10-Q 1 se10q0603.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 June 30, 2003 ------------------------------------- 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 July 31, 2003: 208,714,412 --------------------- 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," "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 Department of Water Resources, and the Federal Energy Regulatory Commission; capital market conditions, inflation rates, interest rates and exchange rates; energy and trading markets, including the timing and extent of changes in commodity prices; weather conditions and conservation efforts; war and terrorist attacks; business, regulatory and legal decisions; the status of deregulation of retail natural gas and electricity delivery; the timing and success of business development efforts; and other uncertainties, all of which are difficult to predict and many of which are beyond the control of the company. Readers are cautioned not to rely unduly on any forward-looking statements and are urged to review and consider carefully the risks, uncertainties and other factors which affect the company's business described in this report and other reports filed by the company from time to time with the Securities and Exchange Commission. ITEM 1. FINANCIAL STATEMENTS. SEMPRA ENERGY STATEMENTS OF CONSOLIDATED INCOME (Dollars in millions, except per share amounts)
Three months ended June 30, ------------------ 2003 2002 ------- ------- OPERATING REVENUES California utilities: Natural gas $ 929 $ 754 Electric 397 323 Other 514 411 ------- ------- Total 1,840 1,488 ------- ------- OPERATING EXPENSES California utilities: Cost of natural gas 480 305 Electric fuel and net purchased power 137 79 Other cost of sales 296 206 Other operating expenses 518 475 Depreciation and amortization 149 152 Franchise fees and other taxes 57 43 ------- ------- Total 1,637 1,260 ------- ------- Operating income 203 228 Other income - net 9 8 Interest income 10 10 Interest expense (71) (78) Preferred dividends of subsidiaries (3) (3) Trust preferred distributions by subsidiary (5) (5) ------- ------- Income before income taxes 143 160 Income taxes 27 15 ------- ------- Income before extraordinary item 116 145 Extraordinary item, net of tax -- 2 ------- ------- Net income $ 116 $ 147 ======= ======= Weighted-average number of shares outstanding (thousands): Basic 207,626 205,354 ------- ------- Diluted 210,164 207,084 ------- ------- Income before extraordinary item per share of common stock Basic $ 0.56 $ 0.71 ------- ------- Diluted $ 0.55 $ 0.70 ------- ------- Net income per share of common stock Basic $ 0.56 $ 0.72 ------- ------- Diluted $ 0.55 $ 0.71 ------- ------- Dividends declared per share of common stock $ 0.25 $ 0.25 ======= ======= See notes to Consolidated Financial Statements.
SEMPRA ENERGY STATEMENTS OF CONSOLIDATED INCOME (Dollars in millions, except per share amounts)
Six months ended June 30, ------------------ 2003 2002 ------- ------- OPERATING REVENUES California utilities: Natural gas $ 2,091 $ 1,634 Electric 792 604 Other 880 725 ------- ------- Total 3,763 2,963 ------- ------- OPERATING EXPENSES California utilities: Cost of natural gas 1,157 729 Electric fuel and net purchased power 300 140 Other cost of sales 515 338 Other operating expenses 963 890 Depreciation and amortization 297 300 Franchise fees and other taxes 113 87 ------- ------- Total 3,345 2,484 ------- ------- Operating income 418 479 Other income - net 4 27 Interest income 22 21 Interest expense (145) (147) Preferred dividends of subsidiaries (6) (6) Trust preferred distributions by subsidiary (9) (9) ------- ------- Income before income taxes 284 365 Income taxes 51 74 ------- ------- Income before extraordinary item and cumulative effect of change in accounting principle 233 291 Extraordinary item, net of tax -- 2 ------- ------- Income before cumulative effect of change in accounting principle 233 293 Cumulative effect of change in accounting principle, net of tax (29) -- ------- ------- Net income $ 204 $ 293 ======= ======= Weighted-average number of shares outstanding (thousands): Basic 207,013 205,105 ------- ------- Diluted 208,882 206,729 ------- ------- Income before extraordinary item and cumulative effect of change of accounting principle per share of common stock Basic $ 1.13 $ 1.42 ------- ------- Diluted $ 1.12 $ 1.41 ------- ------- Income before cumulative effect of change in accounting principle per share of common stock Basic $ 1.13 $ 1.43 ------- ------- Diluted $ 1.12 $ 1.42 ------- ------- Net income per share of common stock Basic $ 0.99 $ 1.43 ------- ------- Diluted $ 0.98 $ 1.42 ------- ------- Dividends declared per share of common stock $ 0.50 $ 0.50 ======= ======= See notes to Consolidated Financial Statements.
SEMPRA ENERGY CONSOLIDATED BALANCE SHEETS (Dollars in millions)
--------------------------- June 30, December 31, 2003 2002 ------------ ------------- ASSETS Current assets: Cash and cash equivalents $ 325 $ 455 Accounts receivable - trade 714 754 Accounts and notes receivable - other 108 135 Due from unconsolidated affiliates 144 80 Deferred income taxes 77 20 Trading assets 4,853 5,064 Regulatory assets arising from fixed-price contracts and other derivatives 146 151 Other regulatory assets 90 75 Inventories 129 134 Other 137 142 ------- ------- Total current assets 6,723 7,010 ------- ------- Investments and other assets: Fixed-price contracts and other derivatives 36 42 Due from unconsolidated affiliate 54 57 Regulatory assets arising from fixed-price contracts and other derivatives 740 812 Other regulatory assets 490 532 Nuclear-decommissioning trusts 534 494 Investments 1,446 1,313 Sundry 723 665 ------- ------- Total investments and other assets 4,023 3,915 ------- ------- Property, plant and equipment: Property, plant and equipment 14,367 13,816 Less accumulated depreciation and amortization (6,890) (6,984) ------- ------- Total property, plant and equipment - net 7,477 6,832 ------- ------- Total assets $18,223 $17,757 ======= ======= See notes to Consolidated Financial Statements.
SEMPRA ENERGY CONSOLIDATED BALANCE SHEETS (Dollars in millions)
---------------------------- June 30, December 31, 2003 2002 ------------ ------------- LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities: Short-term debt $ 311 $ 570 Accounts payable - trade 697 694 Accounts payable - other 52 50 Income taxes payable 4 22 Trading liabilities 4,141 4,094 Dividends and interest payable 136 133 Regulatory balancing accounts - net 666 578 Regulatory liabilities 11 18 Fixed-price contracts and other derivatives 151 153 Current portion of long-term debt 204 281 Other 622 654 ------- ------- Total current liabilities 6,995 7,247 ------- ------- Long-term debt 4,214 4,083 ------- ------- Deferred credits and other liabilities: Due to unconsolidated affiliate 162 162 Customer advances for construction 96 91 Post-retirement benefits other than pensions 138 136 Deferred income taxes 791 800 Deferred investment tax credits 87 90 Fixed-price contracts and other derivatives 827 813 Regulatory liabilities arising from asset retirement obligations 241 -- Regulatory liabilities 117 121 Asset retirement obligations 309 -- Deferred credits and other liabilities 812 985 ------- ------- Total deferred credits and other liabilities 3,580 3,198 ------- ------- Preferred stock of subsidiaries 203 204 ------- ------- Mandatorily redeemable trust preferred securities 200 200 ------- ------- Commitments and contingent liabilities (Note 3) SHAREHOLDERS' EQUITY Preferred stock (50,000,000 shares authorized, none issued) -- -- Common stock (750,000,000 shares authorized; 208,203,574 and 204,911,572 shares outstanding at June 30, 2003 and December 31, 2002, respectively) 1,502 1,436 Retained earnings 1,962 1,861 Deferred compensation relating to ESOP (32) (33) Accumulated other comprehensive income (loss) (401) (439) ------- ------- Total shareholders' equity 3,031 2,825 ------- ------- Total liabilities and shareholders' equity $18,223 $17,757 ======= ======= See notes to Consolidated Financial Statements.
