Washington, D.C.  20549  
                               FORM 8-K  
                            CURRENT REPORT  
     Pursuant to Section 13 or 15(d) of the Securities Exchange Act  
                                of 1934  
Date of Report   
(Date of earliest event reported):   May 5, 1999
                          SEMPRA ENERGY
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       (Exact name of registrant as specified in its charter)  
CALIFORNIA                      1-14201                    33-0732627  
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(State of incorporation      (Commission             (I.R.S. Employer  
or organization)             File Number)          Identification No.  
101 ASH STREET, SAN DIEGO, CALIFORNIA                           92101  
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(Address of principal executive offices)                   (Zip Code)  
                                                       (619) 696-2034  
Registrant's telephone number, including area code-------------------  
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   (Former name or former address, if changed since last report.)  

                                   FORM 8-K  
Item 5.  Other Events  

Sempra Energy Holdings (Holdings) will be filing a shelf 
registration of debt securities to be offered on a delayed or 
continuous basis pursuant to Rule 415 under the Securities Act 
of 1933. Because the debt securities will be guaranteed by 
Sempra Energy, of which Holdings is a wholly owned subsidiary, 
summarized financial information of Holdings is provided 
herein. Consolidated financial information for Sempra Energy, 
as previously filed in its 1998 Form 10-K is also presented 
herein, because it is referred to in the accompanying 
independent auditors' report which also refers to the 
summarized financial information of Holdings.


To the Board of Directors and Shareholders of Sempra Energy:

We have audited the accompanying consolidated balance sheets of 
Sempra Energy and subsidiaries (the "company") as of December 31, 
1998 and 1997, and the related statements of consolidated income, 
changes in shareholders' equity, and cash flows for each of the 
three years in the period ended December 31, 1998. These financial 
statements are the responsibility of the company's management. Our 
responsibility is to express an opinion on these financial 
statements based on our audits.
     We conducted our audits in accordance with generally accepted 
auditing standards. Those standards require that we plan and 
perform the audit to obtain reasonable assurance about whether the 
financial statements are free of material misstatement. An audit 
includes examining, on a test basis, evidence supporting the 
amounts and disclosures in the financial statements. An audit also 
includes assessing the accounting principles used and significant 
estimates made by management, as well as evaluating the overall 
financial statement presentation. We believe that our audits 
provide a reasonable basis for our opinion.
     In our opinion, such consolidated financial statements present 
fairly, in all material respects, the financial position of Sempra 
Energy and subsidiaries as of December 31, 1998, and 1997, and the 
results of their operations and their cash flows for each of the 
three years in the period ended December 31, 1998, in conformity 
with generally accepted accounting principles.

/s/ Deloitte & Touche LLP

San Diego, California
January 27, 1999, except for Note 16 as to which the date is 
February 22, 1999

Statements of Consolidated Income
Years Ended December 31, ------------------------------- (Dollars in millions, except per share amounts) 1998 1997 1996 - ----------------------------------------------------------------------------------- Revenues and Other Income Utility revenues: Natural gas $ 2,772 $ 2,964 $ 2,710 Electric 1,865 1,769 1,591 PX/ISO power 500 -- -- Other operating revenues 344 336 195 Other income 44 58 28 -------- -------- -------- Total 5,525 5,127 4,524 -------- -------- -------- Expenses Cost of natural gas distributed 954 1,168 958 PX/ISO power 468 -- -- Purchased power 292 441 311 Electric fuel 177 164 134 Operating expenses 1,872 1,615 1,405 Depreciation and amortization 929 604 587 Franchise payments and other taxes 182 178 180 Preferred dividends of subsidiaries 12 18 22 -------- -------- -------- Total 4,886 4,188 3,597 -------- -------- -------- Income Before Interest and Income Taxes 639 939 927 Interest 207 206 200 -------- -------- -------- Income Before Income Taxes 432 733 727 Income taxes 138 301 300 -------- -------- -------- Net Income $ 294 $ 432 $ 427 ======== ======== ======== Net Income Per Share of Common Stock (Basic) $ 1.24 $ 1.83 $ 1.77 ======== ======== ======== Net Income Per Share of Common Stock (Diluted) $ 1.24 $ 1.82 $ 1.77 ======== ======== ======== Common Dividends Declared Per Share $ 1.56 $ 1.27 $ 1.24 ======== ======== ======== See notes to Consolidated Financial Statements.
SEMPRA ENERGY Consolidated Balance Sheets
December 31, ---------------- (Dollars in millions) 1998 1997 - -------------------------------------------------------------------- Assets Current assets: Cash and cash equivalents $ 424 $ 814 Accounts receivable - trade 586 633 Accounts and notes receivable - other 159 202 Deferred income taxes 93 15 Energy trading assets 906 587 Inventories 151 111 Regulatory balancing accounts - net -- 297 Other 139 102 ------- ------- Total current assets 2,458 2,761 ------- ------- Investments and other assets: Regulatory assets 980 1,186 Nuclear-decommissioning trusts 494 399 Investments 548 429 Other assets 535 439 ------- ------- Total investments and other assets 2,557 2,453 ------- ------- Property, plant and equipment: Property, plant and equipment 11,235 10,902 Less accumulated depreciation and amortization (5,794) (5,360) ------- ------- Total property, plant and equipment - net 5,441 5,542 ------- ------- Total assets $ 10,456 $ 10,756 ======= ======= See notes to Consolidated Financial Statements.
SEMPRA ENERGY Consolidated Balance Sheets
December 31, ----------------- (Dollars in millions) 1998 1997 - ------------------------------------------------------------------ Liabilities Current liabilities: Short-term debt $ 43 $ 354 Accounts payable - trade 702 625 Accrued income taxes 27 5 Energy trading liabilities 805 557 Dividends and interest payable 168 121 Regulatory balancing accounts - net 120 -- Long-term debt due within one year 330 270 Other 271 279 ------- ------- Total current liabilities 2,466 2,211 ------- ------- Long-term debt: Long-term debt 2,795 3,045 Debt of Employee Stock Ownership Plan -- 130 ------- ------- Total long-term debt 2,795 3,175 ------- ------- Deferred credits and other liabilities: Customer advances for construction 72 72 Post-retirement benefits other than pensions 240 248 Deferred income taxes 634 741 Deferred investment tax credits 147 155 Deferred credits and other liabilities 985 916 ------- ------- Total deferred credits and other liabilities 2,078 2,132 ------- ------- Preferred stock of subsidiaries 204 279 ------- ------- Commitments and contingent liabilities (Note 13) Shareholders' Equity Common stock 1,883 1,849 Retained earnings 1,075 1,157 Less deferred compensation relating to Employee Stock Ownership Plan (45) (47) ------- ------- Total shareholders' equity 2,913 2,959 ------- ------- Total liabilities and shareholders' equity $ 10,456 $ 10,756 ======= ======= See notes to Consolidated Financial Statements.
SEMPRA ENERGY Statements of Consolidated Cash Flows
Years Ended December 31 --------------------------------- (Dollars in millions) 1998 1997 1996 - ------------------------------------------------------------------------------------------ CASH FLOWS FROM OPERATING ACTIVITIES Net Income $ 294 $ 432 $ 427 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 929 604 587 Deferred income taxes and investment tax credits (199) (16) 26 Other - net (180) 62 56 Net changes in other working capital components 479 (164) 68 ---------- --------- --------- Net cash provided by operating activities 1,323 918 1,164 ---------- --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES Expenditures for property, plant and equipment (438) (397) (413) Acquisitions of subsidiaries (191) (206) (50) Contributions to decommissioning trusts (22) (22) (22) Other (28) 23 (29) --------- ----------- ---------- Net cash used in investing activities (679) (602) (514) --------- ----------- ---------- CASH FLOWS FROM FINANCING ACTIVITIES Common stock dividends (325) (301) (300) Sale of common stock 34 17 8 Repurchase of common stock (1) (122) (24) Redemption of preferred stock (75) -- (225) Issuances of other long-term debt 75 140 304 Issuance of rate-reduction bonds -- 658 -- Payment on long-term debt (431) (416) (459) Increase (decrease) in short-term debt - net (311) 92 29 --------- ----------- ---------- Net cash provided by (used in) financing activities (1,034) 68 (667) --------- ----------- ---------- Increase (Decrease) in Cash and Cash Equivalents (390) 384 (17) Cash and Cash Equivalents, January 1 814 430 447 --------- ----------- ---------- Cash and Cash Equivalents, December 31 $ 424 $ 814 $ 430 ========= =========== ========== See notes to Consolidated Financial Statements.
SEMPRA ENERGY Statements of Consolidated Cash Flows
Years Ended December 31 --------------------------------- (Dollars in millions) 1998 1997 1996 - ------------------------------------------------------------------------------------------ CHANGES IN OTHER WORKING CAPITAL COMPONENTS (Excluding cash and cash equivalents, short-term debt and long-term debt due within one year) Accounts and notes receivable $ 90 $ (129) $ (58) Net trading assets (71) -- -- Inventories (40) (2) 32 Regulatory balancing accounts 417 48 9 Other current assets (26) 41 40 Accounts payable and other current liabilities 109 (122) 45 -------- -------- -------- Net change in other working capital components $ 479 $ (164) $ 68 ======== ======== ======== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Cash paid during the year for: Interest (net of amounts capitalized) $ 211 $ 193 $ 205 Income taxes (net of refunds) $ 366 $ 274 $ 268 SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES Acquisition of Sempra Energy Trading: Assets acquired $ -- $ 609 $ -- Cash paid -- (225) -- ---------- ----------- --------- Liabilities assumed $ -- $ 384 $ -- ========== =========== ========= Liabilities assumed for real estate investments $ 36 $ 126 $ 97 ========== =========== ========= Nonutility electric generation assets sold: Book value of assets sold $ -- $ 77 $ -- Cash received -- (20) -- Loss on sale -- (6) -- ---------- ----------- --------- Note receivable obtained $ -- $ 51 $ -- ========== =========== ========= See notes to Consolidated Financial Statements.
