UNITED STATES
                   SECURITIES AND EXCHANGE COMMISSION
                         Washington, D.C.  20549

                               FORM 10-Q

     [ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                    SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended          September 30, 2003
                              -------------------------------------

Commission file number                      1-14201
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                              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
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           (Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period
that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days.
                                               Yes   X      No
                                                   -----       -----

Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Exchange Act).
                                               Yes   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 October 31, 2003:       226,236,056
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          INFORMATION REGARDING FORWARD-LOOKING STATEMENTS


This Quarterly Report contains statements that are not historical fact
and constitute forward-looking statements within the meaning of the
Private Securities Litigation Reform Act of 1995. The words
"estimates," "believes," "expects," "anticipates," "plans," "intends,"
"may," "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 AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
(Dollars in millions, except per share amounts)
Three months ended September 30, ------------------ 2003 2002 ------- ------- OPERATING REVENUES California utilities: Natural gas $ 870 $ 658 Electric 576 358 Other 612 369 ------- ------- Total 2,058 1,385 ------- ------- OPERATING EXPENSES California utilities: Cost of natural gas 372 216 Electric fuel and net purchased power 128 81 Other cost of sales 371 165 Other operating expenses 668 424 Depreciation and amortization 158 147 Franchise fees and other taxes 54 42 ------- ------- Total 1,751 1,075 ------- ------- Operating income 307 310 Other income (expense) - net 34 (21) Interest income 8 10 Interest expense (78) (73) Preferred dividends of subsidiaries (2) (3) Trust preferred distributions by subsidiary -- (4) ------- ------- Income before income taxes 269 219 Income taxes 58 69 ------- ------- Net income $ 211 $ 150 ======= ======= Weighted-average number of shares outstanding (thousands) Basic 208,816 204,932 ------- ------- Diluted 212,273 205,366 ------- ------- Net income per share of common stock Basic $ 1.01 $ 0.73 ------- ------- Diluted $ 1.00 $ 0.73 ------- ------- Dividends declared per share of common stock $ 0.25 $ 0.25 ======= ======= See notes to Consolidated Financial Statements.
SEMPRA ENERGY AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED INCOME (Dollars in millions, except per share amounts)
Nine months ended September 30, ------------------ 2003 2002 ------- ------- OPERATING REVENUES California utilities: Natural gas $ 2,961 $ 2,292 Electric 1,368 962 Other 1,492 1,094 ------- ------- Total 5,821 4,348 ------- ------- OPERATING EXPENSES California utilities: Cost of natural gas 1,529 945 Electric fuel and net purchased power 428 221 Other cost of sales 886 503 Other operating expenses 1,631 1,314 Depreciation and amortization 455 447 Franchise fees and other taxes 167 129 ------- ------- Total 5,096 3,559 ------- ------- Operating income 725 789 Other income - net 38 6 Interest income 30 31 Interest expense (223) (220) Preferred dividends of subsidiaries (8) (9) Trust preferred distributions by subsidiary (9) (13) ------- ------- Income before income taxes 553 584 Income taxes 109 143 ------- ------- Income before extraordinary item and cumulative effect of change in accounting principle 444 441 Extraordinary item, net of tax -- 2 ------- ------- Income before cumulative effect of change in accounting principle 444 443 Cumulative effect of change in accounting principle, net of tax (29) -- ------- ------- Net income $ 415 $ 443 ======= ======= Weighted-average number of shares outstanding (thousands) Basic 207,620 205,047 ------- ------- Diluted 210,160 206,263 ------- ------- Income before extraordinary item and cumulative effect of change of accounting principle per share of common stock Basic $ 2.14 $ 2.15 ------- ------- Diluted $ 2.12 $ 2.14 ------- ------- Income before cumulative effect of change in accounting principle per share of common stock Basic $ 2.14 $ 2.16 ------- ------- Diluted $ 2.12 $ 2.15 ------- ------- Net income per share of common stock Basic $ 2.00 $ 2.16 ------- ------- Diluted $ 1.98 $ 2.15 ------- ------- Common dividends declared per share $ 0.75 $ 0.75 ======= ======= See notes to Consolidated Financial Statements.
SEMPRA ENERGY CONSOLIDATED BALANCE SHEETS (Dollars in millions)
September 30, December 31, 2003 2002 ------------- ------------- ASSETS Current assets: Cash and cash equivalents $ 411 $ 455 Accounts receivable - trade 610 754 Accounts and notes receivable - other 143 135 Due from unconsolidated affiliates 134 80 Deferred income taxes 71 20 Trading assets 4,650 5,064 Regulatory assets arising from fixed-price contracts and other derivatives 145 151 Other regulatory assets 88 75 Inventories 240 134 Other 161 142 ------- ------- Total current assets 6,653 7,010 ------- ------- Investments and other assets: Fixed-price contracts and other derivatives -- 42 Due from unconsolidated affiliates 54 57 Regulatory assets arising from fixed-price contracts and other derivatives 704 812 Other regulatory assets 455 532 Nuclear-decommissioning trusts 529 494 Investments 1,481 1,313 Sundry 725 665 ------- ------- Total investments and other assets 3,948 3,915 ------- ------- Property, plant and equipment: Property, plant and equipment 14,474 13,816 Less accumulated depreciation and amortization (7,021) (6,984) ------- ------- Total property, plant and equipment - net 7,453 6,832 ------- ------- Total assets $18,054 $17,757 ======= ======= See notes to Consolidated Financial Statements.
SEMPRA ENERGY CONSOLIDATED BALANCE SHEETS (Dollars in millions)
September 30, December 31, 2003 2002 ------------- ------------ LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities: Short-term debt $ 639 $ 570 Accounts payable - trade 675 694 Accounts payable - other 59 50 Income taxes payable 82 22 Trading liabilities 3,890 4,094 Dividends and interest payable 131 133 Regulatory balancing accounts - net 422 578 Fixed-price contracts and other derivatives 152 153 Current portion of long-term debt 726 281 Other 624 672 ------- ------- Total current liabilities 7,400 7,247 ------- ------- Long-term debt 3,536 4,083 ------- ------- Deferred credits and other liabilities: Due to unconsolidated affiliate 162 162 Customer advances for construction 98 91 Post-retirement benefits other than pensions 136 136 Deferred income taxes 751 800 Deferred investment tax credits 85 90 Fixed-price contracts and other derivatives 791 813 Regulatory liabilities arising from asset retirement obligations 241 -- Other regulatory liabilities 91 121 Asset retirement obligations 310 -- Mandatorily redeemable preferred securities 223 -- Deferred credits and other liabilities 841 985 ------- ------- Total deferred credits and other liabilities 3,729 3,198 ------- ------- Preferred stock of subsidiaries 179 204 ------- ------- Mandatorily redeemable trust preferred securities -- 200 ------- ------- Commitments and contingent liabilities (Note 3) SHAREHOLDERS' EQUITY Preferred stock (50 million shares authorized, none issued) -- -- Common stock (750 million shares authorized; 212 million and 205 million shares outstanding at September 30, 2003 and December 31, 2002, respectively) 1,534 1,436 Retained earnings 2,121 1,861 Deferred compensation relating to ESOP (31) (33) Accumulated other comprehensive income (loss) (414) (439) ------- ------- Total shareholders' equity 3,210 2,825 ------- ------- Total liabilities and shareholders' equity $18,054 $17,757 ======= ======= See notes to Consolidated Financial Statements.
SEMPRA ENERGY CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (Dollars in millions)
Nine months ended September 30, ------------------- 2003 2002 ------- ------- CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 415 $ 443 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 455 447 Provision for impairment on long-lived assets 77 -- Deferred income taxes and investment tax credits (52) (22) Other - net 38 67 Net changes in other working capital components (33) (58) Changes in other assets (34) 70 Changes in other liabilities 28 70 ------- ------- Net cash provided by operating activities 923 1,015 ------- ------- CASH FLOWS FROM INVESTING ACTIVITIES Expenditures for property, plant and equipment (664) (802) Investments and acquisitions of subsidiaries, net of cash acquired (182) (337) Dividends received from unconsolidated affiliates 21 11 Loans to unconsolidated affiliate (54) (48) Other - net (8) (17) ------- ------- Net cash used in investing activities (887) (1,193) ------- ------- CASH FLOWS FROM FINANCING ACTIVITIES Common dividends paid (155) (154) Issuances of common stock 81 12 Repurchases of common stock (6) (16) Issuances of long-term debt 400 800 Payments on long-term debt (481) (431) Increase (decrease) in short-term debt 89 (200) Other - net (8) (18) ------- ------- Net cash used in financing activities (80) (7) ------- ------- Decrease in cash and cash equivalents (44) (185) Cash and cash equivalents, January 1 455 605 ------- ------- Cash and cash equivalents, September 30 $ 411 $ 420 ======= ======= SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Interest payments, net of amounts capitalized $ 216 $ 210 ======= ======= Income tax payments, net of refunds $ 97 $ 47 ======= ======= 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 Reports on Form 10-Q for the three months ended March 31, 2003 and June 30, 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 Nine months ended ended September 30, September 30, --------------------------------- (Dollars in millions) 2003 2002 2003 2002 - ----------------------------------------------------------------- Net income $ 211 $ 150 $ 415 $ 443 Foreign currency adjustments (13) (54) 31 (182) Minimum pension liability adjustments -- -- (6) (14) --------------------------------- Comprehensive income $ 198 $ 96 $ 440 $ 247 - ----------------------------------------------------------------- 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 by the release of Issue 02-3, the company no longer recognizes energy-related contracts under mark-to-market accounting unless the contracts meet the requirements stated under SFAS 133, "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 Issue 98-10's rescission 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, $6 million of the $29 million was realized during the nine months ended September 30, 2003, all of which occurred in the third quarter. Neither the cumulative nor the ongoing effect impacts the company's cash flow or liquidity. 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 nine months ended September 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 September 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 to utility plant of $71 million, representing the company's share of the San Onofre Nuclear Generating Station's (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 nine months ended September 30, 2003 is as follows (dollars in millions): Balance as of January 1, 2003 $ -- Adoption of SFAS 143 329 Accretion expense 17 Payments (12) ------ Balance as of September 30, 2003 $ 334* ====== *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 144, "Accounting for the Impairment or Disposal of Long-Lived Assets": In August 2001, the FASB issued SFAS 144, which supercedes a prior accounting standard related to the accounting for the impairment or disposal of long-lived assets. However, SFAS 144 retains the fundamental provisions of the impairment standard regarding recognition/measurement of impairment of long-lived assets to be held and used and measurement of long-lived assets to be disposed of by sale. SFAS 144 applies to all long-lived assets, including discontinued operations. Under SFAS 144 the company is required to reduce the carrying value of assets to fair value and recognize asset impairment charges in the event that the carrying value of such assets exceeds the estimated future undiscounted cash flows attributable to such assets. During the third quarter of 2003, the company recorded a $77 million non-cash impairment charge ($47 million after-tax) to write down the carrying value of the assets of Frontier Energy, a small North Carolina utility subsidiary, as a result of reductions in actual and previously anticipated sales of natural gas by this utility. This charge is included in other operating expenses in the Statements of Consolidated Income. In applying the provisions of SFAS 144, management determined the fair value of such assets based on its estimate of discounted future cash flows. 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 Nine months ended September 30, September 30, ------------------------ ----------------------- 2003 2002 2003 2002 ------------------------ ----------------------- Net income as reported $ 211 $ 150 $ 415 $ 443 Stock-based employee compensation expense included in the computation of net income, net of tax 3 (2) 17 (1) Total stock-based employee compensation under fair value method for all awards, net of tax (5) -- (23) (6) ------------------------ ----------------------- Pro forma net income $ 209 $ 148 $ 409 $ 436 ======================== ======================= Earnings per share: Basic--as reported $ 1.01 $ 0.73 $ 2.00 $ 2.16 ======================== ======================= Basic--pro forma $ 1.00 $ 0.72 $ 1.97 $ 2.13 ======================== ======================= Diluted--as reported $ 1.00 $ 0.73 $ 1.98 $ 2.15 ======================== ======================= Diluted--pro forma $ 0.98 $ 0.72 $ 1.95 $ 2.11 ======================== =======================