SEMPRA ENERGY CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (Dollars in millions)
Six months ended June 30, ------------------- 2003 2002 ------- ------- CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 204 $ 293 Adjustments to reconcile net income to net cash provided by operating activities: Extraordinary item, net of tax -- (2) Cumulative effect of change in accounting principle 29 -- Depreciation and amortization 297 300 Deferred income taxes and investment tax credits (25) (54) Other - net 39 17 Net changes in other working capital components 248 145 Changes in other assets (48) 32 Changes in other liabilities 12 23 ------- ------- Net cash provided by operating activities 756 754 ------- ------- CASH FLOWS FROM INVESTING ACTIVITIES Expenditures for property, plant and equipment (441) (559) Investments and acquisitions of affiliates, net of cash acquired (134) (199) Loan to unconsolidated affiliate (64) -- Dividends received from unconsolidated affiliates -- 9 Other - net -- (10) ------- ------- Net cash used in investing activities (639) (759) ------- ------- CASH FLOWS FROM FINANCING ACTIVITIES Common stock dividends (104) (102) Issuances of common stock 50 11 Repurchases of common stock (6) (4) Issuances of long-term debt 400 800 Payments on long-term debt (339) (303) Decrease in short-term debt (240) (462) Other - net (8) (18) ------- ------- Net cash used in financing activities (247) (78) ------- ------- Decrease in cash and cash equivalents (130) (83) Cash and cash equivalents, January 1 455 605 ------- ------- Cash and cash equivalents, June 30 $ 325 $ 522 ======= ======= SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Interest payments, net of amounts capitalized $ 136 $ 141 ======= ======= Income tax payments, net of refunds $ 94 $ 24 ======= ======= SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES Acquisition of subsidiaries: Assets acquired $ -- $ 1,210 Cash paid -- (199) ------- ------- Liabilities assumed $ -- $ 1,011 ======= ======= See notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. 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, 2002 (Annual Report) and the Quarterly Report on Form 10-Q for the three months ended March 31, 2003. 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. As described in the notes to Consolidated Financial Statements in the Annual Report, the California Utilities account for the economic effects of regulation on utility operations (excluding generation operations) in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation". COMPREHENSIVE INCOME The following is a reconciliation of net income to comprehensive income. Three months Six months ended ended June 30, June 30, --------------------------------- (Dollars in millions) 2003 2002 2003 2002 ----------------------------------------------------------------- Net income $ 116 $ 147 $ 204 $ 293 Foreign currency adjustments 30 (34) 44 (128) Minimum pension liability adjustments -- (14) (6) (14) Financial instruments -- 1 -- -- --------------------------------- Comprehensive income $ 146 $ 100 $ 242 $ 151 ----------------------------------------------------------------- 2. NEW ACCOUNTING STANDARDS 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, 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. 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. Only $18 million of the $29 million had been included in net income through December 31, 2002. However, the $18 million was net of the after-tax effect of income-based expenses, which are not considered in calculating the cumulative effect of the accounting change. As the underlying transactions are completed subsequent to December 31, 2002, and the gains or losses are recorded, the entire $29 million, plus or minus intervening changes in market value, will be included in the calculation of net income. On a net basis, no such realization occurred during the six months ended June 30, 2003. In addition, the ongoing effect of rescinding EITF 98-10 negatively impacted after-tax earnings for the three and six months ended June 30, 2003 by an additional $7 million and $16 million, respectively. Neither the cumulative nor the ongoing effect impacts the company's cash flow or liquidity. Emerging Issues Task Force 02-3 "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities": EITF 02-3 requires gains and losses on trading contracts to be recorded on a net basis in the income statement, effective for financial statements covering periods ending after July 15, 2002. This required that SES change its method of recording trading activities from gross to net, which had no impact on previously recorded gross margin, net income or cash provided by operating activities. SET required no change as it was already recording revenues from trading activities net. Statement of Financial Accounting Standards (SFAS) 142, "Goodwill and Other Intangible Assets": In accordance with SFAS 142, recorded goodwill is tested for impairment. As a result, during the first quarter of 2002, SEI recorded a pre-tax charge of $6 million related to the impairment of goodwill associated with its two domestic subsidiaries. Impairment losses are reflected in other operating expenses in the Statements of Consolidated Income. During the first quarter of 2003 SEI purchased the remaining interests in its Mexican subsidiaries, which resulted in the recording of an addition to goodwill of $10 million. The change in the carrying amount of goodwill (included in noncurrent sundry assets on the Consolidated Balance Sheets) for the six months ended June 30, 2003 are as follows: (Dollars in millions) SET Other Total ------------------------------------------------------------------ Balance as of January 1, 2003 $ 141 $ 41 $ 182 Goodwill acquired during 2003 -- 10 10 --------------------------- Balance as of June 30, 2003 $ 141 $ 51 $ 192 --------------------------- SFAS 143, "Accounting for Asset Retirement Obligations": The adoption of SFAS 143 on January 1, 2003 resulted in the recording of an addition of $71 million to utility plant, representing the company's share of the San Onofre Nuclear Generating Station (SONGS) estimated future decommissioning costs (as discounted to the present value at the dates the units began operation), and accumulated depreciation of $41 million related to the increase to utility plant, for a net increase of $30 million. In addition, the company recorded a corresponding retirement obligation liability of $309 million (which includes accretion of that discounted value to December 31, 2002) and a regulatory liability of $215 million to reflect that SDG&E has collected the funds from its customers more quickly than SFAS 143 would accrete the retirement liability and depreciate the asset. These liabilities, less the $494 million recorded as accumulated depreciation prior to January 1, 2003 (which represents amounts collected for future decommissioning costs), comprise the offsetting $30 million. On January 1, 2003, the company recorded additional asset retirement obligations of $20 million associated with the future retirement of a former power plant and three storage facilities. In accordance with SFAS 143, Sempra Energy identified several other assets for which retirement obligations exist, but whose lives are indeterminate. A liability for these asset retirement obligations will be recorded if and when a life is determinable. The change in the asset retirement obligations for the six months ended June 30, 2003 is as follows (dollars in millions): Balance as of January 1, 2003 $ -- Adoption of SFAS 143 329 Accretion expense 11 Payments made (7) ------ Balance as of June 30, 2003 $ 333* ====== *A portion of the obligation is included in other current liabilities on the Consolidated Balance Sheets. Had SFAS 143 been in effect, the asset retirement obligation liability would have been $315 million, $338 million, $363 million and $329 million as of January 1, 2000 and December 31, 2000, 2001 and 2002, respectively. Except for the items noted above, the company has determined that there is no other material retirement obligation associated with tangible long-lived assets. Implementation of SFAS 143 has had no effect on results of operations and is not expected to have a significant one in the future. SFAS 148 "Accounting for Stock-Based Compensation -- Transition and Disclosure": SFAS 148 requires quarterly disclosure of the effects that would have been recorded if the financial statements applied the fair value recognition principle of SFAS 123 "Accounting for Stock-Based Compensation." The company accounts for stock-based employee compensation plans under the recognition and measurement principles of Accounting Principles Board Opinion 25, "Accounting for Stock Issued to Employees," and related interpretations. For certain grants, no stock- based employee compensation cost is reflected in net income, since each option granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. The following table provides the pro forma effects of recognizing compensation expense in accordance with SFAS 123: Three months ended June 30, ------------------------ 2003 2002 ------------------------ Net income as reported $ 116 $ 147 Stock-based employee compensation expense reported in net income, net of tax 7 (2) Total stock-based employee compensation under fair value method for all awards, net of tax (9) (1) ------------------------ Pro forma net income $ 114 $ 144 ======================== Earnings per share: Basic--as reported $ 0.56 $ 0.72 ======================== Basic--pro forma $ 0.55 $ 0.70 ======================== Diluted--as reported $ 0.55 $ 0.71 ======================== Diluted--pro forma $ 0.54 $ 0.70 ======================== Six months ended June 30, ------------------------ 2003 2002 ------------------------ Net income as reported $ 204 $ 293 Stock-based employee compensation expense reported in net income, net of tax 14 1 Total stock-based employee compensation under fair value method for all awards, net of tax (18) (6) ------------------------ Pro forma net income $ 200 $ 288 ======================== Earnings per share: Basic--as reported $ 0.99 $ 1.43 ======================== Basic--pro forma $ 0.97 $ 1.40 ======================== Diluted--as reported $ 0.98 $ 1.42 ======================== Diluted--pro forma $ 0.96 $ 1.39 ======================== 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. Sempra Energy is currently assessing the impact SFAS 149 will have on its consolidated results of operations and financial position. It will have no effect on cash flows. SFAS 150 "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity": This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS 150 requires that certain mandatorily redeemable financial instruments currently classified in the mezzanine section of the balance sheet be reclassified as liabilities. The company will adopt SFAS 150 in the third quarter of 2003 by changing its presentation of $200 million and $24 million of mandatorily redeemable trust preferred securities and preferred stock of subsidiaries, respectively. FASB Interpretation No. 45 (FIN 45), "Guarantor's Accounting and Disclosure Requirements for Guarantees": FIN 45 elaborates on the disclosures to be made in interim and annual financial statements of a guarantor about its obligations under certain guarantees that it has issued. It also clarifies that at the inception of a guarantee a guarantor is required to recognize a liability for the fair value of the obligation undertaken in issuing a guarantee. The only significant guarantee for which disclosure is required is that of the synthetic lease for the Mesquite Power Plant, which is also affected by FASB Interpretation No. 46, as described below. FASB Interpretation No. 46 (FIN 46), "Consolidation of Variable Interest Entities": In January 2003, the FASB issued FIN 46, which requires the primary beneficiary of a variable interest entity's activities to consolidate the entity. The primary beneficiary is the party that absorbs a majority of the expected losses and/or receives a majority of the expected residual returns of the entity's activities. The consolidation requirements of the interpretation apply immediately to entities created after January 31, 2003. For pre-existing entities, they apply beginning July 1, 2003. Sempra Energy has identified two variable interest entities for which it is the primary beneficiary. One of the variable interest entities relates to an investment in an unconsolidated subsidiary, Atlantic Electric & Gas Limited, that markets power and natural gas commodities to commercial and residential customers in the United Kingdom. The other entity is the lessor of the Mesquite Power Plant (Mesquite Power) described below. Accordingly, effective in the third quarter of 2003, Sempra Energy will consolidate these entities, which is estimated to increase total assets and total liabilities by $650 million. The company does not expect a significant impact to income before the cumulative effect of the change in accounting principle and estimates that the cumulative effect of the change will be a charge of $30 million. Mesquite Power, located near Phoenix, Arizona, is a $662 million, 1,250-megawatt (mW) project that will provide electricity to wholesale energy markets in the Southwest. Construction began in September 2001 and the first phase of commercial operations (50-percent of the plant's total capacity) began in June 2003. The second phase of commercial operations (the remaining 50 percent) is expected to begin in November 2003. Expenditures as of June 30, 2003 are $612 million. A synthetic lease agreement provides financing for all project assets owned by the lessor. Financing under the synthetic lease in excess of $280 million requires 103 percent collateralization through the purchase of U.S. Treasury obligations in similar amounts. As of June 30, 2003, the company held $315 million of U.S. Treasury obligations, which is included in investments on the Consolidated Balance Sheets. 