-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Ffmk2PqkTQJ0UkRe9QgslSiyVBIkOmsu7bVkuqgtClcxd7r2oOOdC/gw8M4HNb11 88dz7cSF7ajuegVSzAHd5w== 0000940170-98-000003.txt : 19980302 0000940170-98-000003.hdr.sgml : 19980302 ACCESSION NUMBER: 0000940170-98-000003 CONFORMED SUBMISSION TYPE: 10-K/A PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 19971231 FILED AS OF DATE: 19980227 SROS: AMEX SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: ENOVA CORP CENTRAL INDEX KEY: 0000940170 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 330643023 STATE OF INCORPORATION: CA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K/A SEC ACT: SEC FILE NUMBER: 001-11439 FILM NUMBER: 98552760 BUSINESS ADDRESS: STREET 1: POST OFFICE BOX 1831 CITY: SAN DIEGO STATE: CA ZIP: 92112-4150 BUSINESS PHONE: 6196962000 MAIL ADDRESS: STREET 1: 101 ASH STREET CITY: SAN DIEGO STATE: CA ZIP: 92101 FORMER COMPANY: FORMER CONFORMED NAME: SDO PARENT CO /CA DATE OF NAME CHANGE: 19950303 10-K/A 1 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K/A AMENDMENT 1 (Mark One) [X] Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 1997 OR [ ] Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from to Exact Name of Commission Registrant IRS Employer File as specified State of Identification Number in its charter Incorporation Number - ---------- -------------- -------------- -------------- 1-3779 SAN DIEGO GAS & ELECTRIC COMPANY California 95-1184800 1-11439 ENOVA CORPORATION California 33-0643023 101 ASH STREET, SAN DIEGO, CALIFORNIA 92101 - ----------------------------------------- ---------- (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (619)696-2000 -------------- SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: Name of each exchange Title of each class on which registered - ------------------- --------------------- San Diego Gas & Electric Company Preference Stock (Cumulative) Without Par Value (except $1.70 and $1.7625 Series) American Cumulative Preferred Stock, $20 Par Value (except 4.60% Series) American Enova Corporation Common Stock, Without Par Value New York and Pacific SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: San Diego Gas & Electric Company None Enova Corporation None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. Yes [ X ] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] Exhibit Index on page 90. Glossary on page 98. Aggregate market value of the voting stock held by non-affiliates of the registrant as of January 31, 1998: Enova Corporation Common Stock $2.9 Billion San Diego Gas & Electric Company Preferred Stock $22 Million Common Stock outstanding without par value as of January 31, 1998: Enova Corporation 113,606,162 San Diego Gas & Electric Company Wholly owned by Enova Corporation DOCUMENTS INCORPORATED BY REFERENCE: Portions of the March 1998 Proxy Statement prepared for the April 1998 annual meeting of shareholders are incorporated by reference into Part III. 1 ENOVA CORPORATION FORM 10-K/A AMENDMENT 1 The undersigned registrant hereby amends Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, and Item 8, Financial Statements and Supplementary Data, of its Annual Report for 1997 on Form 10-K as set forth in the pages attached hereto. In these items, the following modifications have been made: in the second paragraph on page 26 and the second paragraph of Note 1 on page 58, in both places, the word "shareholder" should be replaced by the word "shareable." Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this amendment to be signed on its behalf by the undersigned thereunto duly authorized. Date: February 27, 1998 By: /s/ F. H. Ault _____________________________ Vice President and Controller 2 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- Enova Corporation/San Diego Gas & Electric Company GENERAL Enova Corporation (referred to herein as Enova, which includes the parent and its wholly owned subsidiaries) was formed in January 1996 to become the parent company of San Diego Gas & Electric (SDG&E). At that time SDG&E's outstanding common stock was converted on a share-for-share basis into Enova Corporation common stock. SDG&E's debt securities, preferred stock and preference stock were unaffected and remained with SDG&E. SDG&E is an operating public utility engaged in the electric and gas businesses. It generates and purchases electric energy and distributes it to 1.2 million customers in San Diego County and an adjacent portion of Orange County, California. It also purchases and distributes natural gas to 721,000 customers in San Diego County and transports electricity and gas for others. California has enacted an electric-restructuring law that affects the operations of SDG&E and the other California investor-owned electric utilities. This information is discussed below under "Electric Industry Restructuring." Enova has several other subsidiaries (referred to herein as nonutility subsidiaries). Enova Financial invests in limited partnerships