SEMPRA ENERGY STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY For the years ended December 31, 1998, 1997, 1996 (Dollars in millions)
Deferred Compensation Total Common Retained Relating Shareholders' Stock Earnings to ESOP Equity - ------------------------------------------------------------------------------------ Balance at December 31, 1995 $ 1,968 $ 899 $ (52) $ 2,815 Net income 427 427 Common stock dividends declared (300) (300) Sale of common stock 8 8 Repurchase of common stock (24) (24) Common stock released from ESOP 3 3 Long-term incentive plan 1 1 - ------------------------------------------------------------------------------------ Balance at December 31, 1996 1,953 1,026 (49) 2,930 Net income 432 432 Common stock dividends declared (301) (301) Sale of common stock 17 17 Repurchase of common stock (122) (122) Common stock released from ESOP 2 2 Long-term incentive plan 1 1 - ------------------------------------------------------------------------------------ Balance at December 31, 1997 1,849 1,157 (47) 2,959 Net income 294 294 Common stock dividends declared (376) (376) Sale of common stock 34 34 Repurchase of common stock (1) (1) Common stock released from ESOP 2 2 Long-term incentive plan 1 1 - ------------------------------------------------------------------------------------ Balance at December 31, 1998 $ 1,883 $1,075 $ (45) $ 2,913 ==================================================================================== See notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1 BUSINESS COMBINATION On June 26, 1998, Enova Corporation (Enova) and Pacific Enterprises (PE) combined into a new company named Sempra Energy (the company). As a result of the combination, (i) each outstanding share of common stock of Enova was converted into one share of common stock of Sempra Energy, (ii) each outstanding share of common stock of PE was converted into 1.5038 shares of common stock of Sempra Energy and (iii) the preferred stock and preference stock of Enova's principal subsidiary, San Diego Gas & Electric Company (SDG&E); PE; and PE's principal subsidiary, Southern California Gas Company (SoCalGas) remained outstanding. The combination was approved by the shareholders of both companies on March 11, 1997, and was a tax-free transaction. As required by the March 1998 decision of the California Public Utilities Commission (CPUC) approving the business combination, SDG&E has entered into agreements to sell its fossil- fueled generation units. The sales are subject to regulatory approvals and are expected to close during the first half of 1999. Additional information concerning the sale of SDG&E's power plants is provided in Note 14. In addition, SoCalGas has sold its options to purchase the California portions of the Kern River and Mojave Pipeline natural gas-transmission facilities. The Federal Energy Regulatory Commission's (FERC) approval of the combination includes conditions that the combined company will not unfairly use any potential market power regarding natural gas transportation to fossil-fueled electric-generation plants. The FERC also specifically noted that the divestiture of SDG&E's fossil-fueled generation plants would eliminate any concerns about vertical market power arising from transactions between SDG&E and SoCalGas. The Consolidated Financial Statements are those of the company and its subsidiaries and give effect to the business combination using the pooling-of-interests method and, therefore, are presented as if the companies were combined during all periods included therein. The per-share data shown on the Statements Of Consolidated Income reflect the conversion of Enova common stock and of PE common stock into Sempra Energy common stock as described above. All significant intercompany transactions, including SoCalGas' sales of natural gas transportation and storage to SDG&E, have been eliminated. These sales amounted to approximately $60 million in each of the years presented. The results of operations for PE and Enova as reported as separate companies through June 30, 1998, are as follows: - --------------------------------------------------------------- Six months ended June 30, (Dollars in millions) 1998 1997 1996 - --------------------------------------------------------------- PACIFIC ENTERPRISES Revenue and Other Income $1,263 $2,777 $2,588 Net Income $ 50 $ 180 $ 196 ENOVA Revenue and Other Income $1,299 $2,224 $1,996 Net Income $ 68 $ 252 $ 231 - --------------------------------------------------------------- 2 SIGNIFICANT ACCOUNTING POLICIES Property, Plant and Equipment This primarily represents the buildings, equipment and other facilities used by SDG&E and SoCalGas to provide natural gas and electric utility service. The cost of utility plant includes labor, materials, contract services and related items, and an allowance for funds used during construction. The cost of retired depreciable utility plant, plus removal costs minus salvage value, is charged to accumulated depreciation. Information regarding electric- industry restructuring and its effect on utility plant is included in Note 14. Utility plant balances by major functional categories at December 31, 1998, are: natural gas operations $7.0 billion, electric distribution $2.4 billion, electric transmission $0.7 billion, electric generation $0.6 billion and other electric $0.3 billion. The corresponding amounts at December 31, 1997, were essentially the same. Accumulated depreciation and decommissioning of natural gas and electric utility plant in service at December 31, 1998, are $3.5 billion and $2.2 billion, respectively, and at December 31, 1997, were $3.3 billion and $2.0 billion, respectively. Depreciation expense is based on the straight-line method over the useful lives of the assets or a shorter period prescribed by the CPUC. The provisions for depreciation as a percentage of average depreciable utility plant (by major functional categories) in 1998, 1997, and 1996, respectively are: natural gas operations 4.32, 4.31, 4.35, electric generation 6.49, 5.60, 5.60, electric distribution 4.49, 4.39, 4.38, electric transmission 3.31, 3.28, 3.25, and other electric 6.29, 6.02, 5.95. The increase for electric generation in 1998 reflects the accelerated recovery of generation facilities. See Note 14 for additional discussion of generation facilities and industry restructuring. Inventories Included in inventories at December 31, 1998, are $61 million of utility materials and supplies ($56 million in 1997), and $78 million of natural gas and fuel oil ($47 million in 1997). Materials and supplies are generally valued at the lower of average cost or market; fuel oil and natural gas are valued by the last-in first-out method. Trading Instruments Trading assets and trading liabilities are recorded on a trade-date basis at fair value and include option premiums paid and received, and unrealized gains and losses from exchange-traded futures and options, over the counter (OTC) swaps, forwards, and options. Unrealized gains and losses on OTC transactions reflect amounts which would be received from or paid to a third party upon settlement of the contracts. Unrealized gains and losses on OTC transactions are reported separately as assets and liabilities unless a legal right of setoff exists under a master netting arrangement enforceable by law. Revenues are recognized on a trade- date basis and include realized gains and losses, and the net change in unrealized gains and losses. Futures and exchange-traded option transactions are recorded as contractual commitments on a trade-date basis and are carried at fair value based on closing exchange quotations. Commodity swaps and forward transactions are accounted for as contractual commitments on a trade-date basis and are carried at fair value derived from dealer quotations and underlying commodity-exchange quotations. OTC options are carried at fair value based on the use of valuation models that utilize, among other things, current interest, commodity and volatility rates, as applicable. For long- dated forward transactions, where there are no dealer or exchange quotations, fair values are derived using internally developed valuation methodologies based on available market information. Where market rates are not quoted, current interest, commodity and volatility rates are estimated by reference to current market levels. Given the nature, size and timing of transactions, estimated values may differ from realized values. Changes in the fair value are recorded currently in income. Effects of Regulation SDG&E and SoCalGas accounting policies conform with generally accepted accounting principles for regulated enterprises and reflect the policies of the CPUC and the FERC. The company's interstate natural gas transmission subsidiary follows accounting policies authorized by the FERC. SDG&E and SoCalGas have been preparing their financial statements in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," under which a regulated utility may record a regulatory asset if it is probable that, through the ratemaking process, the utility will recover that asset from customers. Regulatory liabilities represent future reductions in rates for amounts due to customers. To the extent that portions of the utility operations were no longer subject to SFAS No. 71, or recovery was no longer probable as a result of changes in regulation or their competitive position, the related regulatory assets and liabilities would be written off. In addition, SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," affects utility plant and regulatory assets such that a loss must be recognized whenever a regulator excludes all or part of an asset's cost from rate base. As discussed in Note 14, California enacted a law restructuring the electric-utility industry. The law adopts the December 1995 CPUC policy decision, and allows California electric utilities the opportunity to recover existing utility plant and regulatory assets over a transition period that ends in 2001. In 1997, SDG&E ceased the application of SFAS No. 71 with respect to its electric- generation business. The application of SFAS No. 121 continues to be evaluated as industry restructuring progresses. Additional information concerning regulatory assets and liabilities is described below in "Revenues and Regulatory Balancing Accounts" and in Note 14. Revenues and Regulatory Balancing Accounts Revenues from utility customers consist of deliveries to customers and the changes in regulatory balancing accounts. The amounts included in regulatory balancing accounts at December 31, 1998, represent a $129 million net payable for SoCalGas combined with a $9 million net receivable for SDG&E. The corresponding amounts at December 31, 1997 were $355 million net receivable and $58 million net payable for SoCalGas and SDG&E, respectively. Previously, earnings fluctuations from changes in the costs of fuel oil, purchased energy and natural gas, and consumption levels for electricity and the majority of natural gas were eliminated by balancing accounts authorized by the CPUC. This is still the case for most natural gas operations. However, as a result of California's electric-restructuring law, overcollections recorded in SDG&E's Energy Cost Adjustment Clause and Electric Revenue Adjustment Mechanism balancing accounts were transferred to the Interim Transition Cost Balancing Account, which is being applied to transition cost recovery, and fluctuations in costs and consumption levels can affect earnings from electric operations. Additional information on electric-industry restructuring is included in Note 14. Regulatory Assets Regulatory assets include San Onofre Nuclear Generating Station (SONGS), unrecovered premium on early retirement of debt, post- retirement benefit costs, deferred income taxes recoverable in rates and other regulatory-related expenditures that the utilities expect to recover in future rates. See Note 14 for additional information. Nuclear-Decommissioning Liability Deferred credits and other liabilities at December 31, 1998, include $146 million ($117 million in 1997) of accumulated decommissioning costs associated with SDG&E's SONGS Unit 1, which was permanently shut down in 1992. Additional information on SONGS Unit 1 decommissioning costs is included in Note 6. The corresponding liability for Units 2 and 3 is included in accumulated depreciation and amortization. Comprehensive Income In 1998, the company adopted SFAS No. 130, "Reporting Comprehensive Income." This statement requires reporting of comprehensive income and its components (revenues, expenses, gains and losses) in any complete presentation of general-purpose financial statements. Comprehensive income describes all changes, except those resulting from investments by owners and distributions to owners, in the equity of a business enterprise from transactions and other events including, as applicable, foreign-currency items, minimum pension liability adjustments and unrealized gains and losses on certain investments in debt and equity securities. Comprehensive income was equal to net income for the years ended December 31, 1998, 1997, and 1996. Quasi-Reorganization In 1993, PE completed a strategic plan to refocus on its natural gas utility and related businesses. The strategy included the divestiture of its merchandising operations and all of its oil and gas exploration and production business. In connection with the divestitures, PE effected a quasi-reorganization for financial reporting purposes, effective December 31, 1992. Certain of the liabilities established in connection with discontinued operations and the quasi-reorganization will be resolved in future years. Management believes the provisions previously established for these matters are adequate at December 31, 1998. Use of Estimates in the Preparation of the Financial Statements The preparation of the consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Statements of Consolidated Cash Flows Cash equivalents are highly liquid investments with original maturities of three months or less, or investments that are readily convertible to cash. Basis of Presentation Certain prior-year amounts have been reclassified from the predecessor companies' classifications to conform to the format of these financial statements. New Accounting Standard In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 133 "Accounting for Derivative Instruments and Hedging Activities." This statement, which is effective January 1, 2000, requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position, measure those instruments at fair value and recognize changes in the fair value of derivatives in earnings in the period of change unless the derivative qualifies as an effective hedge that offsets certain exposures. The effect of this standard on the company's Consolidated Financial Statements has not yet been determined. 