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. The adoption of SFAS 149 did not have an effect on the company's consolidated results of operations and financial position. 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 previously classified in the mezzanine section of the balance sheet be reclassified as liabilities. The company has adopted SFAS 150 beginning July 1, 2003 by reclassifying $200 million and $23 million of mandatorily redeemable trust preferred securities and preferred stock of subsidiaries, respectively, to deferred credits and other liabilities. 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 also will likely be 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 consolidation requirements of the interpretation apply immediately to entities created after January 31, 2003. During October 2003, the FASB deferred the implementation date for pre-existing variable interest entities until the end of the first interim or annual period ending after December 15, 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 (AEG), that markets power and natural gas commodities to commercial and residential customers in the United Kingdom. As currently written, FIN 46 would require Sempra Energy to record 100% of AEG's operations, whereas it now records only its share of AEG's net operating results. The other entity is the lessor of the Mesquite Power Plant (Mesquite Power) described below. Accordingly, if the FASB's deliberations during the deferral period do not result in the exclusion of these entities from FIN 46's definitions, Sempra Energy will consolidate these entities in its financial statements during the fourth quarter of 2003. This is estimated to increase total assets and total liabilities by $700 million. The company expects implementation to result in an after-tax charge for the cumulative effect from the change in accounting principle to be approximately $17 million and no change to operating income. Mesquite Power, located near Phoenix, Arizona, is a $675 million, 1,250- megawatt (mw) project that provides 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 September 30, 2003 are $641 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 by U.S. Treasury obligations in similar amounts. As of September 30, 2003, the company held $350 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 and the power crisis of 2000-2001 caused the California Public Utilities Commission (CPUC) to adjust its plan for restructuring the electricity industry. The background of this issue is described in the Annual Report. Subsequent developments are described herein. Various projections of electricity demand in SDG&E's service territory indicate that, without additional electrical generation and transmission and reductions in electrical usage, beginning in 2005 electricity demand could begin to outstrip available resources. 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 approximately 100 megawatts, and has filed a proposed plan at the CPUC for meeting these capacity requirements. On October 7, 2003, SDG&E applied to the CPUC for approval of its RFP results. SDG&E's electric procurement plan contemplates (i) procuring 643 megawatts of energy and demand reduction resources (73 megawatts beginning in 2005 with contracts extending through 2020 and 570 megawatts beginning in 2007 and extending through 2017); (ii) acquiring 601 megawatts of new generation, including a 555-megawatt power plant in Escondido, California, to be constructed by SER for completion in 2006; and (iii) constructing new transmission lines. The capital cost related to this proposed plan is approximately $640 million and the plan includes a mix of energy supply sources, including renewable resources. Hearings will be held during the fourth quarter of 2003 and a CPUC decision is expected during the first half of 2004. In connection with the possible return to a generation-ownership role for investor-owned utilities (IOUs), SDG&E required bidders to include both power purchase and SDG&E ownership options in their response to the RFP noted above. The California Department of Water Resources' (DWR) Operating Agreement with SDG&E, approved by the CPUC, governs SDG&E's 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 SDG&E's 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. Since the DWR retains legal and financial responsibility for the contracts allocated to SDG&E, the costs associated with the contracts were not included in the Statements of Consolidated Income during 2003. On July 10, 2003, the CPUC approved SDG&E's natural gas supply plan related to certain DWR contracts for the five-month period May 1, 2003 to September 30, 2003. On August 15, 2003, SDG&E filed with the CPUC its natural gas supply plan related to certain DWR contracts for the six-month period October 1, 2003 to March 31, 2004. CPUC action on this filing is pending. On September 4, 2003, the CPUC approved a $1-billion refund to consumers of the three major California IOUs as a result of the DWR's lowering its revenue requirement for 2003. The refund is being returned to customers in the form of a one-time bill credit. SDG&E's portion is 13.51 percent or about $135 million. The bill credit will have no effect on SDG&E's net income and net cash flows because customer savings are coming from lower charges by the DWR, and SDG&E is merely transmitting the electricity from the DWR to the customers, without taking title to the electricity. The final true-up of DWR's 2001/2002 energy costs among California's three major investor-owned electric utilities could result in SDG&E's customers being allocated up to $60 million of additional costs or having their allocation reduced by as much as $100 million. In either case, SDG&E would account for any adjustment in its commodity balancing account, which would be repaid to its customers or collected from its customers in the near future. Either change in allocation would have a short-term effect on SDG&E's cash flow (positive or negative as the case may be), but would not otherwise affect its results of operations. On August 21, 2003, the CPUC denied a rehearing requested by opponents of its December 2002 decision that had approved a settlement with SDG&E allocating between SDG&E customers and shareholders the profits from intermediate-term purchase power contracts that SDG&E had entered into during the early stages of California's electric utility industry restructuring. As previously reported, the settlement provided $199 million of these profits to customers, by reductions to balancing account undercollections in prior years. The settlement provided the remaining $173 million of profits to SDG&E shareholders, of which $57 million had been recognized for financial reporting purposes in prior years. As a result of the decision, SDG&E recognized additional after- tax income of $65 million in the third quarter of 2003. On September 25, 2003 the Utility Consumers' Action Network (UCAN), a consumer-advocacy group which had requested the CPUC rehearing, appealed the decision to the California Court of Appeals. On October 24, 2003, SDG&E and the Commission filed responses with the court to the UCAN appeal, setting forth the reasons why there is no issue of law for the court to consider and that the appeal should be denied. UCAN has twenty days to file a reply. Acceptance of any appeal is at the discretion of the court. There is no deadline by which the court must act. 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. The DA CRS has no impact on SDG&E; however, the surcharge may affect SES's ability to attract and maintain customers in California. 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. The 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). The proposed 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. On September 29, 2003, the CPUC issued a ruling indicating that the proceeding will initially only consider implementation of the original December 2001 decision, but the Assigned Commissioner said he will informally look at the alternatives proposed by SoCalGas. The matter has been set for hearing and a CPUC decision is expected by January 2004. If the December 2001 decision is implemented, it is not expected to have a material effect on the California Utilities' earnings. 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. On September 18, 2003, the Commission suspended 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 will be combined with the annual affiliate audit and should be completed by the end of 2004. The scope of the audit will be broader than the annual affiliate audit. In addition to an evaluation of compliance with CPUC rules and requirements, this audit will assess the potential for conflicts between the interests of Sempra Energy and the interests of the California Utilities and their ratepayers, and examine whether business activities undertaken by the utilities and/or their holding company and affiliates pose potential problems or unjust or unreasonable impacts on utility customers. COST OF SERVICE FILING As previously reported, the California Utilities have filed cost of service applications with the CPUC seeking rate increases designed to reflect forecasts of 2004 capital and operating costs. The California Utilities are requesting revenue increases of approximately $121 million. The CPUC's Office of Ratepayer Advocates (ORA) filed its prepared testimony in the applications on August 8, 2003, recommending rate decreases that would reduce annual revenues by $162 million from their current level. UCAN has proposed rates for SDG&E and The Utility Reform Network (TURN) has proposed rates for SoCalGas that would reduce annual revenues by $88 million and $178 million, respectively, from their current level. Hearings are expected to conclude by the end of this month. The procedural schedule for the cost of service applications permits a decision as early as March 2004, and the California Utilities have filed a petition for interim rate relief for the period from January 1, 2004 until the effective date of the decision. On November 3, 2003, the CPUC ALJ released a Proposed Decision that would authorize the California Utilities to create a memorandum account as of January 1, 2004, to record the difference between existing rates and those that are later authorized in the Commission's final decision in this case. The difference would then be amortized in rates. The full Commission can vote on the Proposed Decision as soon as December 4, 2003. The California Utilities have also filed for continuation through 2004 of existing PBR mechanisms for service quality and safety that would otherwise expire at the end of 2003. MARKET INDEXED CAPITAL ADJUSTMENT MECHANISM (MICAM) MICAM has the potential to revise a utility's rates to reflect changes in market interest rates. On September 4, 2003, the CPUC approved an all-party settlement that modified the MICAM such that the possibility of a MICAM-caused reduction in SDG&E's authorized return on common equity for 2004 has been eliminated. PERFORMANCE-BASED REGULATION (PBR) On August 21, 2003, the CPUC issued a final resolution approving SDG&E's 2001 and 2002 Distribution PBR Performance Reports. SDG&E was awarded $12.2 million for exceeding PBR benchmarks on all six of its performance indicators in 2001, and $6.0 million for exceeding the PBR benchmarks on five of its six performance indicators in 2002. These rewards were included in income in the third quarter of 2003. The total maximum reward (or penalty) SDG&E could earn in a given year under the Distribution PBR mechanism is $14.5 million. On July 16, 2003, SDG&E filed an Advice Letter requesting approval of a shareholder penalty of $1.4 million for Year 9 (August 1, 2001 through July 31, 2002) of its Gas Procurement PBR mechanism. The $1.4 million penalty was recorded in 2002 and is consistent with the ORA's March 19, 2003 Monitoring and Evaluation Report on SDG&E's natural gas procurement activities in Year 9. In its report, the ORA recommended the extension of the PBR mechanism, as modified in Years 8 and 9, to Year 10 and beyond, and 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. This award was recorded in income in the first quarter of 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 August 21, 2003, the CPUC approved SoCalGas' GCIM Years 7 and 8 shareholder rewards of $30.8 million and $17.4 million, respectively, subject to refund or adjustment as determined by the Commission in the Border Price Investigation described above. These rewards have been 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 $32.7 million to ratepayers during Year 9, which led to the requested shareholder reward. This application is pending before the CPUC, with approval expected in the first half of 2004. Performance incentives rewards are not included in the company's earnings before CPUC approval is received. DEMAND SIDE MANAGEMENT (DSM) AND ENERGY EFFICIENCY AWARDS Since the 1990s, IOUs have been eligible to earn awards for implementing and administering energy conservation and efficiency programs. The California Utilities have offered these programs to customers and have consistently achieved significant earnings therefrom. On October 16, 2003, the CPUC issued a decision that the pre-1998 DSM earnings mechanism would not be reopened. Therefore, the CPUC will not redetermine the uncollected portion of past awards earned by the IOUs and will not be recomputing the amounts of the awards, but may adjust such amounts consistent with the application of known, standard measurement and verification protocols. The CPUC has consolidated the 2000, 2001, 2002 and 2003 award applications. On May 2, 2003, the CPUC released an RFP to conduct a review of the IOUs' studies used as the basis for the awards claims. The review should be completed by the second quarter of 2004. All