representing approximately 1,200 affordable-housing properties located throughout the United States. Califia leases computer equipment. These two subsidiaries are expected to provide income tax benefits over the next several years. Enova International is involved in energy projects outside the United States. Pacific Diversified Capital is the parent company of Phase One Development, which has been involved in real estate development. Enova Energy is an energy management and consulting firm offering services to utilities and large consumers. In December 1997, subsidiaries of Enova Energy and Houston Industries formed a joint venture, El Dorado Energy, to build, own and operate a natural gas-fired power plant in Boulder City, Nevada. Enova Technologies is in the business of developing new technologies generally related to utilities and energy. In January 1997, Enova Energy, Enova Technologies and certain subsidiaries of Pacific Enterprises (discussed below) formed Energy Pacific, a joint venture to market integrated energy and energy- related products and services. Energy Pacific has recently changed its name to Sempra Energy Solutions. In January 1998, Sempra Energy Solutions completed the acquisition of CES/Way International, a leading national energy-service provider. In December 1997, Enova and Pacific Enterprises completed the joint acquisition of AIG Trading Corporation (AIG), a leading natural gas and power marketing firm based in Greenwich, Connecticut. AIG has subsequently changed its name to Sempra Energy Trading. Additional information regarding Enova's nonutility subsidiaries is described herein under "Electric Generation" and "Liquidity and Capital Resources - Investing Activities," and in Notes 1, 2 and 3 of the notes to consolidated financial statements. BUSINESS COMBINATION In October 1996, Enova and Pacific Enterprises (PE), parent company of Southern California Gas Company (SoCalGas), announced that they have agreed to combine the two companies. Enova and PE have selected Sempra Energy as the name of the new company formed by the business combination. As a result of the combination, which was unanimously approved by the boards of directors of both companies, (i) each outstanding share of common stock of Enova will be converted into one share of common stock of Sempra Energy, (ii) each outstanding share of common stock of PE will be converted into 1.5038 shares of Sempra Energy's common stock and (iii) the preferred stock and preference stock 25 of SDG&E, PE and SoCalGas will remain outstanding. In March 1997, the shareholders of Enova and PE approved the combination. Consummation of the combination is conditional upon the approvals of the California Public Utilities Commission (CPUC) and various other regulatory bodies (see below). In June 1997, the CPUC revised its procedural schedule for the business combination after delaying until July 1997 its final decision on the Performance-Based Ratemaking (PBR) proceeding for SoCalGas. (The CPUC's decision on SoCalGas' PBR proceeding adopted a rate-setting mechanism for SoCalGas that provides incentives for cost control and efficiency improvement, including comparisons of productivity and other factors against benchmarks based on industry performance. SoCalGas had been operating under traditional "cost of service" regulation. The decision provides for, among other things, a net rate reduction of $160 million.) In accordance with the CPUC's revised schedule, the administrative law judge handling the proceeding issued a draft decision on February 23, 1998. That draft decision proposed approval of the combination. Among other things, the draft decision proposed 50/50 sharing of the net cost savings resulting from the combination between shareholders and customers, but only for five years rather than the 10 years sought. The draft decision would reduce the net shareable savings from $1.1 billion to $340 million. The CPUC decision is scheduled for the end of March 1998. In November 1997, the California attorney general issued an advisory opinion concluding that the business combination would not adversely affect competition within either the wholesale electricity or interstate gas markets. The opinion included a recommendation that the CPUC consider requiring SoCalGas to auction offsetting volumes of natural gas transportation rights equal to the load with SDG&E that will be withdrawn if the CPUC concludes that SDG&E would be eliminated as a potential competitor in the partially regulated intrastate gas transmission market. In September 1997, the CPUC staff issued a final Negative Declaration, concluding that the business combination will not result in any activities or operational changes that may cause a significant adverse effect on the environment. In June 1997, the Federal Energy Regulatory Commission (FERC) approved the business combination, subject to the conditions that the combined company will not unfairly use any potential market power