3 ACQUISITIONS AND JOINT VENTURES Sempra Energy Trading In December 1997, PE and Enova jointly acquired Sempra Energy Trading (SET) for $225 million. SET is a wholesale-energy trading company based in Stamford, Connecticut. It participates in marketing and trading physical and financial energy products, including natural gas, power, crude oil and associated commodities. In July 1998, SET purchased CNG Energy Services Corporation, a subsidiary of Pittsburgh-based Consolidated Natural Gas Company, for $36 million. The acquisition expands SET's business volume by adding large, commodity-trading contracts with local distribution companies, municipalities and major industrial corporations in the eastern United States. Sempra Energy Resources In December 1997, Sempra Energy Resources (SER) in partnership with Reliant Energy Power Generation, formed El Dorado Energy. In April 1998, El Dorado Energy began construction on a 480-megawatt power plant near Boulder City, Nevada. SER invested $2.3 million in 1997 and $19.7 million in 1998 on this $263-million project. In October 1998, El Dorado Energy obtained a $158-million senior secured credit facility, which entails both construction and 15-year term financing for the project. This financing represents approximately 60 percent of estimated total project costs. Sempra Energy Utility Ventures In September 1997, Sempra Energy Utility Ventures (SEUV) formed a joint venture with Bangor Hydro to build, own and operate a $40- million natural gas distribution system in Bangor, Maine. Construction began in June 1998. The new Bangor Gas Company expects to begin deliveries in the fourth quarter of 1999. In December 1997, SEUV formed Frontier Energy with Frontier Utilities of North Carolina to build and operate a $55-million natural gas distribution system in North Carolina. Natural gas delivery began in December 1998. Subsequent to December 31, 1998, SEUV purchased Frontier Utilities' interest and acquired 100 percent ownership of the system. Sempra Energy Solutions In January 1998, Sempra Energy Solutions completed the acquisition of CES/Way International, a national leader in energy-service performance contracting headquartered in Houston, Texas. CES/Way provides energy-efficiency services, including energy audits, engineering design, project management, construction, financing and contract maintenance. In May 1997, Sempra Energy Solutions entered into a joint venture agreement with Conectiv Thermal Systems, Inc. (formerly Atlantic Thermal System, Inc.) to form Atlantic-Pacific Las Vegas, with each receiving a 50-percent interest. Atlantic-Pacific Las Vegas provides integrated energy-management services to commercial and industrial customers, including the construction of facilities. In May 1997, Atlantic-Pacific Las Vegas entered into an energy- services agreement with three other parties to finance, own, operate and maintain an integrated thermal-energy production facility at the site of the future Venetian Casino Resort in Las Vegas. Construction costs incurred to date are $48 million. A second joint venture agreement was entered into with Conectiv Thermal Systems to form Atlantic-Pacific Glendale in August 1997, with each receiving a 50-percent interest. Atlantic- Pacific Glendale entered into an integrated energy-management services agreement with Dreamworks Animation, LLC to develop, manage and finance the construction and operation of a central chiller plant, emergency power generators and chilled-water distribution and circulation system at Dreamworks' Glendale facilities. The cost of the project, completed in May 1998, was $7 million. International Natural Gas Projects Sempra Energy International (SEI) is a wholly owned subsidiary of Sempra Energy. Sempra Energy International and Proxima Gas S.A. de C.V., partners in the Mexican companies Distribuidora de Gas Natural (DGN) de Mexicali and Distribuidora de Gas Natural de Chihuahua, are the licensees to build and operate natural gas distribution systems in Mexicali and Chihuahua. DGN-Mexicali will invest up to $25 million during the first five years of the 30-year license period. DGN-Chihuahua will invest up to $50 million over the first five years of operation. DGN-Mexicali and DGN-Chihuahua assumed ownership of natural gas distribution facilities during the third quarter of 1997. SEI owns interests of 60 and 95 percent in the DGN-Mexicali and DGN-Chihuahua projects, respectively. In August 1998, SEI was awarded a 10-year agreement by the Mexican Federal Electric Commission to provide a complete energy-supply package for a power plant in Rosarito, Baja California. The contract includes provisions for delivery of up to 300 million cubic feet per day of natural gas, transportation services in the U.S. and construction of a 23-mile pipeline from the U.S.-Mexico border to the plant. The pipeline is expected to cost approximately $35 million and take a year to build. Delivery of natural gas is expected to commence in December 1999. SEI also has interests in Argentina and Uruguay. In March 1998, SEI increased its existing investment in two Argentine natural gas utility holding companies (Sodigas Pampeana S.A. and Sodigas Sur S.A.) from 12.5 percent to 21.5 percent by purchasing an additional interest for $40 million. 4 SHORT-TERM BORROWINGS PE has a $300 million multi-year credit agreement. SoCalGas has an additional $400 million multi-year credit agreement. These agreements expire in 2001 and bear interest at various rates based on market rates and the companies' credit ratings. SoCalGas' lines of credit are available to support commercial paper. At December 31, 1998, PE had $43 million of bank loans under the credit agreement outstanding, due and paid in January 1999. SoCalGas' bank line of credit was unused. At December 31, 1997, both bank lines of credit were unused. SDG&E has $30 million of bank lines available to support commercial paper and $265 million of bank lines available to support variable-rate, long-term debt. The credit agreements expire at varying dates from 1999 through 2000 and bear interest at various rates based on market rates and the company's credit rating. SDG&E's bank lines of credit were unused at both December 31, 1998, and 1997. At December 31, 1998, there were no commercial-paper obligations outstanding. At December 31, 1997, SoCalGas had $354 million of commercial-paper obligations outstanding, of which approximately $94 million related to the restructuring costs associated with certain long-term gas-supply contracts under the Comprehensive Settlement. See Note 14 for additional information. 5 LONG-TERM DEBT - -------------------------------------------------------------- December 31, (Dollars in millions) 1998 1997 - -------------------------------------------------------------- Long-Term Debt First mortgage bonds 5.25% March 1, 1998 $ - $ 100 7.625% June 15, 2002 28 80 6.875% August 15, 2002 100 100 5.75% November 15, 2003 100 100 6.8% June 1, 2015 14 14 5.9% June 1, 2018 71 71 5.9% September 1, 2018 93 93 6.1% and 6.4% September 1, 2018 and 2019 118 118 9.625% April 15, 2020 10 54 Variable rates September 1, 2020 58 75 5.85% June 1, 2021 60 60 8.75% October 1, 2021 150 150 8.5% April 1, 2022 10 44 7.375% March 1, 2023 100 100 7.5% June 15, 2023 125 125 6.875% November 1, 2025 175 175 Various rates December 1, 2027 250 250 ---------------------- Total 1,462 1,709 Rate-reduction bonds 592 658 Debt incurred to acquire limited partnerships, secured by real estate, at 6.8% to 9.0%, payable annually through 2008 305 313 Various unsecured bonds at 4.15% to 10% from 1998 to 2006 453 296 Various unsecured bonds at 5.9% or at variable rates (4.3% to 5.0% at December 31, 1998) from 2014 to 2023 254 254 Capitalized leases 76 106 ---------------------- Total 3,142 3,336 ---------------------- Less: Current portion of long-term debt 330 270 Unamortized discount on long-term debt 17 21 ---------------------- 347 291 ---------------------- Total $ 2,795 $ 3,045 - -------------------------------------------------------------- Excluding capital leases, which are described in Note 13, maturities of long-term debt, including PE's Employees Stock Ownership Plan, are $271 million in 1999, $96 million in 2000, $186 million in 2001, $193 million in 2002 and $241 million in 2003. SDG&E and SoCalGas have CPUC authorization to issue an additional $752 million in long-term debt. Although holders of variable-rate bonds may elect to redeem them prior to scheduled maturity, for purposes of determining the maturities listed above, it is assumed the bonds will be held to maturity. First-Mortgage Bonds First-mortgage bonds are secured by a lien on substantially all utility plant. In addition, certain non-utility subsidiary assets are pledged as collateral for SoCalGas' first-mortgage bonds. SDG&E and SoCalGas may issue additional first-mortgage bonds upon compliance with the provisions of their bond indentures, which provide for, among other things, the issuance of additional first- mortgage bonds ($1.5 billion as of December 31, 1998). During 1998, the company retired $247 million of first- mortgage bonds, of which $147 million was retired prior to scheduled maturity. Certain first-mortgage bonds may be called at SDG&E's or SoCalGas' option. SoCalGas has no variable-rate bonds. SDG&E has $188 million of bonds with variable interest-rate provisions that are callable at various dates within one year. Of the company's remaining callable bonds, $10 million are callable in the year 2000, $150 million in 2001, $203 million in 2002, and $624 million in 2003. $242 million of the bonds are not callable. Rate-Reduction Bonds In December 1997, $658 million of rate-reduction bonds were issued on behalf of SDG&E at an average interest rate of 6.26 percent. These bonds were issued to facilitate the 10-percent rate reduction mandated by California's electric-restructuring law. See Note 14 for additional information. These bonds are being repaid over 10 years by SDG&E's residential and small commercial customers via a charge on their electricity bills. These bonds are secured by the revenue streams collected from customers and are not secured by, or payable from, utility assets. Unsecured Debt Various long-term obligations totaling $707 million are unsecured. During 1998, SoCalGas issued $75 million of unsecured debt in medium-term notes used to finance working capital requirements. Unsecured bonds totaling $124 million have variable-interest-rate provisions. Debt of Employee Stock Ownership Plan (ESOP) and Trust The Trust covers substantially all of the company's former PE employees and is used to fund part of their retirement savings program. It has an ESOP feature and holds approximately 3.1 million shares of the company's common stock. The variable-rate ESOP debt held by the Trust bears interest at a rate necessary to place or remarket the notes at par. The balance of this debt was $130 million at December 31, 1998, and is included in the table above as part of the various unsecured bonds at 4.15 percent to 10 percent. Principal is due on November 30, 1999, and interest is payable monthly. The company is obligated to make contributions to the Trust sufficient to satisfy debt service requirements. As the company makes contributions to the Trust, these contributions, plus any dividends paid on the unallocated shares of the company's common stock held by the Trust, will be used to repay the debt. As dividends are increased or decreased, required contributions are reduced or increased, respectively. Interest on ESOP debt amounted to $6 million each in 1998, 1997 and 1996. Dividends used for debt service amounted to $3 million each in 1998, 1997, and 1996, and are deductible only for federal income tax purposes. Currency Interest-Rate Swaps SDG&E periodically enters into interest-rate swap and cap agreements to moderate its exposure to interest-rate changes and to lower its overall cost of borrowings. At December 31, 1998, SDG&E had such an agreement, maturing in 2002, with underlying debt of $45 million. 6 FACILITIES UNDER JOINT OWNERSHIP SONGS and the Southwest Powerlink transmission line are owned jointly with other utilities. The company's interests at December 31, 1998, are: - ----------------------------------------------------------- (Dollars in millions) Southwest Project SONGS Powerlink - ----------------------------------------------------------- Percentage ownership 20 89 Regulatory assets $ 312 - Utility plant in service - $ 217 Accumulated depreciation and amortization - $ 104 Construction work in progress $ 18 $ 1 - ----------------------------------------------------------- The company's share of operating expenses is included in the Statements of Consolidated Income. Each participant in the project must provide its own financing. The amounts specified above for SONGS include nuclear production, transmission and other facilities. $11 million of substation equipment included in these amounts is wholly owned by the company. SONGS Decommissioning Objectives, work scope and procedures for the future dismantling and decontamination of the SONGS units must meet the requirements of the Nuclear Regulatory Commission, the Environmental Protection Agency, the California Public Utilities Commission and other regulatory bodies. The company's share of decommissioning costs for the SONGS units is estimated to be $425 million in today's dollars and is based on a cost study completed in 1998. Cost studies are performed and updated periodically by outside consultants. Although electric- industry restructuring legislation requires that stranded costs, which include SONGS' costs, be amortized in rates by 2001, the recovery of decommissioning costs is allowed until the time that the costs are fully recovered. The amount accrued each year is based on the amount allowed by regulators and is currently being collected in rates. This amount is considered sufficient to cover the company's share of future decommissioning costs. Payments to the nuclear-decommissioning trusts are expected to continue until SONGS is decommissioned, which is not expected to occur before 2013. Unit 1, although permanently shut down in 1992, was scheduled to be decommissioned concurrently with Units 2 and 3. However, the company and the other owners of SONGS have requested that the CPUC grant authority to begin decommissioning Unit 1 on January 1, 2000. The amounts collected in rates are invested in externally managed trust funds. The securities held by the trust are considered available for sale and shown on the Consolidated Balance Sheets adjusted to market value. The fair values reflect unrealized gains of $149 million and $89 million at December 31, 1998, and 1997, respectively. The Financial Accounting Standards Board is reviewing the accounting for liabilities related to closure and removal of long- lived assets, such as nuclear power plants, including the recognition, measurement and classification of such costs. The Board could require, among other things, that the company's future balance sheets include a liability for the estimated decommissioning costs, and a related increase in the cost of the asset. Additional information regarding SONGS is included in Notes 13 and 14. 