3. MATERIAL CONTINGENCIES ELECTRIC INDUSTRY REGULATION The restructuring of California's electric utility industry has significantly affected the company's electric utility operations. The background of this issue is described in the Annual Report. Subsequent developments are described herein. The power crisis of 2000-2001 has caused the California Public Utilities Commission (CPUC) to adjust its plan for restructuring the electricity industry. In addition, several California state agencies, including the CPUC, the Consumer Power and Conservation Financing Authority, and the California Energy Commission, recently adopted an Energy Action Plan for California. The plan calls for a continuation of regulated electricity rates and existing direct access contracts, increased conservation, more renewable energy, and a stable regulatory environment that encourages private investment in the state. Subsequent to the electric capacity shortages of 2000-2001, SDG&E's service territory has had and continues to have an adequate supply of electricity. However, various projections of electricity demand in SDG&E's service territory indicate that, without additional electrical generation or reductions in electrical usage, beginning in 2005 electricity demand could begin to outstrip available resources. SDG&E's strategy for meeting this demand is to: (1) reduce power demand through conservation and efficiency; (2) increase the supply of electricity from renewable sources, including wind and solar; (3) establish new transmission lines by 2008 to import more power; and (4) provide new electric generation by 2005 to meet the expected shortfall. SDG&E has issued a request for proposals (RFP) to meet the electric capacity shortfall, estimated at 69 megawatts in 2005 and increasing annually by 100 megawatts. SDG&E is ahead of the interim schedule required by California legislation in meeting the CPUC's requirement of obtaining 20 percent of its electricity from renewable sources by 2017. There continues to be legislative and regulatory interest in returning the California's investor-owned utilities (IOUs) to an ownership role for generation. At present, there is no firm guidance or set of terms and conditions under which this might take place that would provide adequate customer and shareholder protections, and SDG&E continues to state that these items must be in place before it would consider an ownership position. In anticipation of possible direction on these matters, SDG&E has required bidders to include both power purchase and ownership options in their response to the RFP noted above for additional local generation beginning in 2005. Several legislative proposals relating to utility regulation have failed to be enacted by the California Legislature. California Senate Bill (SB) 429 would have subjected the company and other California energy-utility holding companies to continuing authority of the CPUC to enforce any condition placed upon their authorizations to acquire their California utility subsidiaries, including obligations to give first priority to the capital requirements of the utilities as determined by the CPUC to be necessary to meet the utilities' obligations to serve. It would also require that the CPUC order the holding companies to infuse into the utility subsidiaries sufficient capital, of any type deemed necessary by the CPUC, to enable the utilities to fulfill their service obligations. SB 888 would repeal the provisions of Assembly Bill (AB) 1890, which enabled electric industry restructuring in September 1996. California Governor Davis recently announced that he is seeking a $1- billion electric rate reduction. SDG&E's portion of this is 13.51 percent or $135 million. This rate reduction will have no effect on SDG&E's net income and net cash flows because customer savings are coming from lower charges by the California Department of Water Resources (DWR), and SDG&E is merely transmitting the electricity from the DWR to the customers, acting as a conduit for the parties. In accordance therewith, on July 1, 2003 the DWR submitted to the CPUC a supplemental determination of its 2003 revenue requirement. The DWR's supplemental determination contains a $1-billion reduction in its revenue requirement for 2003. In order to make the corresponding rate reduction available to ratepayers as soon as possible, and consistent with the very limited scope of this phase of this proceeding, the procedural schedule is being expedited. A draft decision is expected by the end of August 2003, with a final decision by September 2003. The CPUC has undertaken a proceeding and issued numerous decisions establishing the framework, rules and processes that would govern SDG&E's renewed responsibility of procuring electricity for its customers. These include decisions (1) allocating to the customers of California's IOUs the power from the long-term contracts entered into by the DWR, with the DWR retaining the legal and financial responsibility for the contracts; (2) adopting an Operating Agreement between SDG&E and the DWR to govern the terms and conditions for SDG&E's administration of DWR contracts; (3) adopting annual procurement plans that include securing supplies to satisfy SDG&E's additional power requirements; (4) consideration of a 20-year resource plan to assess SDG&E's resource needs, emphasizing the next five years; and (5) developing the criteria by which the acceptability and recovery of procurement transactions will be determined, including possible development of an incentive mechanism for procurement activities. The DWR's Operating Agreement with SDG&E, approved by the CPUC, governs SDG&E's relationship with the DWR now that SDG&E has assumed administration of the allocated DWR contracts. The agreement 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 its customers. Legal and financial risks associated with these activities will continue to reside with the DWR. However, in certain limited circumstances involving transactions in which SDG&E, as DWR's limited agent, is selling DWR surplus energy pursuant to the terms of the Operating Agreement, SDG&E may be obligated to provide lines of credit in connection with the allocated contracts. The risk associated with these lines of credit is considered to be minimal. On April 17, 2003, SDG&E filed with the CPUC its natural gas procurement plan related to certain DWR contracts. On July 10, 2003, the CPUC approved SDG&E's natural gas supply plan. On July 11, 2003, the CPUC adopted a proposed decision continuing the level of the Direct Access (DA) cost responsibility surcharge (CRS) cap effective July 1, 2003 at 2.7 cents per kWh, subject to possible revision in the next DA CRS cap review proceeding. In each periodic DA CRS cap review proceeding, the cap is subject to adjustment to the extent necessary to maintain the goal of refunding to utility customers the full amounts to which they are entitled by the end of the DWR contract term in 2011. NATURAL GAS INDUSTRY RESTRUCTURING As discussed in Note 14 of the notes to Consolidated Financial Statements in the Annual Report, in December 2001 the CPUC issued a decision related to natural gas industry restructuring, with implementation anticipated during 2002. During 2002 the California Utilities filed a proposed implementation schedule and revised tariffs and rules required for implementation. However, on February 27, 2003, the CPUC issued a resolution rejecting without prejudice those proposed tariffs and rules. The resolution ordered SoCalGas to file a new application, which would address detailed proposals for implementation of the December 2001 decision, but also would allow reconsideration of the December 2001 decision. SoCalGas filed such an application on June 30, 2003, and proposed some modifications to the provisions of the December 2001 decision to respond to concerns that it could lead to higher natural gas costs for consumers. These modifications include, among other things, a proposal not to unbundle natural gas transmission, a higher market price cap on receipt-point capacity transactions in the secondary market, deferral of retail unbundling provisions, and a proposal to litigate transmission and storage revenue requirements in the Cost of Service case (see below). Modifications would also remove SoCalGas' exposure to risk or reward for the sale of receipt-point capacity. The filing proposes implementation of these provisions on April 1, 2004 and continuing through August 31, 2006. If the December 2001 decision is implemented, it is not expected to adversely affect the California Utilities' earnings. A CPUC decision is expected during 2004. 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 (CA-AZ) border during the period of March 2000 through May 2001. If the investigation determines that the conduct of any respondent contributed to the natural gas price spikes at the CA-AZ border during this period, the CPUC may modify the respondent's applicable natural gas procurement incentive mechanism, reduce the amount of any shareholder award for the period involved, and/or order the respondent to issue a refund to ratepayers to offset the higher rates paid. The California Utilities, included among the respondents to the investigation, are fully cooperating in the investigation and believe that the CPUC will ultimately determine that they were not responsible for the high border prices during this period. On August 1, 2003, the Administrative Law Judge (ALJ) issued a revised schedule with hearings scheduled to begin in March 2004 and with a Commission decision by late 2004. CPUC INVESTIGATION OF COMPLIANCE WITH AFFILIATE RULES On February 27, 2003, the CPUC opened an investigation of the business activities of SDG&E, SoCalGas and Sempra Energy to ensure that they have complied with relevant statutes and CPUC decisions in the management, oversight and operations of their companies. The Assigned Commissioner and ALJ issued a ruling which suspends the procedural schedule until the CPUC completes an independent audit to evaluate energy-related business activities undertaken by Sempra Energy within the service territories of SDG&E and SoCalGas, relative to holding company systems and affiliate activities. The audit is to consider whether these activities pose any problems for ratepayers and whether they are consistent with the CPUC's decision, rules or orders and/or affiliate statutes. The objective of the audit is to analyze the adequacy of the Affiliate Rules. 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. COST OF SERVICE FILING On May 22, 2003, the assigned CPUC Commissioner modified his previously adopted procedural schedule on the California Utilities' Cost of Service applications to expedite a decision by approximately one month, permitting a decision by as early as March 2004. The assigned Commissioner also provided for additional comments to be filed on the California Utilities' request for interim relief for the period from January 1, 2004 to the date of the Cost of Service decision and stated that a decision on the request would be prepared for consideration of the full Commission. On June 3, 2003, various parties filed reply comments supporting or opposing the motion for January 1, 2004 interim relief. The CPUC's Office of Ratepayer Advocates' (ORA) report on the California Utilities' filing is due on August 8, 2003. An October 10, 2001 decision denied the California Utilities' request to continue equal sharing between ratepayers and shareholders of the estimated savings for the 1998 Enova-PE business combination that created Sempra Energy and, instead, ordered that all of the estimated 2003 merger savings go to ratepayers. This decision will adversely affect 2003 net income by $24 million at SoCalGas and $11 million at SDG&E. MARKET INDEXED CAPITAL ADJUSTMENT MECHANISM (MICAM) Under MICAM, automatic adjustments are made to SDG&E's cost of capital based on when the April-September average of single-A utility bond rates in any given calendar year varies more than 100 basis points from a predetermined benchmark. When this occurs, SDG&E's return on common equity (ROE) is adjusted by one-half of the change. SDG&E must file its annual MICAM advice letter with the CPUC on October 15, reporting how the year's April-September average of the utility bond yield compares to the benchmark. Any resulting change in SDG&E's ROE would go into effect January 1 of the following year. Due to a large general decline in interest rates, it is likely that the existing MICAM mechanism would trigger during 2003. However, if the CPUC approves an all-party settlement previously filed, the likelihood of a trigger this year would be less since the benchmark rate under the settlement was changed to the double-A utility bond rate during a different time period which produced a lower benchmark rate. The current MICAM benchmark, based on the April-September 1996 single-A utility bond yield, stands at 7.97%. The MICAM benchmark that would take effect under the settlement agreement, 7.24%, is based on the April-September 2002 double-A utility bond yield. Single-A utility interest rates under the existing mechanism averaged 6.40% from April through June, and an ROE adjustment would occur if the July through September rate averages 7.53% or lower. Double-A utility interest rates under the settlement agreement averaged 6.26% from April