outstanding claims are on hold pending completion of the independent review. As of September 30, 2003, the California Utilities had $46 million in DSM/energy efficiency rewards requested but pending CPUC approval and had $29 million in rewards for which it has not yet requested approval. BLYTHE GAIN ON SALE The ORA is proposing to use a risk analysis to allocate the 2001 gain on the sale of SDG&E's surplus property in Blythe, California rather than the time in rate base versus out of rate base methodology proposed by SDG&E and historically used by the CPUC. SDG&E's proposal would allocate $3.1 million to ratepayers, whereas the ORA proposes to allocate $14.4 million. This issue is being addressed in the Cost of Service filing described above. A decision is expected as early as March 2004. TRANSMISSION RATE INCREASE SDG&E's retail-related rates applicable to transmission service were set based on a 1998 test year, at a level that during 2002 was substantially lower than needed to maintain an adequate return on equity (ROE). Consequently, SDG&E filed revised rates on March 7, 2003, proposing a formula rate that would allow, through June 2007, the full recovery of all transmission-related rate base and expenses on a trued-up basis. Thus, SDG&E would earn no more nor no less than its transmission cost of service at the FERC-adopted ROE for the predetermined period. On May 2, 2003, the FERC accepted SDG&E's request for modification of its Transmission Owner Tariff to adopt a rate increase, subject to hearing and, if appropriate, refunds. New transmission rates, which are subject to refund based on the FERC's final order, became effective October 1, 2003. On October 9, 2003, SDG&E filed a proposed settlement agreement with the FERC, supported by the FERC trial staff, the CPUC and the Independent System Operator (ISO). As a result of the settlement, SDG&E's ROE would be 11.25 percent, rather than the 13 percent SDG&E requested. SDG&E's revenue requirements for its retail and wholesale customers for the initial 12-month period beginning October 1, 2003, would be $142.1 million and $135.6 million, respectively, rather than the $149.5 million and $143.7 million requested. The settlement contemplates that SDG&E will fully recover its cancelled Valley-Rainbow Project costs of $19 million over a ten-year amortization period without interest. The transmission rate formula is to be in effect through June 30, 2007. A final decision is not expected before late November 2003. 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 for transmission line losses and grid management charges related to its Southwest Powerlink. SDG&E had previously been recovering these costs by charging them through the Transmission Revenue Balancing Account, but Opinion No. 458 rejected this approach and required SDG&E to refund the cost differentials so recovered. SDG&E's request for rehearing was denied. As a result, SDG&E is incurring unreimbursed costs of $4 million to $8 million per year. SDG&E has petitioned the United States Court of Appeals for review of these FERC orders and has submitted to the FERC a refund plan which would refund $21 million to transmission customers via the Transition Cost Balancing Account. This refund arrangement is subject to FERC acceptance, which is pending. 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. On October 27, 2003, an independent arbitrator found in SDG&E's favor on this matter. The ISO has the right to appeal this result to the 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 costs. 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 DWR Contract 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. Refund Proceedings The FERC is investigating prices charged to buyers in the California Power Exchange (PX) and ISO markets by various electric suppliers. The FERC is seeking to determine the extent to which individual sellers have yet to be paid for power supplied during the period of October 2, 2000 through June 20, 2001 and to estimate the amounts by which individual buyers and sellers paid and were paid in excess of competitive market prices. Based on these estimates, the FERC could find that individual net buyers, such as SDG&E, are entitled to refunds and individual net sellers, such as SET, are required to provide refunds. To the extent any such refunds are actually realized by SDG&E, they would reduce SDG&E's rate-ceiling balancing account. To the extent that SET is required to provide refunds, they could result in payments by SET after adjusting for any amounts still owed to SET for power supplied during the relevant period (or receipts if refunds are less than amounts owed to SET). In December 2002, a FERC ALJ issued preliminary findings indicating that the California PX and ISO owe power suppliers $1.2 billion (the $3.0 billion that the California PX and ISO still owe energy companies less $1.8 billion that the energy companies charged California customers in excess of the preliminarily determined competitive market clearing prices). On March 26, 2003, the FERC largely adopted the ALJ's findings, but expanded the basis for refunds by adopting a staff recommendation from a separate investigation to change the natural gas proxy component of the mitigated market clearing price that is used to calculate refunds. The March 26 order estimates that the replacement formula for estimating natural gas prices will increase the refund obligations from $1.8 billion to more than $3 billion. The FERC recently released its final instructions, and the ISO and PX have five months to recalculate the precise number through their settlement models. 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 possible share of the additional refund amount. Accordingly, it has not recorded any additional reserves but the company does not believe that any additional amounts that SET may be required to pay would be material to the company's financial position or liquidity. Manipulation Investigation The FERC is also investigating whether there was manipulation of short- term energy markets in the West that would constitute violations of applicable tariffs and warrant disgorgement of associated profits. In this proceeding, the FERC's authority is not confined to the October 2, 2000 through June 20, 2001 period relevant to the refund proceeding. In May 2002 the FERC ordered all energy companies engaged in electric energy trading activities to state whether they had engaged in various specific trading activities in violation of the PX and ISO tariffs (generally described as manipulating or "gaming" the California energy markets). On June 25, 2003, the FERC issued several orders requiring various entities to show cause why they should not be found to have violated California ISO and PX tariffs. First, FERC directed 43 entities, including SET and SDG&E, to show cause why they should not disgorge profits from certain transactions between January 1, 2000 and June 20, 2001 that are asserted to have constituted gaming and/or anomalous market behavior under the California ISO and/or PX tariffs. Second, the FERC directed more than 20 entities, including SET, to show cause why their activities during the period January 1, 2000 to June 20, 2001 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. SET has had such discussions with the FERC staff. On October 31, 2003, SET agreed to pay $7.2 million in full resolution of these investigations. The entire amount has been recorded as of September 30, 2003. The agreement is subject to final approval by the FERC and could be decided as early as December 2003. SDG&E agreed to pay $28 thousand into a FERC-established fund on behalf of customers in order to bring its case to closure. FERC approval is pending. On June 25, 2003, the FERC also determined that it was appropriate to initiate an investigation into possible physical and economic withholding in the California ISO and PX markets. For this purpose, 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 and have provided responses. 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 August 1, 2003, FERC staff issued an initial report that determined there was no need to further investigate particular entities, including SET, for physical withholding of generation. Price Reporting Practices On September 26, 2003, FERC sent a survey to 266 companies concerning natural gas and electric price reporting practices. The survey is being conducted in support of FERC's "Policy Statement on Natural Gas and Electric Price Indices" issued in July 2003, to measure industry progress in voluntary reporting of energy trade data to publishers of energy price indices. Responses to the survey were provided on behalf of SoCalGas, SDG&E and SET, and jointly by SER and SES. A second survey is expected to be conducted in March 2004 in FERC's continuing effort to monitor energy price reporting. The Commodity Futures Trading Commission is also inquiring of numerous companies, including SET, as to possible price reporting discrepancies. 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. The Price-Anderson Act provides for up to $10.6 billion of secondary financial protection if the liability loss exceeds the insurance limit. Should any of the licensed/commercial reactors in the United States experience a nuclear liability loss which exceeds the $300 million insurance limit, all utilities owning nuclear reactors could be assessed under the Price-Anderson Act to provide the secondary financial protection. SDG&E and the other co-owners of SONGS could be assessed up to $201 million under the Price-Anderson Act. SDG&E's share would be $40 million unless default occurs by any other SONGS co-owner. In the event the secondary financial protection limit is insufficient to cover the liability loss, Congress could impose 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, SDG&E could be assessed up to $7.4 million if losses at any covered facility exceed the insurance company's surplus and reinsurance funds. 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 third quarter of 2003, SEI recorded a $4 million negative adjustment to Accumulated Other Comprehensive Income (Loss), resulting in a net positive adjustment of $29 million for the nine months ended September 30, 2003. The net $29 million change reflected the increase in the value of the Argentine peso relative to the U.S. dollar. As of September 30, 2003, SEI has adjusted its investment in its two unconsolidated Argentine subsidiaries downward by $194 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. A preliminary hearing was held on July 3, 2003, establishing a timeline for arbitration. On September 4, 2003, SEI filed its legal brief with ICSID outlining its claims in more detail and is now awaiting a response from the Argentine government. A decision is expected in late 2004. LITIGATION During the third quarter of 2003, the company recorded additional charges against income for litigation costs and possible resolution of certain cases. Management believes that none of these matters will have further material adverse effect on the company's financial condition or results of operations. Except for the matters referred to below, neither the company nor its subsidiaries are party to, nor is their property the subject of, any material pending legal proceedings other than routine litigation incidental to their businesses. DWR Contract 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." Judgment was entered in SER's favor on August 14, 2003. On August 27, 2003, the DWR filed a motion for a new trial claiming irregularities in the Court's judgment. On October 15, 2003, the Court clarified its earlier summary judgment ruling and effectively denied the motion for new trial. The DWR has filed a notice of appeal on the August 14, 2003 judgment and the October 15, 2003 orders by the 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. Antitrust 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 $1.5 billion settlement, of which $125 million is allocated to customers of the California Utilities. The proceeding against Sempra Energy and the California Utilities has not been settled and continues to be litigated. Natural Gas Cases: Similar lawsuits have been filed by the Attorney General of Arizona and the Attorney General of Nevada alleging that El Paso and certain Sempra Energy subsidiaries unlawfully sought to control the natural gas market in their respective states. In April 2003, Sierra Pacific Resources and its utility subsidiary Nevada Power filed a lawsuit in U.S. District Court in Las Vegas against major natural gas suppliers, including Sempra Energy, the California Utilities and other company subsidiaries, seeking damages resulting from an alleged conspiracy to drive up or control natural gas prices, eliminate competition and increase market volatility, breach of contract and wire fraud. Electricity Cases: 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 Appeals and a decision is expected in the 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, SER 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. Price Reporting Practices In the fourth quarter of 2002, Sempra Energy and SoCalGas were named as defendants in a lawsuit filed in Los Angeles Superior Court against various trade publications and other energy companies alleging that energy prices were unlawfully manipulated by defendants' reporting artificially inflated natural gas prices to trade publications. On July 8, 2003, the Superior Court granted the defendants' demurrer on the grounds that the claims contained in the complaint were subject to the Filed Rate Doctrine and were preempted by the Federal Power Act. Plaintiffs have filed an amended complaint, and in September 2003 defendants filed a demurrer to the amended complaint. 