, including the relative prices of natural gas in North America and from LNG suppliers located elsewhere, negotiating sale and supply contracts at adequate margins, and completing cost-effective construction of the required facilities. SEI is expected to require funding from the company and/or external sources to continue the expansion of its existing natural gas distribution operations in Mexico and its planned development of pipelines to serve LNG facilities noted above. The Argentine economic decline and government responses (including Argentina's unilateral, retroactive abrogation of utility agreements early in 2002) are continuing to adversely affect the company's investment in two Argentine utilities. Information regarding this situation is provided in Note 7 of the notes to Consolidated Financial Statements. CRITICAL ACCOUNTING POLICIES AND KEY NON-CASH PERFORMANCE INDICATORS There have been no significant changes to the accounting policies viewed by management as critical or key non-cash performance indicators for the company's subsidiaries, as set forth in the Annual Report. NEW ACCOUNTING STANDARDS Relevant pronouncements that have recently become effective and have had a significant effect on the company are Statement of Financial Accounting Standards (SFAS) Nos. 143, 149 and 150, Financial Accounting Standards Board Interpretation Nos. (FIN) 45 and 46, and Emerging Issues Task Force (EITF) 98-10 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. EITF Issue 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities": In accordance with the EITF's rescission of Issue 98-10, the company no longer recognizes energy- related contracts under mark to market accounting unless the contracts meet the requirements stated under SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," which is the case for a substantial majority of the company's contracts. Upon adoption of this consensus on January 1, 2003, the company recorded the initial effect of rescinding Issue 98-10 as a cumulative effect of a change in accounting principle, which reduced after-tax earnings by $29 million. SFAS 143, "Accounting for Asset Retirement Obligations": SFAS 143 requires entities to record the fair value of liabilities for legal obligations related to asset retirements in the period in which they are incurred. It also requires most energy utilities, including the California Utilities, to reclassify amounts recovered in rates for future removal costs not covered by a legal obligation from accumulated depreciation to a regulatory liability. Further discussion is provided in Note 2 of the notes to Consolidated Financial Statements. SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities": SFAS 149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS 133. Under SFAS 149 natural gas forward contracts that are subject to unplanned netting do not qualify for the normal purchases and normal sales exception. The company has determined that all natural gas contracts are subject to unplanned netting and as such, these contracts will be marked to market. In addition, effective January 1, 2004, power contracts that are subject to unplanned netting and that do not meet the normal purchases and normal sales exception under SFAS 149 will be further marked to market. Implementation of SFAS 149 on July 1, 2003 did not have a material impact on reported net income. FIN 46, "Consolidation of Variable Interest Entities an interpretation of ARB No. 51": In January 2003, the FASB issued FIN 46 to strengthen existing accounting guidance that addresses when a company should consolidate a variable interest entity (VIE) in its financial statements. Adoption of FIN 46 on December 31, 2003 resulted in the consolidation of two VIEs for which Sempra Energy is the primary beneficiary. One of the VIEs (the Mesquite Trust) was the owner of the Mesquite Power plant for which the company had a synthetic lease agreement. The other VIE relates to the investment in AEG. Sempra Energy consolidated these entities in its financial statements at December 31, 2003. During the first quarter of 2004 Sempra Energy's Board of Directors approved management's plan to dispose of AEG. Note 4 of the notes to Consolidated Financial Statements provides further discussion on this matter. In accordance with FIN 46, the company has deconsolidated a wholly owned subsidiary trust from its financial statements at December 31, 2003. Further discussion regarding FIN 46 is provided in Note 2 of the notes to Consolidated Financial Statements. 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. The Value at Risk (VaR) for SET at March 31, 2004, and the average VaR for the quarter ended March 31, 2004, at the 95-percent and 99-percent confidence intervals (one-day holding period) were as follows (in millions of dollars): 95% 99% - ------------------------------------------------------ At March 31, 2004 $ 10.0 $ 14.2 Average for the quarter ended March 31, 2004 $ 5.7 $ 8.1 - ------------------------------------------------------ As of March 31, 2004, the total VaR of the California Utilities' and SES' positions was not material. ITEM 4. CONTROLS AND PROCEDURES The company has designed and maintains disclosure controls and procedures to ensure that information required to be disclosed in the company's reports under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and is accumulated and communicated to the company's management, including its Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating these controls and procedures, management recognizes that any system of controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired objectives and necessarily applies judgment in evaluating the cost-benefit relationship of other possible controls and procedures. In addition, the company has investments in unconsolidated entities that it does not control or manage and, consequently, its disclosure controls and procedures with respect to these entities are necessarily substantially more limited than those it maintains with respect to its consolidated subsidiaries. Under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer, the company as of March 31, 2004 has evaluated the effectiveness of the design and operation of the company's disclosure controls and procedures. Based on that evaluation, the company's Chief Executive Officer and Chief Financial Officer have concluded that the controls and procedures are effective. There have been no significant changes in the company's internal controls over financial reporting or in other factors that could significantly affect the internal controls subsequent to the date the company completed its evaluation. PART II - OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS SDG&E has been advised by the County of San Diego that the county is considering initiating legal proceedings against SDG&E relating to alleged environmental law violations by SDG&E and its contractors in connection with the abatement of asbestos-containing materials during the demolition of a natural gas storage facility that was completed in 2001. SDG&E disputes the county's allegations and believes that the abatement of these materials was properly managed. The county has indicated a willingness to settle this matter for less than $1 million. Except as described above and in Notes 6 and 7 of the notes to Consolidated Financial Statements, neither the company nor its subsidiaries are party to, nor is their property the subject of, any material pending legal proceedings other than routine litigation incidental to their businesses. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits Exhibit 12 - Computation of ratios 12.1 Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends. Exhibit 31 -- Section 302 Certifications 31.1 Statement of Registrant's Chief Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934. 31.2 Statement of Registrant's Chief Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934. Exhibit 32 -- Section 906 Certifications 32.1 Statement of Registrant's Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350. 32.2 Statement of Registrant's Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350. (b) Reports on Form 8-K The following reports on Form 8-K were filed after December 31, 2003: Current Report on Form 8-K filed February 24, 2004, filing as an exhibit Sempra Energy's press release of February 24, 2004, giving the financial results for the quarter ended December 31, 2003. Current Report on Form 8-K filed April 29, 2004, filing as an exhibit Sempra Energy's press release of April 29, 2004, giving the financial results for the quarter ended March 31, 2004. SIGNATURE Pursuant to the requirements 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. SEMPRA ENERGY ------------------- (Registrant) Date: April 29, 2004 By: /s/ F. H. Ault ---------------------------- F. H. Ault Sr. Vice President and Controller EX-12 2 seratios032004.htm EX 12.1 RATIOS EXHIBIT 12 Sempra Energy Ratios