7 INCOME TAXES The reconciliation of the statutory federal income tax rate to the effective income tax rate is as follows: - -------------------------------------------------------------- 1998 1997 1996 - -------------------------------------------------------------- Statutory federal income tax rate 35.0% 35.0% 35.0% Depreciation 6.3 7.1 6.2 State income taxes-net of federal income tax benefit 7.4 6.7 6.2 Tax credits (12.9) (5.7) (4.8) Equipment leasing activities (1.5) (1.1) (1.4) Capitalized expenses not deferred 0.2 (1.4) (2.1) Other-net (2.6) 0.5 2.2 --------------------------- Effective income tax rate 31.9% 41.1% 41.3% - -------------------------------------------------------------- The components of income tax expense are as follows: - -------------------------------------------------------------- (Dollars in millions) 1998 1997 1996 - -------------------------------------------------------------- Current: Federal $278 $236 $183 State 89 63 65 --------------------------- Total current taxes 367 299 248 --------------------------- Deferred: Federal (165) 1 52 State (58) 7 6 --------------------------- Total deferred taxes (223) 8 58 --------------------------- Deferred investment tax credits-net (6) (6) (6) --------------------------- Total income tax expense $138 $301 $300 - -------------------------------------------------------------- Accumulated deferred income taxes at December 31 result from the following: - -------------------------------------------------------------- (Dollars in millions) 1998 1997 - -------------------------------------------------------------- Deferred Tax Liabilities: Differences in financial and tax bases of utility plant $924 $1,063 Regulatory balancing accounts 23 133 Regulatory assets 76 120 Partnership income 27 21 Other 71 53 ------------------ Total deferred tax liabilities 1,121 1,390 ------------------ Deferred Tax Assets: Unamortized investment tax credits 88 89 Comprehensive Settlement (see Note 14) 95 117 Postretirement benefits 76 90 Other deferred liabilities 102 110 Restructuring costs 42 54 Other 177 204 ------------------ Total deferred tax assets 580 664 ------------------ Net deferred income tax liability 541 726 Current portion (net asset) 93 15 ------------------ Non-current portion (net liability) $634 $741 - -------------------------------------------------------------- 8 EMPLOYEE BENEFIT PLANS The information presented below describes the plans of the company and its principal subsidiaries. In connection with the PE/Enova Business Combination described in Note 1, certain of these plans have been or will be replaced or modified, and numerous participants have been or will be transferred from the subsidiaries' plans to those of Sempra Energy. Pension and Other Postretirement Benefits The company sponsors several qualified and nonqualified pension plans and other postretirement benefit plans for its employees. The following tables provide a reconciliation of the changes in the plans' benefit obligations and fair value of assets over the two years, and a statement of the funded status as of each year end:
- ------------------------------------------------------------------------------------- Other Pension Benefits Postretirement Benefits ---------------------------------------------- (Dollars in millions) 1998 1997 1998 1997 - ------------------------------------------------------------------------------------- Weighted-Average Assumptions as of December 31: Discount rate 6.75% 7.07% 6.75% 7.02% Expected return on plan assets 8.50% 8.13% 8.50% 7.87% Rate of compensation increase 5.00% 5.00% 5.00% 5.00% Cost trend of covered health-care charges - - 8.00%(1) 7.00%(2) Change in Benefit Obligation: Net benefit obligation at January 1 $2,117 $1,981 $ 531 $ 442 Service cost 55 53 13 15 Interest cost 148 144 36 35 Plan participants' contributions - - 1 1 Plan amendments 18 - - - Actuarial (gain) loss (44) 54 - 57 Special termination benefits 63 13 3 2 Gross benefits paid (277) (128) (21) (21) ---------------------------------------------- Net benefit obligation at December 31 2,080 2,117 563 531 ---------------------------------------------- Change in Plan Assets: Fair value of plan assets at January 1 2,653 2,373 363 286 Actual return on plan assets 407 406 64 59 Employer contributions 13 2 36 38 Plan participants' contributions - - 1 1 Gross benefits paid (277) (128) (21) (21) ---------------------------------------------- Fair value of plan assets at December 31 2,796 2,653 443 363 ---------------------------------------------- Funded status at December 31 716 536 (120) (168) Unrecognized net actuarial gain (926) (733) (107) (66) Unrecognized prior service cost 73 61 (13) (14) Unrecognized net transition obligation 3 4 - - ---------------------------------------------- Net liability at December 31 (3) $ (134) $ (132) $(240) $(248) - ------------------------------------------------------------------------------------- (1) Decreasing to ultimate trend of 6.50% in 2004. (2) Decreasing to ultimate trend of 6.50% in 1998. (3) Approximates amounts recognized in the Consolidated Balance Sheets at December 31.
The following table provides the components of net periodic benefit cost for the plans:
- ------------------------------------------------------------------------------------- Other Pension Benefits Postretirement Benefits ----------------------------------------------------- (Dollars in millions) 1998 1997 1996 1998 1997 1996 - ------------------------------------------------------------------------------------- Service cost $55 $53 $58 $13 $15 $18 Interest cost 148 144 141 36 35 36 Expected return on assets (196) (178) (161) (24) (22) (19) Amortization of: Transition obligation 1 1 1 2 2 2 Prior service cost 6 5 5 (1) (1) (1) Actuarial (gain) loss (23) (18) (4) - 1 1 Special termination benefit 63 13 - 3 2 - Settlement credit (30) - - - - - Regulatory adjustment - - (12) 9 12 12 ----------------------------------------------------- Total net periodic benefit cost $24 $20 $28 $38 $44 $49 - -------------------------------------------------------------------------------------
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A 1% change in assumed health care cost trend rates would have the following effects: - ------------------------------------------------------------------ (Dollars in millions) 1% Increase 1% Decrease - ------------------------------------------------------------------ Effect on total of service and interest cost components of net periodic postretirement health care benefit cost $11 $(10) Effect on the health care component of the accumulated postretirement benefit obligation $72 $(65) - ------------------------------------------------------------------ The projected benefit obligation and accumulated benefit obligation were $55 million and $45 million, respectively, as of December 31, 1998, and $53 million and $44 million, as of December 31, 1997. There were no pension plans with accumulated benefit obligations in excess of plan assets for 1998 or 1997. Other postretirement benefits include medical benefits for retirees and their spouses (and Medicare Part B reimbursement for certain retirees) and retiree life insurance. Savings Plans Sempra Energy and its subsidiaries offer savings plans, administered by plan trustees, to all eligible employees. Eligibility to participate in the various employer plans ranges from one month to one year of completed service. Employees may contribute, subject to plan provisions, from 1 percent to 15 percent of their regular earnings. Employer contributions, after one year of completed service, are made in shares of company common stock. Employer contribution methods vary by plan, but generally the contribution is equal to 50 percent of the first 6 percent of eligible base salary contributed by employees. During 1998, the SDG&E plan contribution was age-based for represented employees. The employee's contributions, at the direction of the employees, are primarily invested in company stock, mutual funds or guaranteed investment contracts. Employer contributions for the Sempra and SoCalGas plans are partially funded by the Pacific Enterprises Employee Stock Ownership Plan and Trust. Annual expense for the savings plans was $14 million in 1998, $11 million in 1997 and $10 million in 1996. Employee Stock Ownership Plan The Pacific Enterprises Employee Stock Ownership Plan and Trust (Trust) covers substantially all employees of PE and SoCalGas and is used to partially fund their retirement savings plan programs. All contributions to the Trust are made by the company, and there are no contributions made by the participants. As the company makes contributions to the ESOP, the ESOP debt service is paid and shares are released in proportion to the total expected debt service. Compensation expense is charged and equity is credited for the market value of the shares released. Income-tax deductions are allowed based on the cost of the shares. Dividends on unallocated shares are used to pay debt service and are charged against liabilities. The Trust held 3.1 million and 3.3 million shares of company common stock, with fair values of $77.9 million and $80.3 million, at December 31, 1998, and 1997, respectively. 9 STOCK-BASED COMPENSATION Sempra Energy has stock-based compensation plans that align employee and shareholder objectives related to the long-term growth of the company. The company's long-term incentive stock compensation plan provides for aggregate awards of Sempra Energy non-qualified stock options, incentive stock options, restricted stock, stock appreciation rights, performance awards, stock payments or dividend equivalents. In 1995, Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for Stock-Based compensation," was issued. It encourages a fair-value-based method of accounting for stock-based compensation. As permitted by SFAS No. 123, the company adopted its disclosure-only requirements and continues to account for stock-based compensation in accordance with the provisions of accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." In 1998, 102,640 shares of Sempra Energy common stock were awarded to officers. Under the predecessor plan, in each of the last 10 years, Enova awarded between 49,000 and 75,000 shares to key executives. These awards are subject to forfeiture over four years if certain corporate goals are not met. Holders of this stock have voting rights and receive dividends prior to the time the restrictions lapse if, and to the extent, dividends are paid on Sempra Energy common stock. Compensation expense for the issuance of these restricted shares was approximately $2 million in 1998, $1 million in 1997 and $1 million in 1996. In 1998, Sempra Energy granted 3,425,800 stock options. The option price is equal to the market price of common stock at the date of grant. The grants, which vest over a four-year period, include options with and without performance-based features. The stock options expire in ten years from the date of grant. All options granted prior to 1997 became immediately exercisable upon approval by PE's shareholders of the business combination with Enova. The options were originally scheduled to vest annually over a service period ranging from three to five years. Sempra Energy's plans allow for the granting of dividend equivalents based upon performance goals. This feature provides grantees, upon exercise of the option, with the opportunity to receive all or a portion of the cash dividends that would have been paid on the shares if the shares had been outstanding since the grant date. Dividend equivalents are payable only if corporate goals are met and, for grants prior to July 1, 1998, if the exercise price exceeds the market value of the shares purchased. The percentage of dividends paid as dividend equivalents will depend upon the extent to which the performance goals are met. The following information is presented after conversion of PE stock into company stock as described in Note 1. Stock option activity is summarized in the following tables. - ----------------------------------------------------------------- Options With Performance Features - ----------------------------------------------------------------- Shares Average Options Under Exercise Exercisable Option Price at Year End - ----------------------------------------------------------------- December 31, 1995 846,188 $16.23 - Granted 1,030,404 17.95 -------------------------------------------- December 31, 1996 1,876,592 17.17 282,063 Granted 1,040,103 20.37 Exercised (359,288) 16.53 Cancelled (71,190) 20.37 -------------------------------------------- December 31, 1997 2,486,217 18.51 1,513,545 Granted 2,131,803 25.23 Exercised (512,059) 17.12 Cancelled (509,301) 23.00 -------------------------------------------- December 31, 1998 3,596,660 $22.06 1,387,523 - ----------------------------------------------------------------- - ----------------------------------------------------------------- Options Without Performance Features - ----------------------------------------------------------------- Shares Average Options Under Exercise Exercisable Option Price at Year End - ----------------------------------------------------------------- December 31, 1995 2,302,018 $18.14 1,200,183 Exercised (304,520) 15.00 Cancelled (125,417) 26.05 -------------------------------------------- December 31, 1996 1,872,081 18.12 1,197,687 Exercised (493,848) 14.94 Cancelled (14,737) 35.24 -------------------------------------------- December 31, 1997 1,363,496 19.08 1,363,496 Granted 1,293,997 26.33 Exercised (596,629) 15.72 Cancelled (240,632) 29.78 -------------------------------------------- December 31, 1998 1,820,232 $23.92 523,661 - ----------------------------------------------------------------- Additional information on options outstanding at December 31, 1998, is as follows: - ----------------------------------------------------------------- Outstanding Options - ----------------------------------------------------------------- Range of Number Average Average Exercise of Remaining Exercise Prices Shares Life Price - ----------------------------------------------------------------- $12.80-$16.12 623,362 5.55 $15.29 $16.79-$20.36 1,584,272 7.47 $19.03 $24.10-$31.00 3,209,258 9.05 $25.82 ---------- 5,416,892 8.19 $22.64 - ----------------------------------------------------------------- Exercisable Options - ----------------------------------------------------------------- Range of Number Average Exercise of Exercise Prices Shares Price - ----------------------------------------------------------------- $12.80-$16.12 623,362 $15.29 $16.79-$20.36 1,109,878 $18.46 $24.11-$31.00 177,944 $26.70 ---------- 1,911,184 $18.20 - ----------------------------------------------------------------- The fair value of each option grant (including the dividend equivalent) was estimated on the date of grant using the modified Black- Scholes option-pricing model. Weighted average fair values for options granted in 1998, 1997, and 1996 were $8.20, $5.23 and $5.00, respectively. The assumptions that were used to determine these fair values are as follows: - ----------------------------------------------------------------- Year Ended December 31 1998 1997 1996 - ----------------------------------------------------------------- Stock price volatility 16% 18% 19% Risk-free rate of return 5.6% 6.4% 6.1% Annual dividend yield 0% 0% 0% Expected life 6 Years 3.8 Years 4.3 Years - ----------------------------------------------------------------- Compensation expense for the stock option grants was $11.7 million, $16.9 million and $5.5 million in 1998, 1997 and 1996, respectively. The differences between compensation cost included in net income and the related cost measured by the fair-value-based method defined in SFAS No. 123 are immaterial. 