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 addition, in August 2003, a lawsuit was filed in the Southern District of New York against Sempra Energy and SES, alleging that the prices of natural gas options traded on the NYMEX were unlawfully increased under the federal Commodity Exchange Act by defendants' manipulation of transaction data to natural gas trade publications. Other SER was 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. On September 30, 2003, the arbitration proceeding found in favor of SER, determining that SER had not breached its joint development contract with Occidental. 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 Termoelectrica de Mexicali (TDM) plant, failed to evaluate the plants' environmental impact adequately and called into question the U.S. permits they received to build their cross-border transmission lines. 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. On September 12, 2003 a Peruvian court ordered the prosecutor's case to be dismissed. The prosecutor has appealed this decision. INCOME TAX ISSUES Section 29 Income Tax Credits Earlier in the year the Internal Revenue Service (IRS) issued Announcement 2003-46, stating it has reason to question the scientific validity of testing procedures and results related to Section 29 income tax credits. The notice also announced that it would suspend the issuance of new rulings until its review is complete and that rulings could be revoked if the IRS did not determine that the test procedures demonstrate a significant chemical change between the feedstock coal and the synthetic fuel. The IRS has now completed its review and on October 29, 2003, it announced that it will be issuing private letter rulings based on the previous requirements. The Permanent Subcommittee on Investigations of the U.S. Senate's Committee on Governmental Affairs has expressed interest in investigating the issue. As part of its recently commenced normal audit program for the company for the period 1998-2001, the IRS notified the company of its intention to audit the synthetic fuel operations of SET and SEF. Through September 30, 2003, the company has recorded Section 29 income tax credits of $224 million, including $28 million and $80 million during the three months and nine months ended September 30, 2003, respectively. 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. Pending Internal Revenue Service Matters The company is in discussions with the IRS to resolve issues related to various prior years' returns. A Revenue Ruling dealing with utility balancing accounts, and 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 resolved before year end and estimates that favorable resolution could increase reported earnings by in excess of $75 million. The company is unable to predict the net effect of the ultimate resolution of these income tax issues. RECENT SOUTHERN CALIFORNIA FIRES Several major wildfires that began on October 26, 2003 severely damaged some of SDG&E's infrastructure, causing a significant number of customers to be without utility services. On October 27, 2003, Governor Gray Davis declared a "state of emergency" for four counties, including the County of San Diego and three counties within SoCalGas' service territory. The declaration of a state of emergency invokes Public Utilities Code Section 454.9, which authorizes a public utility to establish a catastrophic event memorandum account (CEMA) to record all costs associated with (1) restoring utility services to customers; (2) repairing, replacing or restoring damaged utility facilities and (3) complying with governmental agency orders in connection with events declared disasters by competent state or federal authorities. The costs recorded in the CEMA are recoverable in rates separate from ordinary costs currently recovered in rates. Public Utilities Code Section 454.9 requires that the CPUC hold expedited hearings in response to the utilities' request for recovery. SDG&E is recording fire damage costs and the costs of restoring electric and natural gas service in the CEMA account. SoCalGas is recording fire damage costs and the costs of restoring natural gas service in the CEMA account, although there has not been significant damage to the natural gas system. Therefore, the company expects no significant effect on earnings from the fires. 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 nine months ended September 30, 2003. - --------------------------------------------------------------------------- Three months ended Nine months ended September 30, September 30, ----------------------------------------------- (Dollars in millions) 2003 2002 2003 2002 - --------------------------------------------------------------------------- Operating Revenues: Southern California Gas $ 794 $ 597 $ 2,622 $ 1,999 San Diego Gas & Electric 667 425 1,749 1,271 Sempra Energy Trading 304 178 832 576 Sempra Energy Resources 234 136 453 275 All other 74 56 206 244 Intersegment revenues (15) (7) (41) (17) --------------------------------------------- Total $ 2,058 $ 1,385 $ 5,821 $ 4,348 - --------------------------------------------------------------------------- Net Income (Loss): Southern California Gas* $ 53 $ 56 $ 148 $ 167 San Diego Gas & Electric* 120 46 206 150 Sempra Energy Trading 22 10 39 73 Sempra Energy Resources 33 29 48 60 All other (17) 9 (26) (7) ----------------------------------------------- Total $ 211 $ 150 $ 415 $ 443 - --------------------------------------------------------------------------- * after preferred dividends - ---------------------------------------------------------- Balance at -------------------------- September 30, December 31, 2003 2002 - ---------------------------------------------------------- Assets: Southern California Gas $ 3,823 $ 4,079 San Diego Gas & Electric 5,523 5,123 Sempra Energy Trading 5,212 5,614 Sempra Energy Resources 1,505 1,347 All other 2,725 2,580 Intersegment receivables (734) (986) ------------------------- Total $ 18,054 $ 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" and SFAS 149, "Amendment of Statement 133 on Derivative Instruments and 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 in accordance with 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 and certain physical inventory that were recorded at fair value under EITF 98-10 but are not covered by SFAS 133. This did not impact cash flow or liquidity. The carrying values of SET's trading assets and trading liabilities approximate the following: September 30, December 31, (Dollars in millions) 2003 2002 - -------------------------------------------------------------------------- TRADING ASSETS: Unrealized gains on swaps and forwards $ 1,207 $ 1,226 OTC commodity options purchased 405 480 Due from trading counterparties 1,000 1,279 Due from commodity clearing organizations and clearing brokers 109 49 Resale agreements 10 -- Commodities owned 1,867 1,968 ------ ------ Total trading assets $ 4,598 $ 5,002 ====== ====== TRADING LIABILITIES: Unrealized losses on swaps and forwards $ 1,038 $ 816 OTC commodity options written 271 569 Due to trading counterparties 1,140 1,196 Repurchase obligations 1,363 1,511 Commodities not yet purchased 52 -- ------ ------ Total trading liabilities $ 3,864 $ 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 Cameron 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 nine months ended September 30, 2003 were primarily due to the contingent purchase price obligation arising from the company's acquisition of the proposed Cameron 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 nine months ended September 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 $3.0 billion for the nine months ended September 30, 2003 from $2.3 billion for the corresponding period in 2002, and the cost of natural gas increased to $1.5 billion in 2003 from $945 million in 2002. Additionally, natural gas revenues increased to $870 million for the three months ended September 30, 2003 from $658 million for the corresponding period in 2002, and the cost of natural gas increased to $372 million in 2003 from $216 million in 2002. These changes were primarily attributable to approved performance awards recognized during the third quarter of 2003, as well as natural gas price increases (which are passed on to customers) partially offset by reduced volumes. See discussion of performance awards in Note 3 of the notes to Consolidated Financial Statements. 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 $1.4 billion for the nine months ended September 30, 2003 from $962 million for the same period in 2002, and the cost of electric fuel and purchased power increased to $428 million in 2003 from $221 million in 2002. Additionally, electric revenues increased to $576 million for the three months ended September 30, 2003 from $358 million for the same period in 2002, and the cost of electric fuel and purchased power increased to $128 million in 2003 from $81 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, increases in electric commodity costs, the increase in authorized distribution revenue and higher volumes in 2003, and, for the quarter, recognition of $116 million related to the approved settlement of intermediate-term purchase power contracts and higher earnings from PBR awards. 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 sales to SDG&E's customers were not included in the Statements of Consolidated Income as SDG&E was merely transmitting electricity from the DWR to the customers without taking title to the electricity. 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 nine months ended September 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 189 $ 1,767 1 $ 5 190 $ 1,772 Commercial and industrial 90 649 209 138 299 787 Electric generation plants -- 3 186 61 186 64 Wholesale -- -- 14 2 14 2 --------------------------------------------------------------- 279 $ 2,419 410 $ 206 689 2,625 Balancing accounts and other 336 -------- Total $ 2,961 - ------------------------------------------------------------------------------------------- 2002: Residential 208 $ 1,461 2 $ 5 210 $ 1,466 Commercial and industrial 86 448 219 122 305 570 Electric generation plants -- -- 214 47 214 47 Wholesale -- -- 11 4 11 4 --------------------------------------------------------------- 294 $ 1,909 446 $ 178 740 2,087 Balancing accounts and other 205 -------- Total $ 2,292 - -------------------------------------------------------------------------
Electric Distribution and Transmission (Volumes in millions of kilowatt hours, dollars in millions)
2003 2002 ----------------------------------------- Volumes Revenue Volumes Revenue ----------------------------------------- Residential 4,988 $ 561 4,673 $ 486 Commercial 4,681 526 4,517 481 Industrial 1,460 125 1.393 121 Direct access 2,456 62 2,618 90 Street and highway lighting 68 8 66 7 Off-system sales 26 1 3 -- ----------------------------------------- 13,679 1,283 13,270 1,185 Balancing accounts and other 85 (223) ----------------------------------------- Total 13,679 $ 1,368 13,270 $ 962 -----------------------------------------
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 $1.5 billion for the nine months ended September 30, 2003 from $1.1 billion for the same period of 2002, and increased to $612 million for the three-month period ended September 30, 2003 from $369 million for the corresponding period of 2002. These changes were primarily due to higher revenues at SET as the result of increased volumes and volatility in the energy commodity markets and increased coal sales related to Section 29 income tax credits, and increased revenues from SER. SER's higher revenues were primarily attributable to 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 Cost of Sales Other cost of sales, which consists primarily of cost of sales at Global, increased to $886 million for the nine months ended September 30, 2003 from $503 million for the corresponding period of 2002, and increased to $371 million for the three months ended September 30, 2003 from $165 million for the same period in 2002. The increases were primarily due to the higher sales at SER and the increased activity at SET as noted above. Other Operating Expenses Other operating expenses increased to $1.6 billion for the nine months ended September 30, 2003 from $1.3 billion for the same period in 2002. Of the total balance, $1.1 billion and $975 million in 2003 and 2002, respectively, represent other operating expenses at the California Utilities. Other operating expenses increased to $668 million for the three months ended September 30, 2003 from $424 million for the corresponding period of 2002. Of the total balance, $423 million and $334 million in 2003 and 2002, respectively, represent other operating expenses at the California Utilities. The overall increase was due to general increases at the California Utilities, primarily as a result of a $64 million before-tax charge for litigation and for losses associated with a sublease of portions of the SoCalGas headquarters building. The non-recurring sublease losses pertain to pre-2003 transactions, but are charged against current operations because they are not material to annual financial statements. In addition, general operating costs increased at SER, SET and SEI, mainly due to a $77 million before-tax write-down of the carrying value of the assets of Frontier Energy, a small North Carolina utility subsidiary, as a result of reductions in actual and previously anticipated sales of natural gas by the utility. Other Income - Net Other income, which primarily consists of equity earnings from unconsolidated subsidiaries and interest on regulatory balancing accounts, increased to $38 million for the nine months ended September 30, 2003 from $6 million for the nine months ended September 30, 2002. The increase was primarily due to increased equity earnings from SEI and other subsidiaries, offset partially by depressed results at SER's joint ventures. Other income increased to $34 million for the three months ended September 30, 2003, from a net expense of $21 million for the corresponding period of the prior year due primarily to increased equity earnings from SER, SEI and other subsidiaries. Income Taxes Income tax expense decreased to $109 million