regarding natural gas transportation to gas-fired electric-generation plants. The FERC acknowledged that this issue is clearly within the jurisdiction of the CPUC and the conditions will be considered during the CPUC review process. Therefore, the FERC's final decision is not expected to be issued before the CPUC's approval. In August 1997, the Nuclear Regulatory Commission approved the business combination, ruling that the creation of the new company will not affect SDG&E's qualifications to hold the license for its 20-percent interest in the San Onofre Nuclear Generating Station (SONGS). Remaining regulatory reviews, which are not expected to be concluded prior to the CPUC decision, include clearance by the U.S. Department of Justice, under the Hart-Scott-Rodino Antitrust Act, and approval by the Securities and Exchange Commission. Both agencies will review the business combination for its impacts on competition. The commencement of combined operations is expected in the summer of 1998. Earnings of the combined company could be negatively impacted in 1998, and to a lesser extent in subsequent years, by delays in achieving cost savings from the combination caused by the later-than- expected effective combination date, CPUC limitations on transactions between SDG&E and SoCalGas, which may be modified by the CPUC combination proceedings (discussed below), the possibility that the CPUC 26 might not permit recovery of certain costs of the combination and might reduce the period or percentage for shareholder participation in the related cost savings, and slower-than-anticipated growth in revenues from Sempra Energy Solutions. Additional information regarding the proposed business combination is described in Note 1 of the notes to consolidated financial statements. RESULTS OF OPERATIONS Operating Results Electric revenues increased 11 percent in 1997, primarily due to an increase in sales for resale to other utilities and increased retail sales volume due to weather. Electric revenues increased 6 percent in 1996, primarily due to the accelerated recovery of SONGS Units 2 and 3 which commenced in April 1996. Gas revenues increased 14 percent in 1997, primarily due to weather-related higher sales volume and higher purchased-gas prices, offset by an increase in customer purchases of gas directly from other suppliers (for whom SDG&E provides transportation). Gas revenues increased 12 percent in 1996, reflecting higher purchased-gas prices. Operating Expenses Electric fuel expense increased 22 percent in 1997, primarily due to increased natural gas prices and increased natural gas- fired generation resulting from SONGS Units 2 and 3 refuelings. Electric fuel expense increased 34 percent in 1996, primarily due to increased generation and increases in natural gas prices. Purchased-power expenses increased 42 percent in 1997, primarily due to increased volume, which resulted from lower nuclear-generation availability from the SONGS refuelings and increased use of purchased power due to decreased purchased-power prices. Purchased-power expenses decreased 9 percent in 1996, reflecting the availability of lower-cost nuclear generation and decreases in purchased-power capacity charges. Gas purchased for resale increased 20 percent in 1997 and 34 percent in 1996, primarily due to increases in sales volume and in natural gas prices. The changes in maintenance expenses reflect the nuclear refuelings in 1997 and 1995. General and administrative expenses decreased 15 percent in 1997, primarily due to higher 1996 costs for customer service, partially offset by the expenses relating to the proposed business combination with Pacific Enterprises. Earnings 1997 earnings per common share were $2.20 compared to $1.98 in 1996 and $1.94 in 1995. The increase in earnings in 1997 is primarily due to incentive rewards for Performance-Based Ratemaking (PBR) and Demand-Side Management (DSM) programs, retirements of debt and common shares, and improved earnings of Enova Financial, partially offset by expenses relating to the proposed business combination with Pacific Enterprises. Other events that improved 1997 earnings included income tax benefits from the 1995 sale of Wahlco Environmental Systems and capital gains from the sale of property held by Pacific Diversified Capital. The increase in earnings in 1996 is primarily due to DSM rewards, partially offset by SDG&E's lower authorized return on equity. Earnings per share for the quarter ended December 31, 1997, were $0.72, compared to $0.47 for the same period in 1996. The increase in earnings for the quarter was due to numerous offsetting factors, including PBR and DSM rewards, retirement of common shares, higher off- system electric sales, previously announced seasonal variability related to the elimination of electric balancing accounts, and expenses relating to the proposed business combination with Pacific Enterprises. Although the elimination of the balancing accounts did not