10 FINANCIAL INSTRUMENTS Fair Value The fair values of the company's financial instruments (cash, temporary investments, funds held in trust, notes receivable, investments in limited partnerships, dividends payable, short- and long-term debt, customer deposits, and preferred stock of subsidiaries) are not materially different from the carrying amounts, except for long-term debt and preferred stock of subsidiaries. The carrying amounts and fair values of long-term debt are $3.1 billion and $3.2 billion, respectively, at December 31, 1998, and $3.4 billion and $3.5 billion at December 31, 1997. The carrying amounts and fair values of subsidiaries' preferred stock are $204 million and $182 million, respectively, at December 31, 1998, and $279 million and $258 million, respectively, at December 31, 1997. The fair values of the first-mortgage and other bonds and preferred stock are estimated based on quoted market prices for them or for similar issues. The fair values of long-term notes payable are based on the present value of the future cash flows, discounted at rates available for similar notes with comparable maturities. Included in long-term debt are SDG&E's rate-reduction bonds. The carrying amounts and fair values of the bonds are $592 million and $607 million, respectively, at December 31, 1998. Off-Balance-Sheet Financial Instruments The company's policy is to use derivative financial instruments to manage its exposure to fluctuations in interest rates, foreign-currency exchange rates and energy prices. Transactions involving these financial instruments expose the company to market and credit risks which may at times be concentrated with certain counterparties, although counterparty nonperformance is not anticipated. Additional information on this topic is discussed in Note 2. Swap Agreements The company periodically enters into interest-rate-swap and cap agreements to moderate exposure to interest-rate changes and to lower the overall cost of borrowing. These agreements generally remain off the balance sheet as they involve the exchange of fixed- and variable-rate interest payments without the exchange of the underlying principal amounts. The related gains or losses are reflected in the consolidated income statement as part of interest expense. At December 31, 1998, and 1997, SDG&E had one interest-rate-swap agreement: a floating-to-fixed-rate swap associated with $45 million of variable-rate bonds maturing in 2002. SDG&E expects to hold this financial instrument to its maturity. This swap agreement has effectively fixed the interest rate on the underlying variable-rate debt at 5.4 percent. SDG&E would be exposed to interest-rate fluctuations on the underlying debt should the counterparty to the agreement not perform. Such nonperformance is not anticipated. This agreement, if terminated, would result in an obligation of $3 million at December 31, 1998, and $2 million at December 31, 1997. Additional information on this topic is included in Note 5. Energy Derivatives Information on derivative financial instruments of SET is provided below. The company's regulated operations use energy derivatives for both price- risk management and trading purposes within certain limitations imposed by company policies and regulatory requirements. Energy derivatives are used to mitigate risk and better manage costs. These instruments include forward contracts, swaps, options and other contracts which have maturities ranging from 30 days to 12 months. SoCalGas is subject to price risk on its natural gas purchases if its cost exceeds a 2-percent tolerance band above the benchmark price. This is discussed further in Note 14. SoCalGas becomes subject to price risk when positions are incurred during the buying, selling and storage of natural gas. As a result of the Gas Cost Incentive Mechanism (GCIM), SoCalGas enters into a certain amount of gas futures contracts in the open market with the intent of reducing gas costs within the GCIM tolerance band. The CPUC has approved the use of gas futures for managing risk associated with the GCIM. For the years ended December 31, 1998, 1997, and 1996, gains and losses from natural gas futures contracts are not material to SoCalGas' financial statements. Sempra Energy Trading SET derives a substantial portion of its revenue from market making and trading activities, as a principal, in natural gas, petroleum and electricity. It quotes bid and offer prices to end users and other market makers. It also earns trading profits as a dealer by structuring and executing transactions that permit its counterparties to manage their risk profiles. In addition, it takes positions in energy markets based on the expectation of future market conditions. These positions may be offset with similar positions or may be offset in the exchange-traded markets. These positions include options, forwards, futures and swaps. These financial instruments represent contracts with counterparties whereby payments are linked to or derived from energy-market indices or on terms predetermined by the contract, which may or may not be physically or financially settled by SET. For the year ended December 31, 1998, substantially all of SET's derivative transactions were held for trading and marketing purposes. Market risk arises from the potential for changes in the value of financial instruments resulting from fluctuations in natural gas, petroleum and electricity commodity-exchange prices and basis. Market risk is also affected by changes in volatility and liquidity in markets in which these instruments are traded. SET adjusts the book value of these derivatives to market each month with gains and losses recognized in earnings. These instruments are included in other current assets on the Consolidated Balance Sheet. Certain instruments such as swaps are entered into and closed out within the same month and, therefore, do not have any balance-sheet impact. Gains and losses are included in electric or natural gas revenue or expense, whichever is appropriate, in the Consolidated Income Statements. SET also carries an inventory of financial instruments. As trading strategies depend on both market making and proprietary positions, given the relationships between instruments and markets, those activities are managed in concert in order to maximize trading profits. SET's credit risk from financial instruments as of December 31, 1998, is represented by the positive fair value of financial instruments after consideration of master netting agreements and collateral. Credit risk disclosures, however, relate to the net accounting losses that would be recognized if all counterparties completely failed to perform their obligations. Options written do not expose SET to credit risk. Exchange- traded futures and options are not deemed to have significant credit exposure as the exchanges guarantee that every contract will be properly settled on a daily basis. The following table approximates the counterparty credit quality and exposure of SET expressed in terms of net replacement value (in millions of dollars): - ----------------------------------------------------------------- Futures, forward and swap Purchased Counterparty credit quality: contracts options Total - ----------------------------------------------------------------- AAA $32 $1 $33 AA 41 14 55 A 129 19 148 BBB 290 26 316 Below investment grade 69 2 71 Exchanges 30 8 38 - ----------------------------------------------------------------- $591 $70 $661 - ----------------------------------------------------------------- Financial instruments with maturities or repricing characteristics of 180 days or less, including cash and cash equivalents, are considered to be short-term and, therefore, the carrying values of these financial instruments approximate their fair values. SET's commodities owned, trading assets and trading liabilities are carried at fair value. The average fair values during the year, based on quarterly observation, for trading assets and trading liabilities which are considered financial instruments with off-balance-sheet risk approximate $952 million and $890 million, respectively. The fair values are net of the amounts offset pursuant to rights of setoff based on qualifying master netting arrangements with counterparties, and do not include the effects of collateral held or pledged. As of December 31, 1998, and 1997, SET's trading assets and trading liabilities approximate the following: - ----------------------------------------------------------------- December 31, (Dollars in millions) 1998 1997 - ----------------------------------------------------------------- Trading Assets Unrealized gains on swaps and forwards $756 $497 Due from commodity clearing organization and clearing brokers 75 41 OTC commodity options purchased 45 33 Due from trading counterparties 30 16 --------------------- Total $906 $587 - ----------------------------------------------------------------- Trading Liabilities Unrealized losses on swaps and forwards $740 $487 Due to trading counterparties 35 41 OTC commodity options written 30 29 --------------------- Total $805 $557 - ----------------------------------------------------------------- Notional amounts do not necessarily represent the amounts exchanged by parties to the financial instruments and do not measure SET's exposure to credit or market risks. The notional or contractual amounts are used to summarize the volume of financial instruments, but do not reflect the extent to which positions may offset one another. Accordingly, SET is exposed to much smaller amounts potentially subject to risk. The notional amounts of SET's financial instruments are: - ----------------------------------------------------------------- (Dollars in millions) Total - ----------------------------------------------------------------- Forwards and commodity swaps $5,916 Futures and exchange options 2,915 Options purchased 1,320 Options written 1,298 -------------- Total $11,449 - ----------------------------------------------------------------- 11 PREFERRED STOCK OF SUBSIDIARIES - ----------------------------------------------------------------- Pacific Enterprises Call December 31, (Dollars in millions except call price) Price 1998 1997 - ----------------------------------------------------------------- Cumulative preferred without par value: $4.75 Dividend, 200,000 shares authorized and outstanding $100.00 $20 $20 $4.50 Dividend, 300,000 shares authorized and outstanding $100.00 30 30 $4.40 Dividend, 100,000 shares authorized and outstanding $101.50 10 10 $4.36 Dividend, 200,000 shares authorized and outstanding $101.00 20 20 $4.75 Dividend, 253 shares authorized and outstanding $101.00 - - -------------- Total $80 $80 - ----------------------------------------------------------------- All or any part of every series of presently outstanding PE preferred stock is subject to redemption at PE's option at any time upon not less than 30 days' notice, at the applicable redemption price for each series, together with the accrued and accumulated dividends to the date of redemption. All series have one vote per share and cumulative preferences as to dividends. No shares of Unclassified or Class A preferred stock are outstanding. - ----------------------------------------------------------------- SoCalGas December 31, (Dollars in millions) 1998 1997 - ----------------------------------------------------------------- Not subject to mandatory redemption: $25 par value, authorized 1,000,000 shares 6% Series, 28,664 shares outstanding $1 $1 6% Series A, 783,032 shares outstanding 19 19 Without par value, authorized 10,000,000 shares 7.75% Series - 75 -------------- $20 $95 - ----------------------------------------------------------------- None of SoCalGas' series of preferred stock is callable. All series have one vote per share and cumulative preferences as to dividends. On February 2, 1998, SoCalGas redeemed all outstanding shares of 7.75% Series Preferred Stock at a price per share of $25 plus $0.09 of dividends accruing to the date of redemption. The total cost to SoCalGas was approximately $75.3 million. - ----------------------------------------------------------------- SDG&E Call December 31, (Dollars in millions except call price) Price 1998 1997 - ----------------------------------------------------------------- Not subject to mandatory redemption $20 par value, authorized 1,375,000 shares: 5% Series, 375,000 shares outstanding $24.00 $8 $8 4.50% Series, 300,000 shares outstanding $21.20 6 6 4.40% Series, 325,000 shares outstanding $21.00 7 7 4.60% Series, 373,770 shares outstanding $20.25 7 7 Without par value: $1.70 Series, 1,400,000 shares outstanding $25.85 35 35 $1.82 Series, 640,000 shares outstanding $26.00 16 16 -------------- Total not subject to mandatory redemption $79 $79 -------------- Subject to mandatory redemption Without par value: $1.7625 Series, 1,000,000 shares outstanding $25.00 $25 $25 - ----------------------------------------------------------------- All series of SDG&E's preferred stock have cumulative preferences as to dividends. The $20 par value preferred stock has two votes per share on matters being voted upon by shareholders of SDG&E and a liquidation value at par, whereas the no-par-value preferred stock is nonvoting and has a liquidation value of $25 per share. SDG&E is authorized to issue 10,000,000 shares of no-par-value stock (both subject to and not subject to mandatory redemption). All series are currently callable except for the $1.70 and $1.7625 series (callable in 2003). The $1.7625 series has a sinking fund requirement to redeem 50,000 shares per year from 2003 to 2007; the remaining 750,000 shares must be redeemed in 2008. 