for the nine months ended September 30, 2003 from $143 million for the same period of 2002. The effective income tax rates were 19.7 percent and 24.5 percent for the nine-month periods ended September 30, 2003 and 2002, respectively. The changes were 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. Income tax expense decreased to $58 million for the third quarter of 2003 compared to $69 million for the third quarter of 2002, and the effective income tax rate decreased to 21.6 percent from 31.5 percent. These changes were due to increased income tax credits in 2003, partially offset by higher pretax income. In connection with its affordable-housing investments, the company has unused tax credits dating back to 2000, which the company fully expects to utilize before their various expiration dates of 2020 to 2023. At September 30, 2003, the amount of these unused tax credits was $192 million. In addition, at September 30, 2003, the company has $73 million of alternative minimum tax credits with no expiration date. Net Income For the nine months ended September 30, net income decreased to $415 million, or $1.98 per diluted share of common stock, in 2003 from $443 million, or $2.15 per diluted share in 2002. Excluding the effects of the cumulative effect of the changes 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 associated with negative goodwill from SET's acquisitions of the metals business ($0.01 per diluted share, discussed in the Annual Report), income increased to $444 million in 2003 from $441 million in 2002. The slight increase was due to the approved settlement of intermediate- term purchase power contracts and the recognition of higher performance awards, offset by the write-down of assets at Frontier Energy, litigation and sublease losses as well as the $25 million income-tax resolution in the second quarter of 2002. Net income for the third quarter was $211 million, or $1.00 per diluted share for 2003, compared to $150 million or $0.73 per diluted share in 2002. The increase was due primarily to the factors discussed above, other than the $25 million income-tax resolution, as well as lower income tax expense in 2003. Net Income by Business Unit
Three months ended Nine months ended September 30, September 30, (Dollars in millions) 2003 2002 2003 2002 - ------------------------------------------------------------------------------- California Utilities Southern California Gas Company* $ 53 $ 56 $ 148 $ 167 San Diego Gas & Electric* 120 46 206 150 ------ ------ ------ ------ Total Utilities 173 102 354 317 Global Enterprises Sempra Energy Trading 22 10 39 73 Sempra Energy Resources 33 29 48 60 Sempra Energy International (32) 13 (7) 30 Sempra Energy Solutions -- 5 7 11 ------ ------ ------ ------ Total Global Enterprises 23 57 87 174 Sempra Energy Financial 13 9 32 23 Parent and other 2 (18) (58) (71) ------ ------ ------ ------ Consolidated $ 211 $ 150 $ 415 $ 443 ====== ====== ====== ====== * after preferred dividends
- ------------------------------------------------------------------------------- SOUTHERN CALIFORNIA GAS COMPANY SoCalGas recorded net income of $148 million and $167 million for the nine-month periods ended September 30, 2003 and 2002, respectively, and net income of $53 million and $56 million for the three-month periods ended September 30, 2003 and 2002, respectively. The decreases were primarily due to a $28 million after-tax charge for litigation and for losses associated with a long-term sublease of portions of its headquarters building, and the end of sharing of merger savings (which positively impacted earnings by $13 million for the nine-month period and $4 million for the three-month period in 2002). These factors were partially offset by the after-tax recognition of $29 million in GCIM awards in the third quarter of 2003. The non-recurring sublease losses pertain to pre-2003 transactions, but are charged against current operations because they are not material to annual financial statements. SAN DIEGO GAS & ELECTRIC SDG&E recorded net income of $206 million and $150 million for the nine-month periods ended September 30, 2003 and 2002, respectively, and net income of $120 million and $46 million for the three-month periods ended September 30, 2003 and 2002, respectively. The increases were primarily due to income of $65 million after-tax related to the approved settlement of intermediate-term purchase power contracts, higher earnings from PBR awards, and higher transportation and distribution revenue. These factors were partially offset by higher operating expenses including litigation charges in the third quarter of 2003, and the end of sharing of the merger savings (which positively impacted earnings by $6 million for the nine-month period and $2 million for the three-month period in 2002). Additionally, for the nine-month period, the increases were offset by the $25 million benefit from the favorable resolution of prior years' income-tax issues recorded in the second quarter of 2002. SEMPRA ENERGY TRADING SET recorded net income of $39 million and $73 million for the nine- month periods ended September 30, 2003 and 2002, respectively, and net income of $22 million and $10 million for the three-month periods ended September 30, 2003 and 2002, respectively. For purposes of comparison with the corresponding 2002 periods, net income for the nine months and three months ended September 30, 2003 would have been $70 million and $9 million, respectively, 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 $3 million related to operations for the nine months ended September 30, 2003, including a $13 million positive adjustment for the three months ended September 30, 2003. A summary of SET's net unrealized revenues for trading activities for the nine-month periods ended September 30, 2003 and 2002 follows: (Dollars in millions) 2003 2002 - ----------------------------------------------------------------- Balance at beginning of period $ 180 $ 405 Cumulative effect adjustment (48) -- Additions 833 355 Realized (552) (313) ------------------------------------ Balance at September 30 $ 413 $ 447 ==================================== The estimated fair values for SET's trading activities as of September 30, 2003, and the periods during which net unrealized revenues are expected to be realized, are (dollars in millions):
Fair Market Value at September 30, /--Scheduled Maturity (in months)--/ Source of fair value 2003 0-12 13-24 25-36 >36 - ------------------------------------------------------------------------- Prices actively quoted $ 290 $ 190 $ 68 $ 16 $ 16 Prices provided by other external sources (6) (5) (2) -- 1 Prices based on models and other valuation methods 19 6 3 -- 10 ------------------------------------------------ Over-the-counter (OTC) revenue (1) 303 191 69 16 27 Exchange contracts (2) 110 113 (5) (1) 3 ------------------------------------------------ Total $ 413 $ 304 $ 64 $ 15 $ 30 ================================================ (1) The present value of net unrealized revenues to be received 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. September 30, December 31, (Dollars in millions) 2003 2002 - ----------------------------------------------------------------- Counterparty credit quality* Commodity Exchanges $ 109 $ 49 AAA 4 69 AA 185 194 A 370 316 BBB 387 559 Below investment grade 374 504 --------------------------- Total $ 1,429 $ 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 $48 million and $60 million for the nine- month periods ended September 30, 2003 and 2002, respectively, and net income of $33 million and $29 million for the three-month periods ended September 30, 2003 and 2002, respectively. The decrease for the nine- month period was primarily due to the pricing structure of SER's contract with the DWR, increased interest expense due to borrowings related to newly constructed power plants, and start-up expenses related to the new power plants. SEMPRA ENERGY INTERNATIONAL SEI recorded a net loss of $7 million compared to net income of $30 million for the nine-month periods ended September 30, 2003 and 2002, respectively, and a net loss of $32 million compared to net income of $13 million for the three-month periods ended September 30, 2003 and 2002, respectively. The changes were primarily due to the charge recorded to write down the carrying value of assets at Frontier Energy, as previously discussed, partially offset by increased equity earnings from its subsidiaries and increased earnings from the Gasaducto Bajanorte pipeline. SEMPRA ENERGY SOLUTIONS SES recorded net income of $7 million and $11 million for the nine- month periods ended September 30, 2003 and 2002, respectively, and net income of $0.1 million and $5 million for the three-month periods ended September 30, 2003 and 2002, respectively. The changes were primarily due to reduced margins on retail commodity sales, caused by higher wholesale energy prices and increased competition among retail energy suppliers. SEMPRA ENERGY FINANCIAL SEF recorded net income of $32 million and $23 million for the nine- month periods ended September 30, 2003 and 2002, respectively, and net income of $13 million and $9 million for the three-month periods ended September 30, 2003 and 2002, respectively. The increases were due to increased Section 29 income tax credits in 2003. 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. PARENT AND OTHER Net losses for Parent and Other were $58 million and $71 million for the nine-month periods ended September 30, 2003 and 2002, respectively. For the three-month period ended September 30, 2003, net income was $2 million compared to a loss of $18 million in 2002. These changes were due to lower income tax expense as the result of a positive adjustment to reflect the company's consolidated effective tax rate. For the quarter, the lower income-tax impact was partially offset by the recognition of certain intercompany mark-to-market revenues which were initially deferred in previous years until sales to end users were completed in 2002. 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 utility 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 September 30, 2003, the company had $411 million in cash and $2.4 billion in unused, committed lines of credit available, of which $713 million was supporting commercial paper and variable-rate debt. On October 14, 2003, Sempra Energy completed a common stock offering of 16.5 million shares priced at $28 per common share resulting in net proceeds of $448 million. The proceeds were primarily used to pay off short-term debt. On July 10, 2003, the CPUC issued a decision authorizing SoCalGas to issue up to $715 million of additional long- term debt, of which not less than $500 million will be used for the retirement of 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. On October 17, 2003, SoCalGas issued $250 million of 5.45% first mortgage bonds due in April 2018. The proceeds will be used to replenish amounts previously expended to refund and retire indebtedness and for general corporate purposes. This issuance used up $33 million of the July 10, 2003 CPUC debt authorization. Management believes these amounts and cash flows from operations and new security issuances will be adequate to finance capital expenditure requirements, shareholder dividends, any new business acquisitions or start-ups, and other commitments. If cash flows from operations were reduced significantly and/or the company were 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 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 dividends to Sempra Energy. If SDG&E proceeds with its plans for a 555-megawatt generating facility in Escondido, California, the level of its dividends to Sempra Energy is expected to be significantly lower during the construction of the facility to enable SDG&E to increase its equity in preparation for the purchase of the completed facility. 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 $280 million at September 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. 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 generally expected to be a net provider of cash through reductions of consolidated income tax payments resulting from its investments in affordable housing and synthetic fuel. However, that was not true in 2003 and will not be true in the near term, while the company is in an alternative minimum tax position. The company expects 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. CASH FLOWS FROM OPERATING ACTIVITIES Net cash provided by operating activities totaled $923 million and $1.0 billion for the nine months ended September 30, 2003 and 2002, respectively. The change was attributable to 2003's decrease in overcollected balancing accounts, higher natural gas inventory and refunding of customers' deposits, partially offset by 2003's higher realization of net trading assets and lower compensation payments. During the third quarter of 2003, the company made pension plan contributions of $17.2 million for SDG&E and $1.3 million for SoCalGas for the 2003 plan year. CASH FLOWS FROM INVESTING ACTIVITIES Net cash used in investing activities totaled $887 million and $1.2 billion for the nine months ended September 30, 2003 and 2002, respectively. The change was attributable to lower capital expenditures for the TDM power plant and lower investments in U.S. Treasury obligations made in connection with the Mesquite synthetic lease in 2003, and a higher level of acquisition activity in 2002. 