have any effect on 1997 full-year earnings, quarterly earnings now fluctuate significantly, depending on monthly or seasonal changes in electric sales and fuel 27 prices. In general, earnings are expected to be higher in high sales- volume months and lower in others. In 1998 and future years, full-year earnings also will be affected by sales volumes. Some of the PBR rewards recorded in 1997 had been pending with the CPUC for several years. During 1998, SDG&E will not have a multiple-year backlog of these PBR rewards to record. In addition, because of the elimination of the Generation and Dispatch PBR mechanism and the San Onofre Nuclear Generating Station Target Capacity Factor mechanism, the impact of performance rewards on future earnings will be reduced. Califia and Enova Financial's contributions to earnings for the year were $0.21 in 1997, $0.19 in 1996 and $0.17 in 1995. Contributions to earnings by Enova Energy and Enova Technologies were negatively impacted in 1997 by the slower-than-anticipated growth in revenues from Sempra Energy Solutions. LIQUIDITY AND CAPITAL RESOURCES SDG&E's operations continue to be a major source of liquidity. In addition, financing needs are met primarily through issuances of short- term and long-term debt. These capital resources are expected to remain available. Cash requirements include utility capital expenditures, nonutility subsidiaries' investments, and repayments and retirements of long-term debt. Nonutility cash requirements include capital expenditures associated with subsidiary activities related to the plans to distribute natural gas in Mexico and the eastern United States; new products; investments in Sempra Energy Trading, CES/Way International and El Dorado Energy; and affordable-housing, leasing and other investments. Additional information on these activities is discussed under "Cash Flows from Investing Activities" below. In addition to changes described elsewhere, major changes in cash flows are described below. Cash Flows from Operating Activities The major changes in cash flows from operations among the three years result from changes in income taxes, accounts receivable, other current assets, accounts payable, and regulatory balancing accounts. The changes in cash flows related to income taxes were primarily due to the timing of certain deductions in 1997 and higher 1996 income tax payments in connection with settlements with the Internal Revenue Service. The changes in cash flows related to accounts and notes receivable were primarily due to increases in sales in December 1997. The changes in cash flows related to other current assets were primarily due to advances made to unconsolidated subsidiaries during late 1997. The changes in cash flows related to accounts payable were primarily due to fluctuations in natural gas purchases and prices from year to year. The changes in cash flows related to regulatory balancing accounts were primarily due to overcollections in the Electric Revenue Adjustment Mechanism (ERAM) account as a result of higher-than-authorized sales volumes in 1997 and changes in prices for natural gas in 1996. Quarterly cash dividends of $0.39 per share were declared for the year ended December 31, 1997. The dividend payout ratios for the years ended December 31, 1997, 1996, 1995, 1994 and 1993 were 71 percent, 79 percent, 80 percent, 130 percent, and 82 percent, respectively. The increase in the payout ratio for the year ended December 31, 1994, was due to writedowns recorded during 1994. For additional information regarding the writedowns, see Enova Corporation's 1996 Annual Report. The payment of future dividends is within the discretion of the Enova Board of Directors and is dependent upon future business conditions, earnings and other factors. Net cash flows provided by operating activities currently are sufficient to maintain the payment of dividends at the present level. 28 Enova has initiated an enterprise-wide program to prepare the company's computer systems and applications for the year 2000 and beyond. A comprehensive review has been conducted to identify the systems that could be affected by the year 2000 issue and an implementation plan has been developed. The year 2000 issue results from time-sensitive software applications that recognize a date using only two digits. For example, "00" may be recognized as the year 1900 rather than the year 2000. This could result in a system failure or miscalculations. This year 2000 problem creates risk for the company from unforeseen problems in its own computer systems and from third parties with whom the company deals on financial transactions. Management has not yet assessed whether the company's date-conversion project will be completed on a timely basis nor the impact of third- party computer system failures. The company expects to incur internal staff costs as well as consulting and other expenses related to infrastructure and facilities enhancements necessary to