through June, and an ROE reduction would occur if the July through September rate averages 6.20% or lower. In both versions of MICAM, every percentage point of variance between the April-September average and the benchmark in excess of the threshold reduces SDG&E's authorized annual net income by $5 million. PERFORMANCE-BASED REGULATION (PBR) On July 15, 2003, the CPUC issued a Draft Resolution (DR) approving SDG&E's 2001 and 2002 Distribution PBR Performance Reports. If the DR is approved by the CPUC, SDG&E would be awarded $12.2 million for exceeding PBR benchmarks on all six of its performance indicators in 2001. SDG&E would also be awarded $6.0 million for exceeding the PBR benchmarks on five of its six performance indicators in 2002. The total maximum reward (or penalty) SDG&E could earn in a given year under the Distribution PBR mechanism is $14.5 million. A final CPUC decision is expected during the third quarter of 2003. On March 19, 2003, the ORA issued its Monitoring and Evaluation Report on SDG&E's natural gas procurement activities in Year 9 (August 1, 2001 through July 31, 2002). The ORA analyzed and confirmed the PBR results put forth by SDG&E, resulting in a Year 9 shared loss of $1.9 million and a shareholder penalty of $1.4 million, both of which were recorded in 2002. The ORA recommended the extension of the PBR mechanism, as modified in Years 8 and 9, to Year 10 and beyond. The ORA has stated that the CPUC's adoption of the natural gas procurement PBR mechanism is beneficial both to ratepayers and to shareholders of SDG&E. On July 10, 2003, the CPUC issued a decision relative to SDG&E's Year 11 Gas PBR application, which would extend the PBR mechanism with some modification. The decision approved the Joint Parties' Motion for an Order Adopting Settlement Agreement filed by SDG&E and the ORA, which will apply to Year 10 and beyond. The effect of the modifications is to reduce slightly the potential size of future PBR rewards or penalties. SDG&E's request for a reward of $6.7 million for the PBR natural gas procurement period ended July 31, 2001 (Year 8) was approved by the CPUC on January 30, 2003. Since part of the reward calculation is based on CA-AZ natural gas border price indices, the decision reserved the right to revise the reward in the future, depending on the outcome of the CPUC's border price investigation (see above) and the FERC's investigation into alleged energy price manipulation (see below). GAS COST INCENTIVE MECHANISM (GCIM) SoCalGas' GCIM allows SoCalGas to receive a share of the savings it achieves by buying natural gas for customers below monthly benchmarks. The mechanism permits full recovery of all costs within a tolerance band above the benchmark price and refunds savings within a tolerance band below the benchmark price. The costs outside the tolerance band are shared between customers and shareholders. On June 25, 2003, the assigned CPUC commissioner issued two separate, but essentially identical, Draft Decisions in SoCalGas' GCIM Year 7 and Year 8 proceedings. A final CPUC decision is expected during the third quarter of 2003. If the final decision agrees with the assigned commissioner's Draft Decisions approving the shareholder rewards of $30.8 million for Year 7 and $17.4 million for Year 8 (subject to refund or adjustment as determined by the Commission in the Border Price Investigation described above), the rewards would be included in income in the third quarter of 2003. On June 16, 2003, SoCalGas filed an application with the CPUC requesting a $6.3 million shareholder reward for GCIM Year 9 (April 1, 2002 through March 31, 2003). The company's natural gas purchasing activities resulted in a net savings of $33 million to ratepayers during Year 9, which led to the requested shareholder reward. Performance incentives rewards are not included in the company's earnings until CPUC approval is received. TRANSMISSION RATE INCREASE On May 2, 2003, the FERC accepted SDG&E's request for modification of its Transmission Owner Tariff to adopt a rate increase. The new transmission rates are effective October 1, 2003, and will increase the charges for retail transmission service by $32.3 million (27 percent). SDG&E has proposed formula-based rates which would allow the company over a 4 to 5 year period to recover all of its recorded costs as well as an adopted ROE. Thus, SDG&E would earn no more or no less than the FERC-adopted ROE for the predetermined period. These new rates are subject to refund based on the FERC's final order. The FERC staff and intervenor testimonies are due on August 29, 2003. Litigation of the case would result in a decision by the end of 2004. In August 2002 the FERC issued Opinion No. 458, which effectively disallowed SDG&E's recovery of the differentials between certain costs paid to SDG&E under existing transmission contracts (the "Participation Agreements") and charges assessed to SDG&E under the ISO FERC tariff. These charges are for transmission line losses and grid management charges attributable to energy schedules on portions of the Southwest Powerlink. As a result, SDG&E is incurring unreimbursed cost differentials on an ongoing basis at a rate ranging between $4 million and $8 million per year. SDG&E has petitioned the United States Court of Appeals for review of these FERC orders. In addition, SDG&E is challenging the propriety of the ISO charges as applied to the portions of the Southwest Powerlink jointly owned with Arizona Public Service Co. and the Imperial Irrigation District in proceedings before the FERC, and in an arbitration under the ISO tariff, the result of which may be appealed to FERC. To the extent SDG&E prevails in these matters, the FERC may require the ISO to refund to SDG&E all or part of the subject charges. 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. FERC ACTIONS The FERC is investigating prices charged to buyers in the California Power Exchange (PX) and Independent System Operator (ISO) markets by various electric suppliers. It 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 California owes power suppliers $1.2 billion (the $3.0 billion that California still owes energy companies less $1.8 billion energy companies charged California customers in excess of the FERC cap). 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 totals to more than $3.0 billion. The precise number will not be available until the ISO and PX recalculate the number through their settlement models based on the final FERC instructions. California is seeking $8.9 billion in refunds and has appealed the FERC's preliminary findings and requested rehearing of the March 26 order. 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 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. In addition to the refund proceeding described above, the FERC is also investigating whether there was manipulation of short-term energy prices in the West that would constitute violations of applicable tariffs and warrant disgorgement of associated profits. In this proceeding, the FERC has authority to look at time periods outside of 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 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, the 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 tariff. 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 through partnerships, alliances or other arrangements 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 SET has already had such discussions. SET estimates that the total amount of revenues attributable to the transactions involved in these inquiries is less than $10 million. The ISO has calculated SDG&E's gains attributable to these issues at less than $200,000. In addition, the FERC determined that it was appropriate to initiate an investigation into possible economic withholding in the California ISO and PX markets. For this purpose, the FERC used an initial screen of $250 per mW for all bids between May 1, 2000 and October 2, 2000. Both SDG&E and SET received data requests from the FERC staff. The FERC staff will prepare a report to the Commission, 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 June 25, 2003, the FERC issued orders upholding the company's long- term energy 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 Commission noted that Commission 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 Commission pointed out that the contracts were entered into voluntarily in a market-based environment. The Commission 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. A number of parties have applied to the FERC for a rehearing of the decision and may ultimately appeal the decision to the federal courts. NUCLEAR INSURANCE SDG&E and the other co-owners of SONGS have insurance to respond to any 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 $9.25 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 $176 million under the Price-Anderson Act. SDG&E's share would be $36 million unless default occurs by any other SONGS co-owner. In the event the secondary financial protection limit is 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 co-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 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. Coverage is also provided for the cost of replacement power, which includes indemnity payments for up to three years, after a waiting period of 12 weeks. 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 $7.4 million. Both the nuclear liability and property insurance programs include industry aggregate limits for terrorism-related SONGS losses, including replacement power costs. ARGENTINE INVESTMENTS During the second quarter of 2003, SEI recorded a $9 million credit to "accumulated other comprehensive income" to reflect the increase in the value of the Argentine peso relative to the U.S. dollar, resulting in total credits of $33 million for the six months ended June 30, 2003. As of June 30, 2003, SEI has adjusted its investment in its two unconsolidated Argentine subsidiaries downward by $190 million as a result of the devaluation of the Argentine peso since early 2002. On September 6, 2002, SEI initiated proceedings under the 1994 Bilateral Investment Treaty between the United States and Argentina for recovery of the diminution of the value of its investments resulting from Argentine governmental actions. SEI made a request for arbitration to the International Centre for Settlement of Investment Disputes (ICSID) and all arbitrators have been selected. The company's claim is due in August 2003 and a decision is expected in late 2004. LITIGATION Lawsuits filed in 2000 and currently consolidated in San Diego Superior Court seek class-action certification and 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 announced that they had reached a settlement in principle of the class actions, certain of the individual actions, claims asserted by the California Attorney General and by other western states, and certain complaint proceedings filed with FERC by the CPUC and the California Energy Oversight Board. On June 26, 2003, the settlement was filed for approval with the relevant state courts and the FERC. The settlement provides more than $1.5 billion in consideration to be received by customers, with no effect on the income of the utilities processing the refunds. Of these funds, the settlement provides the following allocation for each SDG&E and SoCalGas customer group: SDG&E Electric Customers -- $60 million, SDG&E Core Gas -- $29 million and SoCalGas Core Gas -- $36 million. Non-core natural gas customers will go through a claims process in the courts, by which they can establish their harm and receive a fair share of the consideration. A similar lawsuit has been filed by the Attorney General of Arizona alleging that El Paso and certain Sempra Energy subsidiaries unlawfully sought to control the natural gas market in Arizona. In April 2003, Sierra Pacific and its utility subsidiary Nevada Power jointly 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, and breach of contract and wire fraud. Various lawsuits, which seek class-action certification, allege that Sempra Energy and certain company 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 Appeal and a decision is expected by first quarter of 2004. Similar suits filed in Washington and Oregon were voluntarily dropped by the plaintiffs without court intervention in June 2003. In addition, in May 2003, the Port of Seattle filed an action alleging that a number of energy companies, including Sempra Energy and SET, unlawfully manipulated the electric energy market and committed wire fraud. That action is pending a motion to dismiss in Washington Federal District Court 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. 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. However, the Court has provided plaintiffs with an opportunity to amend their claims. In May 2003, a similar action was filed in San Diego Superior Court against Sempra Energy and SET, and has been removed to Federal District Court. In May 2003, the San Diego Superior Court granted SER's motion for summary judgment in its complaint for declaratory judgment regarding its contract with the DWR (and the DWR's cross-complaint seeking to void the 10-year energy-supply contract). In the judgment, the court determined that "(a) Sempra is entitled to provide electrical energy from any source, including Market Sources, (b) Sempra is not in breach of the Agreement as framed by the pleadings in this matter, (c) DWR is obligated to take delivery and pay for deliveries under the Agreement, and (d) Sempra has no obligation to complete any specific Project." Once the court enters the judgment, which it has not yet done, the DWR has 60 days to file a notice of appeal. If the state appeals the judgment, SER will respond according to the briefing schedule established by the appellate court. 