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 and other investments by the company's other businesses are estimated to be $450 million for the full year 2003, of which $275 million is for SER's power plant construction and other capital projects. In April 2003, Sempra Energy LNG Corp. completed its previously announced acquisition of the proposed Cameron LNG project from a subsidiary of Dynegy, Inc. Sempra Energy LNG Corp. has paid Dynegy $35 million for the transaction, which includes rights to the location, licensing and FERC approval of the project. Additional payments are contingent on meeting certain benchmarks and milestones and the performance of the project. The total cost of the project is expected to be approximately $700 million. The project could begin commercial operations in early 2007. FERC approval was granted on September 11, 2003. Other state and federal approvals required to commence construction are in progress. In connection with plans to develop Energia Costa Azul, a LNG receiving terminal in Baja California, about 50 miles south of San Diego, Mexico's national environmental agency issued an environmental permit in April 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, were granted in August 2003. The coastal zone use permit and the permit to construct marine facilities are pending and are expected to be received in the near future. Energia Costa Azul will bring natural gas into northwestern Mexico and the U.S. Southwest. The project is 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 $80 million and $7 million for the nine months ended September 30, 2003 and 2002, respectively. The change was attributable to reduced long-term borrowings in 2003 partly offset by a net increase in short-term debt in 2003. In January 2003, the company issued $400 million of 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. 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. On August 21, 2003, SoCalGas called its $125 million 7.5% first-mortgage bonds at a premium of 3.15%. In addition, during the nine months ended September 30, 2003, SEF repaid $36 million of debt incurred to acquire limited partnership interests and SDG&E repaid $48 million of rate-reduction bonds. Dividends paid on common stock amounted to $155 million and $154 million for the nine months ended September 30, 2003 and 2002, respectively. On October 14, 2003, Sempra Energy completed a common stock offering of 16.5 million shares priced at $28 per common share resulting in net proceeds of $448 million. The proceeds were used primarily to pay off short-term debt. On October 17, 2003, SoCalGas issued $250 million of 5.45% first- mortgage bonds due in April 2018. The proceeds will be used to replenish amounts previously expended to refund and retire indebtedness and for general corporate purposes. In August 2003, Global entered into two syndicated revolving credit agreements, permitting aggregate revolving credit borrowings of $1 billion, to replace an expiring $950 million revolving line. One agreement is a 364-day credit agreement permitting $500 million of revolving credit borrowings that may be converted into a one-year term loan upon the August 2004 expiration of the revolving credit period. The other agreement is a three-year credit agreement permitting $500 million of revolving credit borrowings until the expiration of the agreement in August 2006. As of September 30, 2003, a letter of credit for $18 million was outstanding under this facility. Borrowings under the agreements would be guaranteed by Sempra Energy and bear interest at rates varying with market rates and Sempra Energy's credit ratings. Both agreements require Sempra Energy to maintain a debt-to-total capitalization ratio (as identically defined in each agreement) of not to exceed 65%. CREDIT RATINGS On October 7, 2003, Standard & Poor's reduced Sempra Energy's corporate credit and senior unsecured debt ratings from A- to BBB+. It also reduced the corporate credit ratings of the California Utilities from A+ to A, senior unsecured debt ratings from A to A-, and preferred stock ratings from A- to BBB+. The California Utilities' prior ratings for senior secured debt were affirmed at A+. All ratings were issued with a stable outlook. On October 14, 2003 Fitch Ratings affirmed Sempra Energy's prior ratings for senior unsecured debt at A. Fitch also affirmed the senior secured debt ratings of the California Utilities at AA, senior unsecured debt ratings at AA-, and preferred stock ratings at A+. PE's preferred stock rating was lowered to A from A+. All ratings were issued with a stable outlook. Moody's prior ratings of Sempra Energy's unsecured debt remained unchanged at Baa1. The senior secured debt ratings of the California Utilities remained unchanged at A1, the senior unsecured debt ratings at A2, and preferred stock ratings at Baa1. All ratings maintained their prior stable outlook. 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, including LNG. 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 nine months ended September 30, 2003, the balance in the balancing account declined from $215 million to $156 million. Subsequent to the electric capacity shortages of 2000-2001, SDG&E's service territory 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 and transmission and 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 a new transmission interconnect by 2008 or as soon thereafter as practicable; and (4) provide new electric generation to address the reliability deficiency identified by SDG&E as beginning in 2005. 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 approximately 100 megawatts, and has filed a proposed plan at the CPUC for meeting these capacity requirements. SDG&E is currently 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. On October 7, 2003, SDG&E filed a motion for approval of its RFP results. See Note 3 of the notes to Consolidated Financial Statements for additional information regarding the RFP results. 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 company is in the process of addressing 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 is being addressed 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. The proposed 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. On September 29, 2003, the CPUC issued a ruling indicating that the proceeding will initially only consider implementation of the original December 2001 decision, but the Assigned Commissioner said he will informally look at the alternatives proposed by SoCalGas. The matter has been set for hearing and a CPUC decision is expected by January 2004. If the December 2001 decision is implemented, it is not expected to have a material effect on the California Utilities' earnings. 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. On September 18, 2003, the Commission suspended 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 will be combined with the annual affiliate audit and should be completed by the end of 2004. The scope of the audit will be broader than the annual affiliate audit. In addition to an evaluation of compliance with CPUC rules and requirements, this audit will assess the potential for conflicts between the interests of Sempra Energy and the interests of the California Utilities and their ratepayers, and examine whether business activities undertaken by the California Utilities and/or their holding company and affiliates pose potential problems or unjust or unreasonable impacts on utility customers. Cost of Service Filing As previously reported, the California Utilities have filed cost of service applications with the CPUC seeking rate increases designed to reflect forecasts of 2004 capital and operating costs. The California Utilities are requesting revenue increases of approximately $121 million. The ORA filed its prepared testimony in the applications on August 8, 2003, recommending rate decreases that would reduce annual revenues by $162 million from their current level. UCAN has proposed rates for SDG&E and TURN has proposed rates for SoCalGas that would reduce annual revenues by $88 million and $178 million, respectively, from their current level. Hearings are expected to conclude by the end of this month. The procedural schedule for the cost of service applications permits a decision as early as March 2004, and the California Utilities have filed a petition for interim rate relief for the period from January 1, 2004 until the effective date of the decision. On November 3, 2003, the CPUC ALJ released a Proposed Decision that would authorize the California Utilities to create a memorandum account as of January 1, 2004, to record the difference between existing rates and those that are later authorized in the Commission's final decision in this case. The difference would then be amortized in rates. The full Commission can vote on the Proposed Decision as soon as December 4, 2003. The California Utilities have also filed for continuation through 2004 of existing PBR mechanisms for service quality and safety that would otherwise expire at the end of 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. In 2002, merger savings to shareholders for the three-month and nine-month periods were $4 million and $13 million, respectively, at SoCalGas and $2 million and $6 million, respectively, at SDG&E. Sempra Energy Global Enterprises Electric-Generation Assets As discussed in "Cash Flows From Investing Activities" 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 before the end of this year. TDM, 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. 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. Except for Elk Hills, the plants' electricity 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 Cameron LNG project, 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 Argentine 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, 144, 148, 149 and 150, Interpretations 45 and 46, and EITF 02-3. See discussion in Note 2 of the notes to Consolidated Financial Statements. Pronouncements that have or are likely to have a material effect on future earnings are described below. In October 2002, the EITF released Issue 02-3 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 certain inventory and 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 at the same time, even though no economic loss exists. For SET, its earnings for the nine months ended September 30, 2003 of $39 million were negatively impacted by $28 million of the cumulative- effect adjustment and an additional $3 million related to operations during the nine-month period to reflect the ongoing effects of rescission of Issue 98-10. SES's nine months ended September 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. SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets": In August 2001, the FASB issued SFAS 144, which supercedes a prior accounting standard related to the accounting for the impairment or disposal of long-lived assets. Under SFAS 144 the company is required to reduce the carrying value of assets to fair value and recognize asset impairment charges in the event that the carrying value of such assets exceeds the estimated future undiscounted cash flows attributable to such assets. During the third quarter of 2003, the Company recorded a $77 million non-cash impairment charge ($47 million after-tax) to write down the carrying value of the assets of Frontier Energy, a small North Carolina utility subsidiary, as a result of reductions in actual and previously anticipated sales of natural gas by this utility. 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. During October 2003, the FASB deferred the implementation date for pre-existing VIEs until the end of the first interim or annual period ending after December 15, 2003. Sempra Energy has identified two variable interest entities for which it is the primary beneficiary. One VIE is related to the Mesquite Power Plant and the other is related to an investment in an unconsolidated subsidiary, Atlantic Electric & Gas Limited. Accordingly, if the FASB's deliberations during the deferral period do not result in the exclusion of these entities from FIN 46's definitions, Sempra Energy will consolidate these entities in its financial statements during the fourth quarter of 2003. This is estimated to increase total assets and total liabilities by approximately $700 million. The company expects implementation to result in an after-tax charge for the cumulative effect from the change in accounting principle of approximately $17 million and no change to operating income. 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 September 30, 2003, and the average VaR for the nine-month period ended September 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 September 30, 2003 $ 5.52 $ 7.79 Average for the nine months ended September 30, 2003 $ 7.24 $10.20 As of September 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 as of the date of this quarterly 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 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits Exhibit 12 - Computation of ratios 12.1 Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends. Exhibit 31 -- Section 302 Certifications 31.1 Statement of Registrant's Chief Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934. 31.2 Statement of Registrant's Chief Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934. Exhibit 32 -- Section 906 Certifications 32.1 Statement of Registrant's Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350. 32.2 Statement of Registrant's Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350. (b) Reports on Form 8-K The following reports on Form 8-K were filed after June 30, 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. Current Report on Form 8-K filed September 2, 2003, announcing CPUC approval of certain performance rewards and the CPUC's denial of rehearing requested by opponents of an approved settlement agreement with SDG&E. Current Report on Form 8-K filed October 9, 2003, announcing the execution of an underwriting agreement for the issuance and sale of common stock and reporting several recent developments related to credit rating changes, litigation, and other events. Current Report on Form 8-K filed November 6, 2003, filing as an exhibit Sempra Energy's press release of November 6, 2003, giving the financial results for the three months ended September 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: November 6, 2003 By: /s/ F. H. Ault ---------------------------- F. H. Ault Sr. Vice President and Controller