12 SHAREHOLDERS EQUITY AND EARNINGS PER SHARE The company's outstanding stock options represent the only forms of potential common stock at December 31, 1998, 1997 and 1996. The reconciliation between basic and diluted EPS is as follows: - ----------------------------------------------------------------- Income Shares Earnings (in millions) (in thousands) Per Share - ----------------------------------------------------------------- 1998: Basic $294 236,423 $1.24 Effect of dilutive stock options 701 - ----------------------------------------------------------------- Diluted $294 237,124 $1.24 - ----------------------------------------------------------------- 1997: Basic $432 236,662 $1.83 Effect of dilutive stock options 587 - ----------------------------------------------------------------- Diluted $432 237,249 $1.82 - ----------------------------------------------------------------- 1996: Basic $427 240,825 $1.77 Effect of dilutive stock options 332 - ----------------------------------------------------------------- Diluted $427 241,157 $1.77 - ----------------------------------------------------------------- The company is authorized to issue 750,000,000 shares of no par value common stock and 50,000,000 shares of Preferred Stock. At December 31, 1998, there were 240,026,439 shares of common stock outstanding, compared to 235,598,111 shares outstanding at December 31, 1997. No shares of Preferred Stock were issued and outstanding. 13 COMMITMENTS AND CONTINGENCIES Natural Gas Contracts The company buys natural gas under several short-term and long-term contracts. Short-term purchases are based on monthly spot-market prices. SoCalGas has commitments for firm pipeline capacity under contracts with pipeline companies that expire at various dates through the year 2006. These agreements provide for payments of an annual reservation charge. SoCalGas recovers such fixed charges in rates. SDG&E has long-term capacity contracts with interstate pipelines which expire on various dates between 2007 and 2023. SDG&E has long-term natural gas supply contracts (included in the table below) with four Canadian suppliers that expire between 2001 and 2004. SDG&E has been involved in negotiations and litigation with the suppliers concerning the contracts' terms and prices. SDG&E has settled with three of the suppliers. One of the three is delivering natural gas under the terms of the settlement agreement; the other two have ceased deliveries. The fourth supplier has ceased deliveries pending legal resolution. A U.S. Court of Appeal has upheld a U.S. District Court's invalidation of the contracts with two of these suppliers. If the supply of Canadian natural gas to SDG&E is not resumed to a level approximating the related committed long-term pipeline capacity, SDG&E intends to continue using the capacity in other ways, including the transport of replacement gas and the release of a portion of this capacity to third parties. At December 31, 1998, the future minimum payments under natural gas contracts were: - ----------------------------------------------------------------- Storage and (Dollars in millions) Transportation Natural Gas - ----------------------------------------------------------------- 1999 $193 $288 2000 195 170 2001 197 175 2002 197 179 2003 193 181 Thereafter 587 - ---------------------------------- Total minimum payments $1,562 $993 - ----------------------------------------------------------------- Total payments under the short-term and long-term contracts were $1.0 billion in 1998, $1.2 billion in 1997, and $1.0 billion in 1996. All of SDG&E's gas is delivered through SoCalGas pipelines under a short-term transportation agreement. In addition, SoCalGas provides SDG&E six billion cubic feet of natural gas storage capacity under an agreement expiring March 2000. These agreements are not included in the above table. Purchased-Power Contracts SDG&E buys electric power under several long-term contracts. The contracts expire on various dates between 1999 and 2025. Under California's Electric Industry Restructuring law, which is described in Note 14, the California investor-owned electric utilities (IOUs) are obligated to bid their power supply, including owned generation and purchased-power contracts, into the California Power Exchange (PX). As a result, SDG&E's system requirements are met primarily through purchases from the PX. At December 31, 1998, the estimated future minimum payments under the long-term contracts were: - ----------------------------------------------------------------- (Dollars in millions) - ----------------------------------------------------------------- 1999 $249 2000 211 2001 174 2002 136 2003 135 Thereafter 2,001 ---------- Total minimum payments $2,906 - ----------------------------------------------------------------- These payments for actual purchases represent capacity charges and minimum energy purchases. SDG&E is required to pay additional amounts for actual purchases of energy that exceed the minimum energy commitments. Total payments, including actual energy payments, under the contracts were $293 million in 1998, $421 million in 1997 and $296 million in 1996. Payments under purchased-power contracts decreased in 1998 as a result of the purchases from the PX, which commenced April 1, 1998. SDG&E has entered into agreements to sell its power plants and other electric-generating resources (excluding SONGS), and has announced a plan to auction its long-term purchased power contracts. Additional information on this topic is provided in Note 14. Leases The company has leases (primarily operating) on real and personal property expiring at various dates from 1999 to 2030. Certain leases on office facilities contain escalation clauses requiring annual increases in rent ranging from 2 percent to 7 percent. The rentals payable under these leases are determined on both fixed and percentage bases, and most leases contain options to extend, which are exercisable by the company. The company also has nuclear fuel, office buildings, a generating facility and other properties that are financed by long-term capital leases. Utility plant includes $177 million at December 31, 1998, and $198 million at December 31, 1997, related to these leases. The associated accumulated amortization is $114 million and $102 million, respectively. The minimum rental commitments payable in future years under all noncancellable leases are: - ----------------------------------------------------------------- Operating Capitalized (Dollars in millions) Leases Leases - ----------------------------------------------------------------- 1999 $60 $31 2000 58 14 2001 55 14 2002 52 14 2003 51 11 Thereafter 380 9 ------------------------------ Total future rental commitment $656 93 Imputed interest (6% to 9%) (17) ----------- Net commitment $76 - ----------------------------------------------------------------- Rent expense totaled $105 million in 1998, $137 million in 1997 and $146 million in 1996. In connection with the quasi-reorganization described in Note 2, PE established reserves of $102 million to fair value operating leases related to its headquarters and other leases at December 31, 1992. The remaining amount of these reserves was $76 million at December 31, 1998. These leases are reflected in the above table. Environmental Issues The company believes that its operations are conducted in accordance with federal, state and local environmental laws and regulations governing hazardous wastes, air and water quality, land use, and solid waste disposal. SoCalGas and SDG&E incur significant costs to operate their facilities in compliance with these laws and regulations. The costs of compliance with environmental laws and regulations generally have been recovered in customer rates. In 1994, the CPUC approved the Hazardous Waste Collaborative Memorandum account allowing utilities to recover their hazardous waste costs, including those related to Superfund sites or similar sites requiring cleanup. Recovery of 90 percent of cleanup costs and related third-party litigation costs and 70 percent of the related insurance- litigation expenses is permitted. Environmental liabilities that may arise are recorded when remedial efforts are probable and the costs can be estimated. The company's capital expenditures to comply with environmental laws and regulations were $1 million in 1998, $5 million in 1997, and $9 million in 1996, and are not expected to be significant during the next five years. These expenditures primarily include the cost of retrofitting SDG&E's power plants to reduce air emissions. These costs will be reduced significantly by SDG&E's sale of its non-nuclear generating facilities. The company has been associated with various sites which may require remediation under federal, state or local environmental laws. The company is unable to determine fully the extent of its responsibility for remediation of these sites until assessments are completed. Furthermore, the number of others that also may be responsible, and their ability to share in the cost of the cleanup, is not known. The company does not anticipate that such costs, net of the portion recoverable in rates, will be significant. As discussed in Note 14, restructuring of the California electric- utility industry will change the way utility rates are set and costs are recovered. SDG&E asked that the collaborative account be modified, and that electric generation-related cleanup costs be eligible for transition-cost recovery. The final outcome of this decision is that SDG&E's costs of compliance with environmental regulations may be fully recoverable. Nuclear Insurance SDG&E and the co-owners of SONGS have purchased primary insurance of $200 million, the maximum amount available, for public-liability claims. An additional $8.7 billion of coverage is provided by secondary financial protection required by the Nuclear Regulatory Commission and provides for loss sharing among utilities owning nuclear reactors if a costly accident occurs. SDG&E could be assessed retrospective premium adjustments of up to $32 million in the event of a nuclear incident involving any of the licensed, commercial reactors in the United States, if the amount of the loss exceeds $200 million. In the event the public-liability limit stated above is insufficient, the Price-Anderson Act provides for Congress to enact further revenue-raising measures to pay claims, which could include an additional assessment on all licensed reactor operators. Insurance coverage is provided for up to $2.8 billion of property damage and decontamination liability. Coverage is also provided for the cost of replacement power, which includes indemnity payments for up to three years, after a waiting period of 17 weeks. Coverage is provided primarily through mutual insurance companies owned by utilities with nuclear facilities. If losses at any of the nuclear facilities covered by the risk-sharing arrangements were to exceed the accumulated funds available from these insurance programs, SDG&E could be assessed retrospective premium adjustments of up to $6 million. Department of Energy Decommissioning The Energy Policy Act of 1992 established a fund for the decontamination and decommissioning of the Department of Energy nuclear-fuel-enrichment facilities. Utilities which have used DOE enrichment services are being assessed a total of $2.3 billion, subject to adjustment for inflation, over a 15-year period ending in 2006. Each utility's share is based on its share of enrichment services purchased from the DOE through 1992. SDG&E's annual assessment is approximately $1 million. This assessment is recovered through SONGS revenue. Litigation The company is involved in various legal matters, including those arising out of the ordinary course of business. Management believes that these matters will not have a material adverse effect on the company's results of operations, financial condition or liquidity. Electric Distribution System Conversion Under a CPUC-mandated program and through franchise agreements with various cities, SDG&E is committed, in varying amounts, to converting overhead distribution facilities to underground. As of December 31, 1998, the aggregate unexpended amount of this commitment was approximately $104 million. Capital expenditures for underground conversions were $17 million in 1998, $17 million in 1997, and $15 million in 1996. Concentration of Credit Risk The company maintains credit policies and systems to minimize overall credit risk. These policies include, when applicable, the use of an evaluation of potential counterparties' financial condition and an assignment of credit limits. These credit limits are established based on risk and return considerations under terms customarily available in the industry. SDG&E and SoCalGas grant credit to their utility customers, substantially all of whom are located in their service territories, which together cover most of Southern California and a portion of central California. SET monitors and controls its credit-risk exposures through various systems which evaluate its credit risk, and through credit approvals and limits. To manage the level of credit risk, SET deals with a majority of counterparties with good credit standing, enters into master netting arrangements whenever possible and, where appropriate, obtains collateral. Master netting agreements incorporate rights of setoff that provide for the net settlement of subject contracts with the same counterparty in the event of default. 