EXHIBIT 12.1
SEMPRA ENERGY
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS
(Dollars in millions)


						Quarter ended
	1999	2000	2001	2002	2003	March 31, 2004

Fixed Charges and Preferred Stock Dividends:

Interest	$ 233	$ 308	$ 358	$ 350	$ 351	$ 85

Interest portion of annual rentals	10	8	6	6	5	1

Preferred dividends of subsidiaries (1)	16	18	16	15	11	3


Combined fixed charges and preferred stock
dividends for purpose of ratio	$ 259	$ 334	$ 380	$ 371	$ 367	$ 89




Earnings:

Pretax income from continuing operations	$ 573	$ 699	$ 731	$ 721	$ 742	$ 278

Total fixed charges (from above)	259	334	380	371	367	89

Less:
Interest capitalized	1	3	11	29	26	4
Equity in income (loss) of unconsolidated
subsidiaries and joint ventures	-	62	12	(55)	8	(6)


Total earnings for purpose of ratio	$ 831	$ 968	$ 1,088	$ 1,118	$ 1,075	$ 369




Ratio of earnings to combined fixed charges
and preferred stock dividends	3.21	2.90	2.86	3.01	2.93	4.15




(1) In computing this ratio, "Preferred dividends of subsidiaries" represents the before-tax earnings necessary to pay such dividends,
computed at the effective tax rates for the applicable periods.

EX-31 3 semprabaumex31qtr.txt EX 31.1 EXHIBIT 31.1 CERTIFICATION I, Stephen L. Baum, certify that: 1. I have reviewed this Quarterly Report on Form 10-Q of Sempra Energy; 2. Based on my knowledge, this Quarterly Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Quarterly Report; 3. Based on my knowledge, the financial statements and other financial information included in this Quarterly Report fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this Quarterly Report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 15(f) and 15d-15(f)) for the registrant and we have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Quarterly Report is being prepared; b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this Quarterly Report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this Quarterly Report, based on such evaluation; and d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls over financial reporting. April 29, 2004 /S/ STEPHEN L. BAUM Stephen L. Baum Chief Executive Officer EX-31 4 sempraschmaleex31qtr.txt EX 31.2 EXHIBIT 31.2 CERTIFICATION I, Neal E. Schmale, certify that: 1. I have reviewed this Quarterly Report on Form 10-Q of Sempra Energy; 2. Based on my knowledge, this Quarterly Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Quarterly Report; 3. Based on my knowledge, the financial statements and other financial information included in this Quarterly Report fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this Quarterly Report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 15(f) and 15d-15(f)) for the registrant and we have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Quarterly Report is being prepared; b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this Quarterly Report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this Quarterly Report, based on such evaluation; and d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls over financial reporting. April 29, 2004 /S/ NEAL E. SCHMALE Neal E. Schmale Chief Financial Officer EX-32 5 semprabaumex32.txt EX 32.1 Exhibit 32.1 Statement of Chief Executive Officer Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Executive Officer of Sempra Energy (the "Company") certifies that: (i) the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarterly period ended March 31, 2004 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and (ii) the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company. April 29, 2004 /S/ STEPHEN L. BAUM ______________________ Stephen L. Baum Chief Executive Officer EX-32 6 sempraschmaleex32.txt EX 32.2 Exhibit 32.2 Statement of Chief Financial Officer Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Financial Officer of Sempra Energy (the "Company") certifies that: (i) the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarterly period ended March 31, 2004 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and (ii) the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company. April 29, 2004 /S/ NEAL E. SCHMALE ______________________ Neal E. Schmale Chief Financial Officer -----END PRIVACY-ENHANCED MESSAGE-----