                                                                         EXHIBIT 12.1
                                      SEMPRA ENERGY
               COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES
                             AND PREFERRED STOCK DIVIDENDS
                                 (Dollars in millions)
Nine months ended September 30, 1998 1999 2000 2001 2002 2003 -------- -------- -------- -------- -------- --------- Fixed Charges and Preferred Stock Dividends: Interest $ 210 $ 233 $ 308 $ 358 $ 350 $ 260 Interest portion of annual rentals 20 10 8 6 6 4 Preferred dividends of subsidiaries (1) 18 16 18 16 15 11 -------- -------- -------- -------- -------- --------- Combined Fixed Charges and Preferred Stock Dividends for Purpose of Ratio $ 248 $ 259 $ 334 $ 380 $ 371 $ 275 ======== ======== ======== ======== ======== ========= Earnings: Pretax income from continuing operations $ 432 $ 573 $ 699 $ 731 $ 721 $ 553 Total Fixed Charges (from above) 248 259 334 380 371 275 Less: Interest capitalized 1 1 3 11 29 22 Equity income (loss) of unconsolidated subsidiaries and joint ventures - - 62 12 (55) 17 -------- -------- -------- -------- -------- --------- Total Earnings for Purpose of Ratio $ 679 $ 831 $ 968 $1,088 $1,118 $ 789 ======== ======== ======== ======== ======== ========= Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends 2.74 3.21 2.90 2.86 3.01 2.87 ======== ======== ======== ======== ======== ========= (1) In computing this ratio, "Preferred dividends of subsidiaries" represents the before-tax earnings necessary to pay such dividends, computed at the effective tax rates for the applicable periods.
                                                  EXHIBIT 31.1
                       CERTIFICATION