prepare the systems for the year 2000. Expenditures for the testing and conversion of system applications were $4 million in 1997 and are expected to be between $20 million and $25 million over the next two years. These costs are expensed as incurred. Cash Flows from Financing Activities Enova did not issue additional stock or long-term debt in 1997, except for SDG&E-related refinancings and electric industry restructuring-related rate-reduction bonds. Additional information concerning the rate-reduction bonds is discussed below and under "Electric Industry Restructuring." Enova and SDG&E do not plan any issuances in 1998. In October 1997, SDG&E issued $25 million of tax-exempt Industrial Development Bonds (IDBs) through the City of Chula Vista. The variable- rate bonds were issued at an initial rate of 3.5 percent. The proceeds from the bonds, which will mature in 2023, were used to redeem $25 million of 8.75 percent IDBs with the City of San Diego. Also during 1997, SDG&E purchased and retired $62 million of 9.625 percent and 8.5 percent first mortgage bonds. In December 1997, $658 million of rate-reduction bonds were issued on SDG&E's behalf at an average interest rate of 6.26 percent. A portion of the bond proceeds was used to retire $14.9 million of variable-rate, taxable IDBs in December 1997 and $15.7 million of variable-rate, taxable IDBs in January 1998. Additional retirements are planned. Additional information concerning the rate-reduction bonds is provided below under "Electric Industry Restructuring." SDG&E currently has approximately $83 million of temporary investments that will be maintained into the future. The purpose of maintaining such a level of investments is to offset a like amount of long-term debt. The specific debt series being offset consists of variable-rate IDBs. The CPUC has approved specific ratemaking treatment which allows SDG&E to offset IDBs as long as there is at least a like amount of temporary investments. If and when SDG&E requires all or a portion of the $83 million of IDBs to meet future needs for long-term debt, such as to finance new construction, the amount of investments which is being maintained will be reduced below $83 million and the level of IDBs being offset will be reduced by the same amount. During 1997, Enova Corporation repurchased three million shares of its outstanding common stock. During 1998, the $1.82-series preferred stock becomes callable at $26 per share. SDG&E maintains its capital structure so as to obtain long-term financing at the lowest possible rates. The following table shows the percentages of capital represented by the various components. In 1993 the capital structure is net of the construction funds held by a trustee. 29 1993 1994 1995 1996 1997 Goal ----------- (A) (B) (A) - ------------------------------------------------------------------------ Common equity 47 % 48 % 49 % 50 % 51 % 41 % 46-49 % Preferred stock 4 4 4 4 4 3 3-5 Debt and leases 49 48 47 46 45 56 46-49 - ------------------------------------------------------------------------ Total 100 % 100 % 100 % 100 % 100 % 100 % 100 % - ------------------------------------------------------------------------ (A) Excludes rate reduction bonds ($658 million at December 31, 1997). (B) Includes rate reduction bonds ($658 million at December 31, 1997). The CPUC regulates SDG&E's capital structure, limiting the dividends it may pay Enova. At December 31, 1997, $152 million of common equity was available for future dividends. In addition, at December 31, 1997, approximately one half of the $658 million of rate-reduction bonds was also available for future dividends. Of this available amount, $100 million in dividends were paid by SDG&E to Enova on January 2, 1998, in conjunction with the acquisition of Sempra Energy Trading. This restriction is not expected to affect Enova's ability to meet its cash obligations. In December 1997, Moody's Investors Service upgraded SDG&E's long- term-bond rating from an A1/stable outlook to an A1/positive outlook, reflecting SDG&E's business mix, which is heavily weighted toward distribution and transmission. The outlook upgrade also reflects the probability of recovery of stranded costs and the expected proceeds from the sale of generating assets (see discussion under "Electric Generation"). Standard & Poor's Ratings Group affirmed SDG&E's long- term-bond rating of A+/positive outlook. Cash Flows from Investing Activities Cash used in investing activities in 1997 included SDG&E's construction expenditures and payments to its nuclear decommissioning trusts. SDG&E's capital expenditures were $197 million in 1997 and are estimated to be $242 million in 1998. Actual capital expenditures in 1997 were lower than anticipated due to changes in the scope and timing of several major capital projects. Estimated 1998 capital expenditures are closer to normal levels, with increases to meet industry restructuring needs and improvements to the electric distribution