14 REGULATORY MATTERS Electric-Industry Restructuring In September 1996, California enacted a law restructuring its electric- utility industry (AB 1890). The legislation adopts the December 1995 CPUC policy decision restructuring the industry to stimulate competition and reduce rates. Beginning on March 31, 1998, customers were given the opportunity to choose to continue to purchase their electricity from the local utility under regulated tariffs, to enter into contracts with other energy- service providers (direct access) or to buy their power from the independent Power Exchange (PX) that serves as a wholesale power pool allowing all energy producers to participate competitively. The PX obtains its power from qualifying facilities, from nuclear units and, lastly, from the lowest-bidding suppliers. The California investor-owned electric utilities (IOUs) are obligated to sell their power supply, including owned-generation and purchased-power contracts, to the PX. The IOUs are also obligated to purchase from the PX the power that they distribute. An Independent System Operator (ISO) schedules power transactions and access to the transmission system. The local utility continues to provide distribution service regardless of which source the consumer chooses. An example of these changes in the electric-utility environment is the U.S. Navy, SDG&E's largest customer. The U.S. Navy's contract to purchase energy from SDG&E was not renewed when it expired on September 30, 1998. Instead, the U.S. Navy elected to obtain energy through direct access and SDG&E continues to provide the distribution service. Utilities are allowed a reasonable opportunity to recover their stranded costs via a competition transition charge (CTC) to customers through December 31, 2001. Stranded costs include sunk costs, as well as ongoing costs the CPUC finds reasonable and necessary to maintain generation facilities through December 31, 2001. These costs also include other items SDG&E has recorded under traditional cost-of-service regulation. Certain stranded costs, such as those related to reasonable employee-related costs directly caused by restructuring, and purchased- power contracts (including those with qualifying facilities) may be recovered beyond December 31, 2001. To the extent that the opportunity to recover stranded costs is reduced by the costs to accommodate the implementation of direct access and the ISO/PX during the rate freeze, those displaced stranded costs may be recovered after December 31, 2001. Outside of those exceptions, stranded costs not recovered through 2001 will not be collected from customers. Such costs, if any, would be written off as a charge against earnings. Nuclear decommissioning costs are nonbypassable until fully recovered, but are not included as part of transition costs. Additional information is provided in Note 10. Through December 31, 1998, SDG&E has recovered transition costs of $500 million for nuclear generation and $200 million for non-nuclear generation. Excluding the costs of purchased power and other costs whose recovery is not limited to the pre-2002 period, the balance of SDG&E's stranded assets at December 31, 1998, is $600 million, consisting of $400 million for the power plants and $200 million of related deferred taxes and undercollections. In November 1997, SDG&E announced a plan to auction its power plants and other electric-generating assets. This plan includes the divestiture of SDG&E's fossil power plants and combustion turbines, its 20-percent interest in SONGS and its portfolio of long-term purchased-power contracts. The power plants, including the interest in SONGS, have a net book value as of December 31, 1998, of $400 million ($100 million for fossil and $300 million for SONGS) and a combined generating capacity of 2,400 megawatts. The proceeds from the sales, net of the costs of the sales and certain environmental cleanup costs, will be applied directly to SDG&E's transition costs. The fossil-fuel assets' auction is being separated from the auction of SONGS and the purchased-power contracts. In October 1998 the CPUC issued an interim decision approving the commencement of the fossil fuel assets' auction. On December 11, 1998, contracts were executed for the sale of SDG&E's South Bay Power Plant, Encina Power Plant and 17 combustion- turbine generators. The South Bay Power Plant is being sold to the San Diego Unified Port District for $110 million. The Encina Power Plant and the combustion-turbine generators are being sold to a special-purpose entity owned equally by Dynegy Power Corp. and NRG Energy, Inc. for $356 million. The sales are subject to regulatory approval and are expected to close during the first half of 1999. During the 1998-2001 period, recovery of transition costs is limited by the rate freeze discussed below. Management believes that rates and the proceeds from the sale of electric-generating assets will be sufficient to recover all of SDG&E's approved transition costs by December 31, 2001, not including the post-2001 purchased-power contracts payments that may be recovered after 2001. However, if 1998-2001 generation costs, principally fuel costs, are greater than anticipated, SDG&E may be unable to recover all of its approved transition costs. This would result in a charge against earnings at the time it ceases to be probable that SDG&E will be able to recover all of the transition costs. AB 1890 requires a 10-percent reduction of residential and small commercial customers' rates, beginning in January 1998, and provides for the issuance of rate-reduction bonds by an agency of the state of California to enable the IOUs to achieve this rate reduction. In December 1997, $658 million of rate-reduction bonds were issued on behalf of SDG&E at an average interest rate of 6.26 percent. These bonds are being repaid over 10 years by SDG&E's residential and small commercial customers via a nonbypassable charge on their electric bills. In 1997, SDG&E formed a subsidiary, SDG&E Funding LLC, to facilitate the issuance of the bonds. In exchange for the bond proceeds, SDG&E sold to SDG&E Funding LLC all of its rights to certain revenue streams collected from such customers. Consequently, the transaction is structured to cause such revenue streams not to be the property of SDG&E nor to be available to satisfy any claims of SDG&E's creditors. AB 1890 includes a rate freeze for all electric customers. Until the earlier of March 31, 2002, or when transition-cost recovery is complete, SDG&E's system-average rate will be frozen at the June 10, 1996, levels of 9.64 cents per kwh, except for the impact of fuel-cost changes and the 10-percent rate reduction described above. Beginning in 1998, system- average rates were fixed at 9.43 cents per kwh, which includes the maximum permitted increase related to fuel-cost increases and the mandatory rate reduction. In early 1999, SDG&E filed with the CPUC for an interim mechanism to deal with electric rates after the rate freeze ends, noting the possibility that the SDG&E rate freeze could end in 1999. As discussed in Note 2, SDG&E has been accounting for the economic effects of regulation in accordance with SFAS No. 71. The SEC indicated a concern that California's investor-owned utilities (IOUs) may not meet the criteria of SFAS No. 71 with respect to their electric-generation regulatory assets. SDG&E has ceased the application of SFAS No. 71 to its generation business, in accordance with the conclusion of the Emerging Issues Task Force of the Financial Accounting Standards Board that the application of SFAS 71 should be discontinued when legislation is issued that determines that a portion of an entity's business will no longer be subject to traditional cost-of-service regulation. The discontinuance of SFAS No. 71 applied to the IOUs' generation business did not result in a write-off of their net regulatory assets since the CPUC has approved the recovery of these assets by the distribution portion of their operations, subject to the rate freeze. In October 1997, the FERC approved key elements of the California IOUs' restructuring proposal. This included the transfer by the IOUs of the operational control of their transmission facilities to the ISO, which is under FERC jurisdiction. The FERC also approved the establishment of the California PX to operate as an independent wholesale power pool. The IOUs pay to the PX an upfront restructuring charge (in four annual installments) and an administrative-usage charge for each megawatt hour of volume transacted. SDG&E's share of the restructuring charge is approximately $10 million, which is being recovered as a transition cost. The IOUs have guaranteed $300 million of commercial loans to the ISO and PX for their development and initial start-up. SDG&E's share of the guarantee is $30 million. Thus far, electric-industry deregulation has been confined to generation. Transmission and distribution have remained subject to traditional cost-of-service regulation. However, the CPUC is exploring the possibility of opening up electric distribution to competition. During 1999, the CPUC will be conducting a rulemaking, one objective of which may be to develop a coordinated proposal for the state legislature regarding how various distribution competition issues should be addressed. SDG&E and SoCalGas will actively participate in this effort. Gas Industry Restructuring The natural gas industry experienced an initial phase of restructuring during the 1980s by deregulating gas sales to noncore customers. On January 21, 1998, the CPUC released a staff report initiating a project to assess the current market and regulatory framework for California's natural gas industry. The general goals of the plan are to consider reforms to the current regulatory framework emphasizing market-oriented policies benefiting California natural gas consumers. On August 25, 1998, California adopted a law prohibiting the CPUC from enacting any natural gas industry restructuring decision for customers prior to January 1, 2000. During the implementation moratorium, the CPUC will hold hearings throughout the state and intends to give the California Legislature a report for its review detailing specific recommendations for changing the natural gas market within California. SDG&E and SoCalGas will actively participate in this effort. Performance-Based Regulation (PBR) To promote efficient operations and improved productivity and to move away from reasonableness reviews and disallowances, the CPUC has been directing utilities to use PBR. PBR has replaced the general rate case and certain other regulatory proceedings for both SoCalGas and SDG&E. Under PBR, regulators require future income potential to be tied to achieving or exceeding specific performance and productivity measures, as well as cost reductions, rather than relying solely on expanding utility rate base in a market where a utility already has a highly developed infrastructure. SoCalGas' PBR is in effect through December 31, 2002; however, the CPUC decision allows for the possibility that changes to the PBR mechanism could be adopted in a decision to be issued in SoCalGas' 1999 Biennial Cost Allocation Proceeding, which is anticipated to become effective before year end 1999. Key elements of the SoCalGas PBR include an initial reduction in base rates, an indexing mechanism that limits future rate increases to the inflation rate less a productivity factor, a sharing mechanism with customers if earnings exceed the authorized rate of return on rate base, and rate refunds to customers if service quality deteriorates. Specifically, the key elements of SoCalGas' PBR include the following: - --Earnings up to 25 basis points in excess of the authorized rate of return on rate base are retained 100 percent by shareholders. Earnings that exceed the authorized rate of return on rate base by greater than 25 basis points are shared between customers and shareholders on a sliding scale that begins with 75 percent of the additional earnings being given back to customers and declining to 0 percent as earned returns approach 300 basis points above authorized amounts. There is no sharing if actual earnings fall below the authorized rate of return. In 1999, SoCalGas is authorized to earn a 9.49 percent return on rate base, the same as in 1998. - --Revenue or base margin per customer is indexed based on inflation less an estimated productivity factor of 2.1 percent in the first year (1998), increasing 0.1 percent per year up to 2.5 percent in the fifth year (2002). This factor includes 1 percent to approximate the projected impact of a declining rate base. - --The CPUC decision allows for pricing flexibility for residential and small commercial customers, with any shortfalls in revenue being borne by shareholders and with any increase in revenue shared between shareholders and customers. Under SoCalGas' PBR, annual cost of capital proceedings are replaced by an automatic adjustment mechanism if changes in certain indices exceed established tolerances. The mechanism is triggered if the 12-month trailing average of actual market interest rates increases or decreases by more than 150 basis points and is forecasted to continue to vary by at least 150 basis points for the next year. If this occurs, there would be an automatic adjustment of rates for the change in the cost of capital according to a preestablished formula which applies a percentage of the change to various capital components. SDG&E continues to participate in a PBR process for base rates for its electric and natural gas distribution business. In conjunction therewith, in December 1998, a Cost of Service settlement agreement among SDG&E, the CPUC's Office of Ratepayers' Advocates (ORA) and the Utility Consumers' Action Network (UCAN) was approved by the CPUC, resulting in an authorized revenue increase of $12 million (an electric-distribution increase of $18 million and a natural gas decrease of $6 million). The electric-distribution increase does not affect rates during the rate freeze and, therefore, reduces the amount available for transition cost recovery. Revised rates were effective January 1, 1999. In January 1999, an administrative law judge's proposed decision was issued on SDG&E's distribution PBR application. The proposed decision recommends a revenue-per-customer indexing mechanism (similar to the indexing mechanism in SoCalGas' PBR) rather than the rate-indexing mechanism proposed by SDG&E. In addition, the proposed decision recommends much tighter earnings sharing bands (similar to SoCalGas'). The performance indicators are as adopted in the settlement agreement, including employee safety, electric reliability, customer satisfaction, call-center responsiveness and electric-system maintenance. SDG&E would be authorized to earn or be penalized up to a maximum of $14.5 million annually as a result of its performance in those areas. Comprehensive Settlement Of Natural Gas Regulatory Issues In July 1994, the CPUC approved a comprehensive settlement for SoCalGas (Comprehensive Settlement) of a number of regulatory issues, including rate recovery of