I, Stephen L. Baum, certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q of Sempra Energy;

2.	Based on my knowledge, this Quarterly Report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect
to the period covered by this Quarterly Report;

3.	Based on my knowledge, the financial statements and other financial
information included in this Quarterly Report fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented
in this Quarterly Report;

4.	The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the
registrant and we have:

a)	Designed such disclosure controls and procedures, or caused
such disclosure controls and procedures to be designed under
our supervision, to ensure that material information relating
to the registrant, including its consolidated subsidiaries, is
made known to us by others within those entities, particularly
during the period in which this Quarterly Report is being
prepared;

b)	Evaluated the effectiveness of the registrant's disclosure
controls and procedures and presented in this Quarterly Report
our conclusions about the effectiveness of the disclosure
controls and procedures, as of the end of the period covered
by this Quarterly Report, based on such evaluation; and

c)	Disclosed in this report any change in the registrant's
internal control over financial reporting that occurred during
the registrant's most recent fiscal quarter that has
materially affected, or is reasonably likely to materially
affect, the registrant's internal control over financial
reporting;

5.	The registrant's other certifying officer and I have disclosed,
based on our most recent evaluation of internal control over
financial reporting, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing
the equivalent function):

a)	All significant deficiencies and material weaknesses in the
design or operation of internal controls over financial
reporting which are reasonably likely to adversely affect the
registrant's ability to record, process, summarize and report
financial information; and

b)	Any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls over financial reporting.


November 6, 2003

/S/ STEPHEN L. BAUM
Stephen L. Baum
Chief Executive Officer



                                                  EXHIBIT 31.2
                       CERTIFICATION

I, Neal E. Schmale, certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q of Sempra
Energy;

2.	Based on my knowledge, this Quarterly Report does not contain any
untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading
with respect to the period covered by this Quarterly Report;

3.	Based on my knowledge, the financial statements and other financial
information included in this Quarterly Report fairly present in all
material respects the financial condition, results of operations
and cash flows of the registrant as of, and for, the periods
presented in this Quarterly Report;

4.	The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the
registrant and we have:

a)	Designed such disclosure controls and procedures, or caused
such disclosure controls and procedures to be designed under
our supervision, to ensure that material information relating
to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities,
particularly during the period in which this Quarterly Report
is being prepared;

b)	Evaluated the effectiveness of the registrant's disclosure
controls and procedures and presented in this Quarterly
Report our conclusions about the effectiveness of the
disclosure controls and procedures, as of the end of the
period covered by this Quarterly Report, based on such
evaluation; and

c)	Disclosed in this report any change in the registrant's
internal control over financial reporting that occurred
during the registrant's most recent fiscal quarter that has
materially affected, or is reasonably likely to materially
affect, the registrant's internal control over financial
reporting;

5.	The registrant's other certifying officer and I have disclosed,
based on our most recent evaluation of internal control over
financial reporting, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing
the equivalent function):

a)	All significant deficiencies and material weaknesses in the
design or operation of internal controls over financial
reporting which are reasonably likely to adversely affect the
registrant's ability to record, process, summarize and report
financial information; and

b)	Any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls over financial reporting.


November 6, 2003

/S/ NEAL E. SCHMALE
Neal E. Schmale
Chief Financial Officer


                                                        Exhibit 32.1


Statement of Chief Executive Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the
Sarbanes-Oxley Act of 2002, the undersigned Chief Executive Officer of
Sempra Energy (the "Company") certifies that:

(i)	the Quarterly Report on Form 10-Q of the Company filed with
the Securities and Exchange Commission for the quarterly
period ended September 30, 2003 (the "Quarterly Report")
fully complies with the requirements of Section 13(a) or
Section 15(d), as applicable, of the Securities Exchange
Act of 1934, as amended; and

(ii)	the information contained in the Quarterly Report fairly
presents, in all material respects, the financial condition
and results of operations of the Company.



November 6, 2003
                                            /S/ STEPHEN L. BAUM
                                           ______________________
                                            Stephen L. Baum
                                            Chief Executive Officer



                                                     Exhibit 32.2

Statement of Chief Financial Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the
Sarbanes-Oxley Act of 2002, the undersigned Chief Financial Officer of
Sempra Energy (the "Company") certifies that:

(i)	the Quarterly Report on Form 10-Q of the Company filed with
the Securities and Exchange Commission for the quarterly
period ended September 30, 2003 (the "Quarterly Report")
fully complies with the requirements of Section 13(a) or
Section 15(d), as applicable, of the Securities Exchange
Act of 1934, as amended; and

(ii)	the information contained in the Quarterly Report fairly
presents, in all material respects, the financial condition
and results of operations of the Company.



November 6, 2003
                                           /S/ NEAL E. SCHMALE
                                          ______________________
                                           Neal E. Schmale
                                           Chief Financial Officer