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 made all payments that have been billed under the contract. SER is a defendant in an action brought by Occidental Energy Ventures Corporation (Occidental) with respect to the Elk Hills power project being jointly developed by the two companies. Occidental alleges that SER breached the joint development agreement by not providing that Occidental would be a party to the contract with the DWR or receiving its share of the proceeds from providing the DWR with power from Elk Hills under the contract. The matter remains scheduled for arbitration in the third quarter of 2003. In May 2003 a Federal judge issued an order finding that the U.S. Department of Energy's (DOE) abbreviated assessment of two Mexicali power plants, including SER's TDM plant, failed to evaluate the plants' environmental impact adequately and calls into question the U.S. permits they received to build their cross-border transmission lines. On July 8, 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 Global each acquired a 44-percent interest in Luz Del Sur, an electric distribution company based in Peru. Local law required that electricity assets built with government funds be purchased by the local utility and added to rate base. The government financed 194 projects that were subsequently transferred to Luz Del Sur. A dispute arose between the government and Luz Del Sur over the amount of compensation due for the projects received by Luz Del Sur. According to the government, the total amount owed relating to these projects was approximately $36 million. Luz Del Sur argued that the amount was less and the matter was settled with the government for approximately $10 million. On May 12, 2003, following a change in the government in Peru, 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 did not provide the government with adequate compensation. Luz Del Sur is currently investigating this matter. Except for the matters referred to above, 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 a material adverse effect on the company's financial condition or results of operations. INCOME TAX ISSUES Section 29 Income Tax Credits The Internal Revenue Service (IRS) has recently 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. As part of its recently commenced normal audit program for the company for the period 1998-2001, the IRS has notified the company of its intention to audit the synthetic fuel operations of Sempra Energy Trading and Sempra Energy Financial. Through June 30, 2003, the company has recorded Section 29 income tax credits of $194 million, including $28 million and $52 million during the three months and six months ended June 30, 2003. For the second half of 2003, the company's 2003 forecast has included additional contributions to net income of $22 million from Section 29 income tax credits, net of operating costs of the related facilities. The company believes retroactive disallowance of Section 29 income tax credits is unlikely. Luz del Sur Peruvian income-tax authorities have challenged the valuation of Luz del Sur's assets for tax depreciation purposes. If the Peruvian government is successful in its challenge, income-tax deductions for depreciation will be reduced, resulting in additional income taxes, interest and penalties aggregating as much as $16 million for the company's share for the period being questioned (1996 through 1999) and $12 million for subsequent periods. The company believes that it has substantial defenses to the imposition of any additional taxes. Spanish Holding Company The IRS has issued Notice 2003-50, stating that regulations will be issued that will adversely affect foreign tax credit utilization by companies with "stapled-stock" affiliates. The company's intermediate parent company for many of its non-domestic subsidiaries is such a company. The most adverse resolution of this issue could result in a charge to net income of $13 million by the company. The company is unable to predict the net effect of the ultimate resolution of these income tax issues. Pending Internal Revenue Service Matters The company is in discussions with the IRS to resolve issues related to various prior years' returns. A recently issued Revenue Ruling dealing with utility balancing accounts, and recent discussions with the IRS concerning this Ruling and another matter lead the company to believe it will be entitled to record a reduction in previously recorded income tax expense, accrue significant interest income on overpayments of tax in certain prior periods and reverse recorded interest associated with the reporting of these items in other prior periods. The company expects that these matters will be favorably resolved before year end and estimates that the resolution will increase reported 2003 earnings in excess of $75 million. QUASI-REORGANIZATION In 1993, PE divested its merchandising operations and most of its oil and natural gas exploration and production business. In connection with the divestitures, PE effected a quasi-reorganization for financial reporting purposes effective December 31, 1992. Management believes the remaining balances of the liabilities established in connection with the quasi-reorganization are adequate. 4. SEGMENT INFORMATION The company is a holding company, whose subsidiaries are primarily engaged in the energy business. It has four separately managed reportable segments comprised of SoCalGas, SDG&E, SET and SER. The California Utilities operate in essentially separate service territories under separate regulatory frameworks and rate structures set by the CPUC. SoCalGas is a natural gas distribution utility, serving customers throughout most of southern California and part of central California. SDG&E provides electric service to San Diego and southern Orange counties, and natural gas service to San Diego county. SET, based in Stamford, Connecticut, is a wholesale trader of physical and financial energy products and other commodities, and a trader and wholesaler of metals, serving a broad range of customers in the United States, Canada, Europe and Asia. SER develops, owns and operates power plants and natural gas storage, production and transportation facilities within the western and southwestern United States and Baja California, Mexico. The accounting policies of the segments are described in the notes to Consolidated Financial Statements in the company's 2002 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. Other than SER's completing the construction of combined-cycle power plants, there were no significant changes in segment assets during the six months ended June 30, 2003. ----------------------------------------------------------------------- Three months ended Six months ended June 30, June 30, ------------------- ------------------ (Dollars in millions) 2003 2002 2003 2002 ----------------------------------------------------------------------- Operating Revenues: Southern California Gas $ 820 $ 670 $ 1,828 $ 1,402 San Diego Gas & Electric 520 414 1,082 846 Sempra Energy Trading 305 192 528 398 Sempra Energy Resources 129 116 219 139 All other 82 103 132 188 Intersegment revenues (16) (7) (26) (10) ------------------------------------------ Total $ 1,840 $ 1,488 $ 3,763 $ 2,963 ----------------------------------------------------------------------- Net Income (Loss): Southern California Gas* $ 37 $ 51 $ 95 $ 111 San Diego Gas & Electric* 41 51 86 104 Sempra Energy Trading 35 21 17 63 Sempra Energy Resources 5 34 15 31 All other (2) (10) (9) (16) ------------------- ---------------------- Total $ 116 $ 147 $ 204 $ 293 ----------------------------------------------------------------------- * after preferred dividends -------------------------------------------------------- Balance at ------------------------ June 30, December 31, 2003 2002 -------------------------------------------------------- Assets: Southern California Gas $ 3,967 $ 4,079 San Diego Gas & Electric 5,464 5,123 Sempra Energy Trading 5,441 5,614 Sempra Energy Resources 1,576 1,347 All other 2,786 2,580 Intersegment receivables (1,011) (986) ------------------------ Total $ 18,223 $ 17,757 -------------------------------------------------------- 5. FINANCIAL INSTRUMENTS Note 10 of the notes to Consolidated Financial Statements in the Annual Report discusses the company's financial instruments, including the adoption of SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities." The effect is to recognize all derivatives as assets or liabilities on the balance sheet, measure those instruments at fair value, and recognize any changes in fair value in earnings for the period that the change occurs unless the derivative qualifies as an effective hedge that offsets other exposures. The company utilizes derivative financial instruments to manage its exposure to unfavorable changes in commodity prices, which are subject to significant and often volatile fluctuations. Derivative financial 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 or paid by the company and, in the case of the California Utilities, their customers. In accordance with SFAS 133, the California Utilities have elected to account for contracts that are settled by physical delivery at historical cost, with gains and losses reflected in the income statement at the contract settlement date. SET's and SES's derivative instruments are recorded at fair value pursuant to SFAS 133 and are included in the Consolidated Balance Sheets as trading assets or liabilities. Net gains and losses on these derivative transactions are recorded in "Other operating revenues" in the Statements of Consolidated Income. In October 2002, the EITF reached a consensus to rescind Issue 98-10 "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," which was the basis for fair value accounting used for recording energy-trading activities by SET and SES. The consensus requires that all new energy- related contracts entered into subsequent to October 25, 2002 should not be accounted for pursuant to Issue 98-10. Instead, those contracts should be accounted for at historical cost or the lower of cost or market, unless the contracts meet the requirements for fair value accounting under SFAS 133. Energy transportation and storage contracts entered into by the company on or after October 25, 2002 are recorded at cost. Energy commodity inventory is being recorded at the lower of cost or market. The company's base metals and concentrates inventory continue to be recorded at fair value as provided by Accounting Research Bulletin Number 43. On January 1, 2003, as a result of the rescission of EITF 98-10, SET and SES recorded a cumulative effect of a change in accounting principle, which reduced after-tax earnings by $29 million, related to the non-derivative contracts that were recorded at fair value under EITF 98-10 but are not covered by SFAS 133. The ongoing effect of EITF 98-10's rescission further reduced after-tax earnings for the six months ended June 30, 2003 by $16 million, including $7 million for the three months ended June 30, 2003. Neither of these effects impacted cash flow or liquidity. The carrying values of SET's trading assets and trading liabilities approximate the following: June 30, December 31, (Dollars in millions) 2003 2002 ---------------------------------------------------------------------------- TRADING ASSETS: Unrealized gains on swaps and forwards $1,401 $1,226 OTC commodity options purchased 528 480 Due from trading counterparties 1,007 1,279 Due from commodity clearing organizations and clearing brokers 104 49 Resale agreements 44 -- Commodities owned 1,710 1,968 ------ ------ Total trading assets $4,794 $5,002 ====== ====== TRADING LIABILITIES: Unrealized losses on swaps and forwards $1,088 $ 816 OTC commodity options written 463 569 Due to trading counterparties 1,345 1,196 Repurchase obligations 1,240 1,511 ------ ------ Total trading liabilities $4,136 $4,092 ====== ====== Fixed-price contracts and other derivatives on the Consolidated Balance Sheets primarily reflect the California Utilities' derivative gains and losses related to long-term delivery contracts for purchased power and natural gas transportation. The California Utilities have established regulatory assets and liabilities to the extent that these gains and losses are recoverable or payable through future rates. Other significant derivatives recorded on the balance sheet include a fixed- to-floating interest rate swap agreement and a contingent purchase price obligation arising from the company's acquisition of the proposed Hackberry, La. LNG project. Payments under the swap agreement and changes in interest rate (LIBOR) are reflected as adjustments to long- term debt. The contingent payments under the proposed LNG project purchase obligation are included in property, plant and equipment. The changes in fixed-price contracts and other derivatives on the Consolidated Balance Sheets for the six months ended June 30, 2003 were primarily due to the contingent purchase price obligation arising from the company's acquisition of the proposed Hackberry, La. LNG project, partially offset by physical deliveries under long-term purchased-power and natural gas transportation contracts. The transactions associated with fixed-price contracts and other derivatives had no material impact to the Statements of Consolidated Income for the six months ended June 30, 2003 or 2002. ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion should be read in conjunction with the financial statements contained in this Form 10-Q and "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained in the Annual Report. RESULTS OF OPERATIONS California Utility Revenues and Cost of Sales Natural gas revenues increased to $2.1 billion for the six months ended June 30, 2003 from $1.6 billion for the corresponding period in 2002, and the cost of natural gas increased to $1.2 billion in 2003 from $729 million in 2002. Additionally, natural gas revenues increased to $929 million for the three months ended June 30, 2003 from $754 million for the corresponding period in 2002, and the cost of natural gas increased to $480 million in 2003 from $305 million in 2002. These changes were primarily attributable to natural gas price increases, which are passed on to customers, partially offset by reduced volumes. Under the current regulatory framework, changes in core-market natural gas prices for core customers (primarily residential and small commercial and industrial customers) do not affect net income, since core-customer rates generally recover the actual cost of natural gas on a substantially concurrent basis and are fully balanced. However, SoCalGas' 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 gas procurement 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 increased to $792 million for the six months ended June 30, 2003 from $604 million for the same period in 2002, and the cost of electric fuel and purchased power increased to $300 million in 2003 from $140 million in 2002. Additionally, electric revenues increased to $397 million for the three months ended June 30, 2003 from $323 million for the same period in 2002, and the cost of electric fuel and purchased power increased to $137 million in 2003 from $79 million in 2002. These changes were mainly due to the effect of the DWR's purchasing the net short position of SDG&E during 2002, changes in electric commodity costs, the increase in authorized distribution revenue and higher volumes in 2003. Under the current regulatory framework, changes in commodity costs do not affect net income. The commodity costs associated with the DWR's purchases and the corresponding sale to SDG&E's customers were not included in the Statements of Consolidated Income as SDG&E was merely transmitting the electricity from the DWR to the customers, acting as a conduit to pass through the electricity from the DWR to the customers. During 2003, costs associated with long-term contracts allocated to SDG&E from the DWR were likewise 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 six months ended June 30, 2003 and 2002. Gas Sales, Transportation and Exchange (Volumes in billion cubic feet, dollars in millions)
Gas Sales Transportation & Exchange Total --------------------------------------------------------------- Volumes Revenue Volumes Revenue Volumes Revenue ---------------------------------------------------------------- 2003: Residential 148 $ 1,361 1 $ 4 149 $ 1,365 Commercial and industrial 66 475 140 89 206 564 Electric generation plants -- 1 95 30 95 31 Wholesale -- -- 11 1 11 1 --------------------------------------------------------------- 214 $ 1,837 247 $ 124 461 1,961 Balancing accounts and other 130 -------- Total $ 2,091 ------------------------------------------------------------------------------------------- 2002: Residential 165 $ 1,123 1 $ 4 166 $ 1,127 Commercial and industrial 63 324 145 81 208 405 Electric generation plants -- -- 104 24 104 24 Wholesale -- -- 21 2 21 2 --------------------------------------------------------------- 228 $ 1,447 271 $ 111 499 1,558 Balancing accounts and other 76 -------- Total $ 1,634 -------------------------------------------------------------------------
Electric Distribution and Transmission (Volumes in millions of kilowatt hours, dollars in millions)
2003 2002 ----------------------------------------- Volumes Revenue Volumes Revenue ----------------------------------------- Residential 3,161 $ 366 3,072 $ 323 Commercial 2,922 333 2,853 294 Industrial 902 80 897 75 Direct access 1,565 37 1,693 54 Street and highway lighting 45 5 43 4 Off-system sales 33 1 -- -- ----------------------------------------- 8,628 822 8,558 750 Balancing accounts and other (30) (146) ----------------------------------------- Total 8,628 $ 792 8,558 $ 604 -----------------------------------------
Although commodity-related revenues from the DWR's purchasing of SDG&E's net short position or from the DWR's allocated contracts are not included in revenue, the associated volumes and distribution revenue are included herein. Other Operating Revenues Other operating revenues, which consist primarily of revenues at Global, increased to $880 million for the six months ended June 30, 2003 from $725 million for the same period of 2002. These changes were primarily due to higher revenue at SET due to increased volumes and increased coal sales related to Section 29 income tax credits, and increased revenues from SER, which resulted mainly from higher sales of electricity to the DWR under the contract which recommenced in April 2002, and sales by its Twin Oaks power plant, purchased in the fourth quarter of 2002. Other operating revenues increased to $514 million for the three-month period ended June 30, 2003 from $411 million for the corresponding period of 2002 due primarily to the increased revenue at SET resulting from increased volumes and volatility in the energy commodity markets and the increased coal sales. Other Cost of Sales Other cost of sales, which consists primarily of cost of sales at Global, increased to $515 million for the six months ended June 30, 2003 from $338 million for the six months ended June 30, 2002, and increased to $296 million for the three months ended June 30, 2003, from $206 million for the same period in 2002. The increase for the six-month period was primarily due to the increased sales as noted above for SER, and the increased activity at SET. The increase for the quarter was primarily due to the increased activity at SET. Other Operating Expenses Other operating expenses increased to $963 million for the six months ended June 30, 2003 from $890 million for the same period in 2002. Of the total balance, $682 million and $641 million in 2003 and 2002, respectively, represent other operating expenses at the California Utilities. The increase was due primarily to general operating cost increases at SoCalGas and SER. Other operating expenses increased to $518 million for the three months ended June 30, 2003 from $475 million for the corresponding period of 2002. Of the total balance, $364 million and $360 million in 2003 and 2002, respectively, represent other operating expenses at the California Utilities. The increase was primarily due to increased operating costs at SET, SER and SoCalGas. Other Income - Net Other income, which primarily consists of equity earnings from unconsolidated subsidiaries and interest on regulatory balancing accounts, decreased to $4 million for the six months ended June 30, 2003 from $27 million for the six months ended June 30, 2002. The decrease was primarily due to SEI's foreign exchange losses, compared to its foreign exchange gains in the prior-year period and increased equity losses at SER and other subsidiaries, offset partially by increased equity earnings from SEI's Argentine subsidiaries. Income Taxes Income tax expense decreased to $51 million for the six months ended June 30, 2003 from $74 million for the same period of 2002. The effective income tax rates were 18.0 percent and 20.3 percent for the six-month periods ended June 30, 2003 and 2002, respectively. The change was primarily due to reduced pretax income and increased income tax credits from synthetic fuel investments in 2003 (see discussion of Section 29 credits in Note 3), offset partially by a $25 million favorable resolution of income-tax issues at SDG&E in the second quarter of 2002. In connection with its affordable-housing investments, the company has unused tax credits dating back to 1999, which the company fully expects to utilize in future years. At June 30, 2003, the amount of these unused tax credits was $172 million. In addition, at June 30, 2003, the company has $46 million of alternative minimum tax credits with no expiration date. Income tax expense increased to $27 million for the second quarter of 2003 compared to $15 million for the second quarter of 2002, and the effective income tax rate increased to 18.9 percent from 9.4 percent. This change was due to the $25 million favorable resolution of SDG&E's income-tax issues in 2002 discussed above. Net Income For the six months ended June 30, net income decreased to $204 million, or $0.98 per diluted share of common stock, in 2003 from $293 million, or $1.42 per diluted share in 2002. Excluding the effects of the cumulative effect of the change in accounting principle in 2003 ($0.14 per diluted share, discussed in Note 2 of the notes to Consolidated Financial Statements) and the extraordinary item in 2002 ($0.01 per diluted share, discussed in the Annual Report), the change in net income in 2003 was primarily due to the $25 million after-tax benefit in 2002 discussed above, as well as lower income from SET and SoCalGas. Net income for the second quarter was $116 million, or $0.55 per diluted share for 2003, compared to $147 million or $0.71 per diluted share in 2002. The change was primarily due to lower income from SER and SoCalGas and the 2002 tax benefit discussed above, offset partially by increased income from SET. Net Income by Business Unit
Three months ended Six months ended June 30, June 30, (Dollars in millions) 2003 2002 2003 2002 ------------------------------------------------------------------------------- California Utilities Southern California Gas Company* $ 37 $ 51 $ 95 $ 111 San Diego Gas & Electric* 41 51 86 104 ------ ------ ------ ------ Total Utilities 78 102 181 215 Global Enterprises Sempra Energy Trading 35 21 17 63 Sempra Energy Resources 5 34 15 31 Sempra Energy International 18 9 25 17 Sempra Energy Solutions 8 5 7 6 ------ ------ ------ ------ Total Global Enterprises 66 69 64 117 Sempra Energy Financial 8 7 19 14 Parent and other (36) (31) (60) (53) ------ ------ ------ ------ Consolidated $ 116 $ 147 $ 204 $ 293 ====== ====== ====== ====== * after preferred dividends
------------------------------------------------------------------------------- SOUTHERN CALIFORNIA GAS COMPANY SoCalGas recorded net income of $95 million and $111 million for the six-month periods ended June 30, 2003 and 2002, respectively, and net income of $37 million and $51 million for the three-month periods ended June 30, 2003 and 2002, respectively. The change was primarily due to the end of sharing of the merger savings (discussed in the Annual Report) and increased operating expenses associated with legal costs principally related to antitrust litigation, partially offset by increased margins and other factors. SAN DIEGO GAS & ELECTRIC SDG&E recorded net income of $86 million and $104 million for the six- month periods ended June 30, 2003 and 2002, respectively, and net income of $41 million and $51 million for the three-month periods ended June 30, 2003 and 2002, respectively. The decreases were primarily due to income-tax effects, primarily the $25 million after-tax benefit from the favorable resolution of prior years' income-tax issues recorded in the second quarter of 2002, and the end of sharing of the merger savings, partially offset by increased margins and increased output at SONGs. SEMPRA ENERGY TRADING SET recorded net income of $17 million and $63 million for the six- month periods ended June 30, 2003 and 2002, respectively, and net income of $35 million and $21 million for the three-month periods ended June 30, 2003 and 2002, respectively. For purposes of comparison with the corresponding 2002 period, net income for the six months ended June 30, 2003 would have been $61 million if not for the repeal of EITF 98- 10 as described in Note 2 of the notes to Consolidated Financial Statements. The repeal of EITF 98-10 adversely impacted SET's results by a cumulative effect adjustment of $28 million and an additional $16 million related to operations for the six months ended June 30, 2003, including $7 million for the three months ended June 30, 2003. A summary of SET's net unrealized revenues for trading activities for the six-month periods ended June 30, 2003 and 2002 follows: (Dollars in millions) 2003 2002 ----------------------------------------------------------------- Balance at beginning of period $ 180 $ 405 Cumulative effect adjustment (48) -- Additions 599 186 Realized (277) (184) ------------------------------------ Balance at June 30 $ 454 $ 407 ==================================== The estimated fair values for SET's trading activities as of June 30, 2003, and the periods during which net unrealized revenues are expected to be realized, are (dollars in millions):
Fair Market Value at June 30, /--Scheduled Maturity (in months)--/ Source of fair value 2003 0-12 13-24 25-36 >36 ------------------------------------------------------------------------- Prices actively quoted $ 354 $ 407 $ (72) $ 12 $ 7 Prices provided by other external sources (2) (5) (2) -- 5 Prices based on models and other valuation methods 26 7 5 1 13 ------------------------------------------------ Over-the-counter (OTC) revenue (1) 378 409 (69) 13 25 Exchange contracts (2) 76 19 38 13 6 ------------------------------------------------ Total $ 454 $ 428 $ (31) $ 26 $ 31 ================================================ (1) The present value of net unrealized revenue to be received or (paid) from outstanding OTC contracts. (2) Cash (paid) or received associated with open Exchange contracts.