a significant portion of the restructuring costs associated with certain long-term contracts with suppliers of California- offshore and Canadian natural gas. In the past, the cost of these supplies had been substantially in excess of SoCalGas' average delivered cost for all natural gas supplies. The restructured contracts substantially reduced the ongoing delivered costs of these supplies. The Comprehensive Settlement permits SoCalGas to recover in utility rates approximately 80 percent of the contract-restructuring costs of $391 million and accelerated amortization of related pipeline assets of approximately $140 million, together with interest, incurred prior to January 1, 1999. In addition to the supply issues, the Comprehensive Settlement addressed the following other regulatory issues: - --Noncore Customer Rates. The Comprehensive Settlement changed the procedures for determining noncore rates to be charged by SoCalGas for the five-year period commencing August 1, 1994. These rates are based upon SoCalGas' recorded throughput to these customers for 1991. SoCalGas will bear the full risk of any declines in noncore deliveries from 1991 levels. Any revenue enhancement from deliveries in excess of 1991 levels will be limited by a crediting account mechanism that will require a credit to customers of 87.5 percent of revenues in excess of certain limits. These annual limits above which the credit is applicable increase from $11 million to $19 million over the five-year period from August 1, 1994, through July 31, 1999. SoCalGas' ability to report as earnings the results from revenues in excess of SoCalGas' authorized return from noncore customers due to volume increases has been limited for the five years beginning August 1, 1994, as a result of the Comprehensive Settlement. The 1999 Biennial Cost Allocation Proceeding is intended to adopt measures to replace this aspect of the Comprehensive Settlement when it expires during 1999. - --Gas Cost Incentive Mechanism (GCIM). On April 1, 1994, SoCalGas implemented a new process for evaluating its natural gas purchases, substantially replacing the previous process of reasonableness reviews. Initially a three-year pilot program, in December 1998 the CPUC extended the GCIM program indefinitely. Automatic annual extensions to the program will continue unless the CPUC issues an order stating otherwise. GCIM compares SoCalGas' cost of natural gas with a benchmark level, which is the average price of 30-day firm spot supplies in the basins in which SoCalGas purchases the natural gas. 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 equally between customers and shareholders. The CPUC approved the use of natural gas futures for managing risk associated with the GCIM. SoCalGas enters into natural gas futures contracts in the open market on a limited basis to mitigate risk and better manage natural gas costs. In June 1997, SoCalGas requested a shareholder award of $11 million, which was approved by the CPUC in June 1998 and is included in pretax income in 1998. In June 1998, SoCalGas filed its annual GCIM application with the CPUC requesting an award of $2 million for the annual period ended March 31, 1998. This request was approved by the CPUC in December 1998 and is included in pretax income in 1998. - --Attrition Allowances. The Comprehensive Settlement authorized SoCalGas an annual allowance for increases in operating and maintenance expenses. However, no attrition allowance was authorized for 1997 and beyond, based on an agreement reached as part of the PBR application. PE and SoCalGas recorded the impact of the Comprehensive Settlement in 1993. Upon giving effect to liabilities previously recognized by the companies, the costs of the Comprehensive Settlement, including the restructuring of natural gas supply contracts, did not result in any future charge to PE's earnings. Biennial Cost Allocation Proceeding (BCAP) In the second quarter of 1997, the CPUC issued a decision on SoCalGas' 1996 BCAP filing. In this decision, the CPUC considered SoCalGas' relinquishments of interstate pipeline capacity on both the El Paso and Transwestern pipelines. This resulted in a reduction in the pipeline demand charges allocated to SoCalGas' customers and surcharges allocated to firm capacity holders through pipeline rate-case settlements adopted at the FERC. However, the CPUC and FERC are reviewing the decision. In October 1998, SoCalGas and SDG&E filed 1999 BCAP applications requesting that new rates become effective August 1, 1999 and remain in effect through December 31, 2002. The proposed beginning date follows the conclusion of the Comprehensive Settlement (discussed above), and the proposed end date aligns with the expiration of SoCalGas' and SDG&E's PBRs. The applications seek overall decreases in natural gas revenues of $204 million for SoCalGas and $9 million for SDG&E. Cost of Capital Under PBR, annual Cost of Capital proceedings were replaced by an automatic adjustment mechanism if changes in certain indices exceed established tolerances. For 1999, SoCalGas is authorized to earn a rate of return on common equity (ROE) of 11.6 percent and a 9.49 percent return on rate base (ROR), the same as in 1998, unless interest-rate changes are large enough to trigger an automatic adjustment as discussed above under "Performance-Based Regulation." For SDG&E, electric-industry restructuring is changing the method of calculating the utility's annual cost of capital. In May 1998, SDG&E filed with the CPUC its unbundled Cost of Capital application for 1999 rates. The application seeks approval to establish new, separate rates of return for SDG&E's electric- distribution and natural gas businesses. The application proposes a 12.00 percent ROE, which would produce an overall ROR of 9.33 percent. The ORA, UCAN and other intervenors have filed testimony recommending significantly lower RORs. The ORA is recommending an electric ROR of 7.68 percent and a gas ROR of 8.01 percent. A CPUC decision is expected during the second quarter of 1999. In 1998, SDG&E's electric and natural gas distribution operations were authorized to earn an ROE of 11.6 percent and an ROR of 9.35 percent, unchanged from 1997. In addition, the authorized rates of return on nuclear and non-nuclear generating assets are 7.14 percent and 6.75 percent, respectively. Transactions Between Utilities and Affiliated Companies On December 16, 1997, the CPUC adopted rules, effective January 1, 1998, establishing uniform standards of conduct governing the manner in which IOUs conduct business with their energy-related affiliates. The objective of the affiliate-transaction rules is to ensure that these affiliates do not gain an unfair advantage over other competitors in the marketplace and that utility customers do not subsidize affiliate activities. The rules establish standards relating to non-discrimination, disclosure and information exchange, and separation of activities. The CPUC excluded utility-to-utility transactions between SDG&E and SoCalGas from the affiliate-transaction rules in its March 1998 decision approving the business combination of Enova and PE (see Note 1). 15 SEGMENT INFORMATION The company, primarily an energy-services company, has three separately managed reportable segments comprised of SoCalGas, SDG&E and Sempra Energy Trading (SET). The two utilities operate in essentially separate service territories under separate regulatory frameworks and rate structures set by the CPUC. As described in Note 1, SDG&E provides electric and natural gas service to San Diego and southern Orange counties. SoCalGas is a natural gas distribution utility, serving customers throughout most of Southern California and part of central California. SET is based in Stamford, Connecticut, and is engaged in the nationwide wholesale trading and marketing of natural gas, power and petroleum. The accounting policies of the segments are the same as those described in Note 2, and segment performance is evaluated by management based on reported net income. Intersegment transactions generally are recorded the same as sales or transactions with third parties. Utility transactions are primarily based on rates set by the CPUC and FERC. - ----------------------------------------------------------------- For the year ended December 31 (Dollars in millions) 1998 1997 1996 - ----------------------------------------------------------------- Operating Revenues: Southern California Gas $2,427 $2,641 $2,422 San Diego Gas & Electric 2,749 2,167 1,939 Sempra Energy Trading 110 - - Intersegment revenues (59) (55) (60) All other 254 316 195 ------------------------------ Total $5,481 $5,069 $4,496 ------------------------------ Interest Revenue: Southern California Gas $4 $16 $5 San Diego Gas & Electric 40 9 7 Sempra Energy Trading 3 - - All other interest 3 21 23 ------------------------------ Total interest 50 46 35 Sundry income (loss) (6) 12 (7) ------------------------------ Total other income $44 $58 $28 ------------------------------ Depreciation and Amortization: Southern California Gas $254 $251 $248 San Diego Gas & Electric (See Note 14) 603 324 314 Sempra Energy Trading 13 - - All other 59 29 25 ------------------------------ Total $929 $604 $587 ------------------------------ Interest Expense: Southern California Gas $80 $87 $86 San Diego Gas & Electric 116 86 91 Sempra Energy Trading 5 - - All other 6 33 23 ------------------------------ Total $207 $206 $200 ------------------------------ Income Tax Expense (Benefit): Southern California Gas $128 $178 $148 San Diego Gas & Electric 142 219 198 Sempra Energy Trading (9) - - All other (123) (96) (46) ------------------------------ Total $138 $301 $300 ------------------------------ Net Income: Southern California Gas $158 $231 $193 San Diego Gas & Electric 185 232 216 Sempra Energy Trading (13) - - All other (36) (31) 18 ------------------------------ Total $294 $432 $427 ------------------------------ - ----------------------------------------------------------------- At December 31, or for the year then ended (Dollars in millions) 1998 1997 1996 - ----------------------------------------------------------------- Assets: Southern California Gas $3,834 $4,205 $4,354 San Diego Gas & Electric 4,257 4,654 4,161 Sempra Energy Trading 1,225 846 - All other 1,253 1,181 1,257 Eliminations (113) (130) (10) ------------------------------ Total $10,456 $10,756 $9,762 ------------------------------ Capital Expenditures: Southern California Gas $128 $159 $197 San Diego Gas & Electric 227 197 209 Sempra Energy Trading - - - All other 83 41 7 ------------------------------ Total $438 $397 $413 ------------------------------ Geographic Information: Long-lived assets: United States $5,849 $5,904 $6,647 Latin America 140 67 50 ------------------------------ Total $5,989 $5,971 $6,697 ------------------------------ Operating Revenues: United States $5,474 $5,058 $4,488 Latin America 7 11 8 ------------------------------ Total $5,481 $5,069 $4,496 - ----------------------------------------------------------------- 16 SUBSEQUENT EVENT On February 22, 1999, the company and KN Energy, Inc. (KN Energy) announced that their respective boards of directors approved the company's acquisition of KN Energy, subject to approval by the shareholders of both companies and by various federal and state regulatory agencies. If the transaction is approved, holders of KN Energy common stock will receive 1.115 shares of company common stock or $25 in cash, or some combination thereof, for each share of KN Energy common stock. In the aggregate, the cash portion of the transaction will constitute not more than 30 percent of the total consideration of $1.7 billion. The companies anticipate that the closing will occur in six to eight months. The transaction will be treated as a purchase for accounting purposes. INDEPENDENT AUDITORS' REPORT To the Board of Directors and Shareholders of Sempra Energy San Diego, California We have audited the consolidated financial statements of Sempra Energy and subsidiaries as of December 31, 1998 and 1997 and for each of the three years in the period ended December 31, 1998, and have issued our unqualified report thereon dated January 27, 1999, except for Note 16 as to which the date is February 22, 1999. Our audits also included the Supplemental Schedule of Summarized Financial Information. This schedule of summarized financial information is the responsibility of Sempra Energy's management. Our responsibility is to express an opinion based on our audits. In our opinion, such schedule of summarized financial information, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein. /S/ DELOITTE & TOUCHE LLP San Diego, California January 27, 1999, except for Note 16 as to which the date is February 22, 1999 Supplemental Schedule of Summarized Financial Information Sempra Energy Holdings, Inc. (in millions of dollars) December 31, 1998 1997 Current Assets $1,470 $ 778 Non-current Assets 544 619 Current Liabilities 1,452 663 Non-current Liabilities 140 205 Year Ended December 31, 1998 1997 1996 Operating Revenues $ 572 $ 526 $ 301 Operating Expenses 667 585 319 Net Loss 54 17 4 Note 1: Basis of Presentation The summarized financial information as of December 31, 1998 and December 31, 1997 and for each of the three years in the period ended December 31, 1998 includes certain subsidiaries of Sempra Energy that are not subject to California utility regulation (principally Sempra Energy Solutions, Sempra Energy Trading, CES/Way, Sempra Energy Resources and Sempra Energy International) at the dates and for the periods they were owned by Sempra Energy. Although not all of the enterprises included in the summarized financial information were owned by Holdings as of those dates or for those years, they all were owned (directly or indirectly) by Sempra Energy or by one of its predecessor companies (Pacific Enterprises and Enova Corporation) at the dates and for the periods for which they are included, and they all are currently owned (directly or indirectly) by Holdings. 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: May 5, 1999 By: /S/F.H. AULT ---------------- --------------------------- F. H. Ault Vice President and Controller
                                                  EXHIBIT 23.1


We consent to the incorporation by reference in Registration 
Statement Number 333-51309 on Form S-3 and Registration Statement 
Number 333-56161 on Form S-8 of Sempra Energy of our report dated 
January 27, 1999, except for Note 16 as to which the date is February 
22, 1999 on the Supplemental Schedule of Summarized Financial 
Information appearing in this Current Report on Form 8-K dated May 5, 


San Diego, California
May 5, 1999