------------------------------------------------------------------------- The following table summarizes the counterparty credit quality for SET. These amounts are net of collateral in the form of customer margin and/or letters of credit. June 30, December 31, (Dollars in millions) 2003 2002 ----------------------------------------------------------------- Counterparty credit quality* Commodity Exchanges $ 104 $ 49 AAA 46 69 AA 340 194 A 384 316 BBB 417 559 Below investment grade 393 504 --------------------------- Total $ 1,684 $ 1,691 =========================== * Except for commodity exchanges, counterparty credit quality is determined by rating agencies or internal models intended to approximate rating-agency determinations. ----------------------------------------------------------------- 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 Restructuring" in Note 13 of the Annual Report. SEMPRA ENERGY RESOURCES SER recorded net income of $15 million and $31 million for the six- month periods ended June 30, 2003 and 2002, respectively, and net income of $5 million and $34 million for the three-month periods ended June 30, 2003 and 2002, respectively. The changes were primarily due to the pricing structure of SER's contract with the DWR, increased interest expense due to borrowings for the new power plants, and start- up expenses related to the new power plants. SEMPRA ENERGY INTERNATIONAL SEI recorded net income of $25 million and $17 million for the six- month periods ended June 30, 2003 and 2002, respectively, and net income of $18 million and $9 million for the three-month periods ended June 30, 2003 and 2002, respectively. The changes were primarily due to increased equity earnings from its Argentine subsidiaries partially offset by the effect of foreign currency losses in 2003. SEMPRA ENERGY SOLUTIONS SES recorded net income of $7 million and $6 million for the six-month periods ended June 30, 2003 and 2002, respectively, and net income of $8 million and $5 million for the three-month periods ended June 30, 2003 and 2002, respectively. SEMPRA ENERGY FINANCIAL SEF invests as a limited partner in affordable-housing properties. SEF's portfolio includes 1,300 properties throughout the United States, including Puerto Rico and the Virgin Islands. These investments are expected to provide income tax benefits (primarily from income tax credits) over 10-year periods. SEF also has an investment in a limited partnership which produces synthetic fuel from coal. See discussion of Section 29 income tax credits in Note 3 of the Notes to Consolidated Financial Statements under "Income Tax Issues." Whether SEF will invest in additional properties will depend on Sempra Energy's income tax position. SEF recorded net income of $19 million and $14 million for the six- month periods ended June 30, 2003 and 2002, respectively, and net income of $8 million and $7 million for the three-month periods ended June 30, 2003 and 2002, respectively. CAPITAL RESOURCES AND LIQUIDITY The company's California Utility operations are the major source of liquidity. Funding of other business units' capital expenditures is largely dependent on the California Utilities' paying sufficient dividends to Sempra Energy, which, in turn, depends on the sufficiency of those earnings in excess of utility needs. For additional discussion, see "Factors Influencing Future Performance- -Electric Industry Restructuring and Electric Rates" herein and Note 3 of the notes to Consolidated Financial Statements. At June 30, 2003, the company had $325 million in cash and $2.3 billion in unused, committed lines of credit available, of which $388 million was supporting commercial paper and variable-rate debt. On July 10, 2003, the CPUC issued a decision authorizing SoCalGas to issue up to $715 million of long-term debt, of which not less than $500 million will be used for the retirement of currently outstanding debt or preferred stock. The decision also grants SoCalGas an exemption from the Competitive Bidding Rule and permits SoCalGas to enter into interest-rate swaps, caps, collars and currency-exchange contracts. Management believes these amounts, 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 significantly reduced and/or the company was 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 adequately meet the needs of its operating, financing and investing activities. 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 significant dividends to Sempra Energy. 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 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 $316 million at June 30, 2003, down from $418 million at December 31, 2002. Company management continuously monitors the level of SET's cash requirements in light of the company's overall liquidity. SER's projects are expected to be financed through a combination of the existing synthetic lease, project financing, SER's borrowings and funds from the company. Its capital expenditures over the next several years may require some additional funding. SEI is expected to require funding for its planned development of liquefied natural gas (LNG) facilities and to continue the expansion of its existing natural gas distribution operations in Mexico. While internal funds are expected to be adequate for these purposes, the company may decide to use project financing if that is more advantageous. SES is expected to require moderate amounts of cash in the near future as its commodity and energy services businesses continue to grow. SEF is expected to continue to be a net provider of cash through reductions of consolidated income tax payments resulting from its investments in affordable housing and synthetic fuel. CASH FLOWS FROM OPERATING ACTIVITIES Net cash provided by operating activities totaled $756 million and $754 million for the six months ended June 30, 2003 and 2002, respectively. Offsetting factors included the higher realization in net trading assets in 2003 and greater compensation costs paid in 2002 versus the increases in overcollected regulatory balancing accounts in 2002 (resulting from higher natural gas usage in 2002 and the reduced rate of recovery of the AB265 undercollection in 2003) and higher income tax payments in 2003. CASH FLOWS FROM INVESTING ACTIVITIES Net cash used in investing activities totaled $639 million and $759 million for the six months ended June 30, 2003 and 2002, respectively. The change in cash flows from investing activities was attributable to a higher level of acquisition activity in 2002, lower capital expenditures for the Termoelectrica de Mexicali (TDM) power plant in 2003, and loans to an unconsolidated subsidiary (Atlantic Electric & Gas Limited) in 2003. Capital expenditures for property, plant and equipment by the California Utilities are estimated to be $750 million for the full year 2003 and are being financed primarily by internally generated funds and security issuances. Construction, investment and financing programs are continuously reviewed and revised in response to changes in competition, customer growth, inflation, customer rates, the cost of capital, and environmental and regulatory requirements. Capital expenditures for property, plant and equipment by the company's other businesses are estimated to be $550 million for the full year 2003, of which $230 million is for SER's power plant construction and other capital projects. In April 2003, Sempra Energy LNG Corp., a newly created subsidiary within the SEI business unit, completed its previously announced acquisition of the proposed Hackberry, La. LNG project from a subsidiary of Dynegy, Inc. Sempra Energy LNG Corp., paid Dynegy $20 million on April 23, 2003, for the first phase of the transaction, which includes rights to the location, licensing and preliminary FERC approval. Additional payments are contingent on meeting certain benchmarks and milestones and the performance of the project, now known as Cameron. The total cost of the project is expected to be approximately $700 million. The project could begin commercial operations in early 2007. Final FERC approval is expected by the end of 2003. In connection with SEI's plans to develop Energia Costa Azul, an LNG receiving terminal in Baja California, about 50 miles south of San Diego, Mexico's national environmental agency issued the principal onshore environmental permit to SEI in April 2003. The secondary offshore environmental permit is pending and is expected by October 2003. Two other significant permits, an operating permit from Mexico's Energy Regulatory Commission and a local land-use permit from the City of Ensenada, are pending and expected to be received in the near future. Energia Costa Azul will bring natural gas into northwestern Mexico and southern California. The project is currently estimated to cost $600 million and to commence commercial operations in early 2007. CASH FLOWS FROM FINANCING ACTIVITIES Net cash used in financing activities totaled $247 million and $78 million for the six months ended June 30, 2003 and 2002, respectively. The change in cash flows from financing activities was attributable to reduced long-term borrowings in 2003 partly offset by reduced repayments of short-term debt in 2003. In January 2003, the company issued $400 million of 10-year 6% notes due February 2013. The bonds are not subject to a sinking fund and are not redeemable prior to maturity except through a make-whole mechanism. Proceeds were used to pay down commercial paper. These bonds were assigned ratings of A- by the S&P rating agency, Baa1 by Moody's and A by Fitch, Inc. On January 15, 2003, $70 million of SoCalGas' $75 million 5.67% medium- term notes were put back to the company. In March 2003, SER repaid $100 million outstanding under a line of credit. On April 7, 2003, SoCalGas called its $100 million 7.375% first-mortgage bonds at a premium of 3.53 percent. In addition, during the six months ended June 30, 2003, Sempra Energy Financial repaid $35 million of debt incurred to acquire limited partnerships and SDG&E repaid $32 million of rate-reduction bonds. Dividends paid on common stock amounted to $104 million and $102 million for the six months ended June 30, 2003 and 2002, respectively. In April 2003, PE amended its revolving line of credit and extended the expiration date by an additional two years. The revolving credit commitment, initially $500 million, declines semi-annually by $125 million until expiration on April 5, 2005 and is for the purpose of funding loans by PE to Global. Borrowings under the agreement would bear interest at rates varying with market rates, PE's credit ratings and the amount of the borrowings outstanding. They would be guaranteed by Sempra Energy and would be subject to mandatory repayment if SoCalGas' unsecured long-term credit ratings were to cease to be at least BBB by S&P and Baa2 by Moody's, if Sempra Energy's or SoCalGas' debt-to-total capitalization ratio (as defined in the agreement) were to exceed 65 percent, or if there were to be a change in law materially and adversely affecting the ability of SoCalGas to pay dividends or make distributions to PE. No borrowings have been made under this agreement. In May 2003, the California Utilities replaced their expiring $500 million, 364-day credit agreement with a substantially identical agreement expiring on May 14, 2004. Under the agreement, each utility may individually borrow up to $300 million, subject to a combined borrowing limit for both utilities of $500 million. At the maturity date, each utility may convert its then outstanding borrowings to a one-year term loan, subject to having obtained any requisite regulatory approvals. Borrowings under the agreement would be available for general corporate purposes including back-up support for commercial paper and variable-rate long-term debt, and would bear interest at rates varying with market rates and the borrowing utility's credit rating. The agreement requires each utility to maintain a debt-to- total capitalization ratio (as defined in the agreement) of not to exceed 60 percent. The rights, obligations and covenants of each utility under the agreement are individual rather than joint with those of the other utility, and a default by one utility would not constitute default by the other. 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, SEI and other businesses. Recent developments concerning the factors influencing future performance are summarized below. Note 3 of the notes to Consolidated Financial Statements and the Annual Report describe events in the deregulation of California's electric and natural gas industries and various FERC, SET and income tax issues. Income-Tax Issues Resolution of the income-tax issues described in Note 3 of the notes to Consolidated Financial Statements herein could have a material impact on results of operations for 2003, or one or more future periods. California Utilities Electric Industry Restructuring and Electric Rates Supply/demand imbalances and a number of other factors resulted in abnormally high electric-commodity costs beginning in mid-2000 and continuing into 2001. This caused SDG&E's customer bills to be substantially higher than normal. In response, legislation enacted in September 2000 imposed a ceiling on the cost of electricity that SDG&E could pass on to its small-usage customers on a current basis. SDG&E accumulated the amount that it paid for electricity in excess of the ceiling rate in an interest-bearing balancing account, which it continues to collect from its customers. During the six months ended June 30, 2003, the balance in the balancing account declined from $215 million to $174 million. Subsequent to the electric capacity shortages of 2000-2001, SDG&E's service territory has had and continues to have an adequate supply of electricity. However, various projections of electricity demand in SDG&E's service territory indicate that, without additional electrical generation or reductions in electrical usage, beginning in 2005 electricity demand could begin to outstrip available resources. SDG&E's strategy for meeting this demand is to: (1) reduce power demand through conservation and efficiency; (2) increase the supply of electricity from renewable sources, including wind and solar; (3) establish new transmission lines by 2008 to import more power; and (4) provide new electric generation by 2005 to meet the expected shortfall. SDG&E has issued a request for proposals to meet the electric capacity shortfall, estimated at 69 megawatts in 2005. SDG&E is ahead of the interim schedule required by California legislation in meeting the requirement of obtaining 20 percent of its electricity from renewable sources by 2017. Operating costs of SONGS Units 2 and 3, including nuclear fuel and related financing costs, and incremental capital expenditures are recovered through the Incremental Cost Incentive Pricing (ICIP) mechanism which allows SDG&E to receive approximately 4.4 cents per kilowatt-hour for SONGS generation. Any differences between these costs and the incentive price affect net income. This mechanism expires on December 31, 2003. For the year ended December 31, 2002, ICIP contributed $50 million to SDG&E's net income. The CPUC has denied the previously approved market-based pricing for SONGS beginning in 2004 and instead provided for traditional rate-making treatment, under which the SONGS ratebase would begin at zero, essentially eliminating earnings from SONGS until ratebase grows. The company has applied for rehearing of this decision, which the CPUC has not yet ruled on. The company is in the process of litigating the SONGS revenue requirement, primarily in conjunction with the General Rate Case of Southern California Edison (the operator and 75-percent owner of SONGS), for rates that begin in January 2004. (SDG&E seeks to recover approximately 95 percent of its 2004 SONGS operating & maintenance and capital revenue requirements in that case.) The remaining five percent of the company's SONGS revenue requirement will be litigated in SDG&E's Cost Of Service proceeding. See additional discussion of this and related topics, including the CPUC's adjustment to its plan for deregulation of electricity, in Note 3 of the notes to Consolidated Financial Statements. Natural Gas Restructuring and Rates As discussed in the Annual Report, in December 2001 the CPUC issued a decision related to natural gas industry restructuring, with implementation anticipated during 2002. During 2002 the California Utilities filed a proposed implementation schedule and revised tariffs and rules required for implementation. However, on February 27, 2003, the CPUC issued a resolution rejecting without prejudice those proposed tariffs and rules. The resolution ordered SoCalGas to file a new application, which would address detailed proposals for implementation of the December 2001 decision, but also would allow reconsideration of the December 2001 decision. SoCalGas filed such an application on June 30, 2003, and proposed some modifications to the provisions of the December 2001 decision to respond to concerns that it could lead to higher natural gas costs for consumers. Modifications proposed by SoCalGas would also remove SoCalGas' exposure to risk or reward for the sale of receipt-point capacity. The filing proposes implementation of these provisions on April 1, 2004 and continuing through August 31, 2006. If the December 2001 decision is implemented, it is not expected to adversely affect the California Utilities' results of operations, cash flows or financial position. A CPUC decision is expected during 2004. CPUC Investigation of Compliance with Affiliate Rules On February 27, 2003, the CPUC opened an investigation of the business activities of SDG&E, SoCalGas and Sempra Energy to ensure that they have complied with relevant statutes and CPUC decisions in the management, oversight and operations of their companies. The Assigned Commissioner and ALJ issued a ruling which suspends the procedural schedule until the CPUC completes an independent audit to evaluate energy-related business activities undertaken by Sempra Energy within the service territories of SDG&E and SoCalGas, relative to holding company systems and affiliate activities. The audit is to consider whether these activities pose any problems for ratepayers and whether they are consistent with the CPUC's decision, rules or orders and/or affiliate statutes. The objective of the audit is to analyze the adequacy of the Affiliate Rules. 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. Cost of Service Filing On May 22, 2003, the assigned CPUC Commissioner modified his previously adopted procedural schedule on the California Utilities' Cost of Service applications to expedite a decision by approximately one month, permitting a decision by as early as March 2004. The assigned Commissioner also provided for additional comments to be filed on the California Utilities' request for interim relief for the period from January 1, 2004 to the date of the Cost of Service decision and stated that a decision on the request would be prepared for consideration of the full Commission. On June 3, 2003, various parties filed reply comments supporting or opposing the motion for January 1, 2004 interim relief. The CPUC's Office of Ratepayer Advocates' (ORA) report on the California Utilities' filing is due on August 8, 2003. An October 10, 2001 decision denied the California Utilities' request to continue equal sharing between ratepayers and shareholders of the estimated savings for the 1998 Enova-PE business combination that created Sempra Energy and, instead, ordered that all of the estimated 2003 merger savings go to ratepayers. This decision will adversely affect 2003 net income by $24 million at SoCalGas and $11 million at SDG&E. Sempra Energy Global Enterprises Electric-Generation Assets As discussed in "Cash Flows From Investing Activities" above and in the Annual Report, the company is involved in the development of several electric-generation projects that will significantly impact the company's future performance. SER has approximately 2,700 megawatts of new generation in operation or under construction. The 550-megawatt Elk Hills power project, 50 percent owned by SER and located near Bakersfield, California, began commercial operations in July 2003. The 1,250-megawatt Mesquite Power Plant near Phoenix, Arizona, commenced commercial operations at 50-percent capacity in June 2003 and is expected to reach full capacity in November 2003. Termoelectrica de Mexicali, a 600-megawatt power plant near Mexicali, Baja California, Mexico, commenced operations in June 2003, contingent upon resolution of the sufficiency issue of environmental impact studies and permits (see additional discussion under "Cash Flows from Investing Activities"). The 305-megawatt Twin Oaks Power Plant located near Bremond, Texas, was acquired in October 2002. El Dorado Energy, a 480- megawatt power plant near Las Vegas, Nevada, 50 percent owned by SER, began commercial operation in May 2000. Electricity from the plants will be available for markets in California, Arizona, Texas and Mexico. SER's projected portfolio of plants in the western United States and Baja California may be used to supply power to California under SER's agreement with the DWR. Investments As discussed in "Cash Flows From Investing Activities" above and in the Annual Report, the company's investments will significantly impact the company's future performance. During 2002, SET completed acquisitions that added base metals trading and warehousing to its trading business. These acquisitions include Sempra Metals Limited and Henry Bath & Son Limited. In addition, SET acquired assets of Sempra Metals & Concentrates Corp. and the U.S. warehousing business of Henry Bath, Inc. and SER acquired the Twin Oaks Power Plant. SEI is in the process of developing Energia Costa Azul, an LNG receiving terminal in Baja California, Mexico, expected to commence commercial operations in early 2007. In April 2003, Sempra Energy LNG Corp. acquired the proposed Hackberry, La. LNG project, to be renamed Cameron LNG, which could begin commercial operations in early 2007. On September 6, 2002, SEI initiated proceedings under the 1994 Bilateral Investment Treaty between the United States and Argentina for recovery of the diminution of the value of its investments resulting from governmental actions. SEI has made a request for arbitration to the International Center for Settlement of Investment Disputes (ICSID) and all arbitrators have been selected. The company has filed a claim for $258 million with ICSID and has presented additional information that may provide a basis for a larger award. A decision is expected in late 2004. NEW ACCOUNTING STANDARDS Relevant pronouncements that have recently become effective or that are yet to be effective are SFAS 142, 143, 148, 149 and 150, Interpretations 45 and 46, EITF 02-3, and the rescission of EITF 98-10. See discussion in Note 2 of the notes to Consolidated Financial Statements. Pronouncements that have or potentially could have a material effect on future earnings are described below. In October 2002, the EITF reached a consensus to rescind Issue 98-10 "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," the basis for mark-to-market accounting used for recording certain trading activities by SET and SES. The consensus provided that new contracts entered into subsequent to October 25, 2002 should not be accounted for 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. 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. This is further described in Note 2 of the notes to Consolidated Financial Statements. One impact of the rescission is that an enterprise that hedges its commodity risk on items previously marked-to-market under Issue 98-10 but not covered by SFAS 133 could have to record a loss on the hedges without being able to record the corresponding gain on the hedged items, even though no economic loss exists. For SET, its earnings for the six months ended June 30, 2003 of $17 million were negatively impacted by $28 million of the cumulative- effect adjustment and an additional $16 million related to operations during the six-month period to reflect the ongoing effects of the rescission of Issue 98-10. SES's six months ended June 30, 2003 results were negatively impacted by the cumulative effect adjustment of $1 million to reflect the rescission of Issue 98-10. SFAS 143, "Accounting for Asset Retirement Obligations" : SFAS 143, issued in July 2001, addresses financial accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets. It requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The company adopted SFAS 143 on January 1, 2003. See further discussion in Note 2 of the notes to Consolidated Financial Statements. FASB Interpretation No. 46 (FIN 46), "Consolidation of Variable Interest Entities": 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. The consolidation requirements of the interpretation apply immediately to VIEs created after January 31, 2003. For Sempra Energy, the consolidation requirements apply to pre-existing VIEs beginning July 1, 2003. Sempra Energy has identified two VIEs, of which one is related to the Mesquite Power Plant and one is related to an investment in an unconsolidated subsidiary, Atlantic Electric & Gas Limited. Accordingly, effective July 1, 2003, Sempra Energy will consolidate these entities, which are expected to significantly increase total assets and total liabilities by an estimated $650 million. However, the company does not expect a significant impact to income before the cumulative effect of a change in accounting principle and estimates that the cumulative effect of the change will be a charge of $30 million. See Note 2 of the notes to Consolidated Financial Statements for further discussion. ITEM 3. MARKET RISK There have been no significant changes in the risk issues affecting the company subsequent to those discussed in the Annual Report. The VaR for SET at June 30, 2003, and the average VaR for the six-month period ended June 30, 2003, at the 95-percent and 99-percent confidence intervals (one-day holding period) were as follows (in millions of dollars): 95% 99% ------ ------ At June 30, 2003 $ 5.28 $ 7.45 Average for the six months ended 6/30/03 $ 7.79 $10.98 As of June 30, 2003, the total VaR of the California Utilities' and SES's natural gas 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 within 90 days prior to the date of this report 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 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 Except as described in Note 3 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 4. SUBMISSION OF MATTERS TO VOTE Sempra Energy's 13-member board of directors is divided into three classes whose terms are staggered so that the term of one class expires at each Annual Meeting of Shareholders. At the annual meeting on May 13, 2003, the shareholders of Sempra Energy elected four directors for a three-year term expiring in 2006. The name of each nominee and the number of shares voted for and withheld from the election of each director were as follows: Nominees Votes For Votes Withheld ------------------------------------------------------------- James G. Brocksmith, Jr. 156,575,103 18,417,791 Herbert L. Carter 151,116,141 23,876,753 William D. Jones 151,571,173 23,421,721 William G. Ouchi 147,565,155 27,427,739 Each of the following proposals received a majority of the votes cast on the proposal and, accordingly, was approved by shareholders. The results of the voting on the proposals were as follows: A Compensation Committee proposal recommending approval of the 2003 Percentage Percentage Executive Incentive Plan. of Shares of Shares Votes Outstanding Voted ----------- ------------ ------------ In Favor 144,196,405 69% 85% Opposed 25,403,742 12% 15% A shareholder proposal recommending simple majority voting. In Favor 82,924,874 40% 59% Opposed 56,465,786 27% 41% A shareholder proposal recommending annual election of all directors. In Favor 78,201,213 37% 56% Opposed 61,349,322 29% 44% The following proposal did not receive a majority of the votes cast on the proposal and, accordingly, was not approved by shareholders. The results of the voting on the proposal were as follows: A shareholder proposal recommending an independent Chairman of the Board. Percentage Percentage of Shares of Shares Votes Outstanding Voted ----------- ------------ ------------ In Favor 57,376,389 27% 41% Opposed 81,986,910 39% 59% Additional information concerning the election of the board of directors and other matters voted upon at the Annual Meeting is contained in Sempra Energy's Notice of 2003 Annual Meeting of Shareholders and Proxy Statement. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits Exhibit 10 - Material Contracts 10.1 2003 Executive Incentive Plan 10.2 Amended 1998 Long-Term Incentive Plan Exhibit 12 - Computation of ratios 12.1 Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends. Exhibit 31 - Section 302 Certification 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 Certification 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 March 31, 2003: Current Report on Form 8-K filed May 1, 2003, filing as an exhibit Sempra Energy's press release of May 1, 2003, giving the financial results for the three months ended March 31, 2003. Current Report on Form 8-K filed August 7, 2003, filing as an exhibit Sempra Energy's press release of August 7, 2003, giving the financial results for the three months ended June 30, 2003. 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: August 7, 2003 By: /s/ F. H. Ault ---------------------------- F. H. Ault Sr. Vice President and Controller