system. SDG&E continuously reviews its construction, investment and financing programs and revises them in response to changes in competition, customer growth, inflation, customer rates, the cost of capital, and environmental and regulatory requirements. Among other things, the level of expenditures in the next few years will depend heavily on the impacts of industry restructuring and the sale of SDG&E's Encina and South Bay power plants and other electric-generating assets, as well as the timing and extent of expenditures to comply with air-emission reduction and other environmental requirements. Additional information concerning the proposed sale of SDG&E's electric-generating assets is provided below under "Electric Generation." Payments to the nuclear-decommissioning trusts are expected to continue until SONGS is decommissioned, which is not expected to occur before 2013. Although Unit 1 was permanently shut down in 1992, it is scheduled to be decommissioned concurrently with Units 2 and 3. However, this will depend on the outcome of the proposed sale of SDG&E's electric-generating assets, including its interest in SONGS. Enova's level of nonutility expenditures in the next few years will depend primarily on the activities of its subsidiaries other than SDG&E, including Sempra Energy Solutions and the natural gas distribution projects in Mexico and the eastern United States. Nonutility expenditures were $158 million in 1997 and are estimated to be $100 30 million in 1998, not including special projects. The decrease in expected expenditures in 1998 is primarily attributable to a decrease in expected investments by Enova Financial. As discussed previously, in January 1997, certain subsidiaries of Enova and Pacific Enterprises formed Sempra Energy Solutions, a joint venture to market integrated energy and energy-related products and services. During 1997, Enova invested $21 million in Sempra Energy Solutions. In addition, in January 1998, Sempra Energy Solutions completed the acquisition of CES/Way International, a leading national energy-service provider. In September 1997, Sempra Energy Solutions formed a joint venture with Bangor Hydro to build, own and operate a $40 million natural gas distribution system in Bangor, Maine. In addition, in December 1997 Sempra Energy Solutions signed a partnership agreement with Frontier Utilities to build and operate a $55 million natural gas distribution system in North Carolina. In December 1997, Enova and Pacific Enterprises completed the joint acquisition of AIG Trading Corporation, a leading natural gas and power marketing firm. Enova contributed $110.6 million to that acquisition, which was subsequently renamed Sempra Energy Trading. In July 1997, Enova International and its partners, Pacific Enterprises International and Proxima S.A. de C.V., delivered their first supply of natural gas to Baja California. The Mexican company formed by the three partners, Distribuidora de Gas Natural de Mexicali, will invest up to $25 million during the first five years of the 30-year license period to supply natural gas to the region. The partnership is expected to serve 25,000 customers over the next four years. In March 1997, the Mexican Energy Regulatory Commission awarded the partners their second natural gas privatization license in Mexico, allowing Distribuidora de Gas Natural de Chihuahua to build and operate a natural gas distribution system in Chihuahua. That partnership plans to invest approximately $50 million in the project and is expected to serve 50,000 customers over the next five years. In January 1998, Enova International and its partner, Union Fenosa ACEX of Spain, submitted a bid to build, own and operate a natural gas distribution system in Monterrey, Mexico. The project will consist of an initial investment of $190 million for a system that will serve 320,000 customers, with an additional $60 million invested over five years to serve a total of 400,000 customers. Two other international consortia have submitted bids on the project. The Mexican Energy Regulatory Commission is expected to announce the winning bidder in March 1998. In December 1997, Enova Power Corporation, a subsidiary of Enova Energy, and Houston Industries Power Generation formed El Dorado Energy, a joint venture to build, own and operate a natural gas power plant in Boulder City, Nevada. Enova invested $2.3 million in El Dorado Energy in 1997 and expects to invest an additional $37 million in 1998 and $17 million in 1999. Additional information about these acquisitions and joint ventures is discussed in Note 3 of the notes to consolidated financial statements. Derivative Financial Instruments The policy of Enova is to use derivative financial instruments to reduce exposure to fluctuations in interest rates, foreign currency exchange rates and natural gas prices. These financial instruments are with major investment firms and expose Enova to market and credit risks. At times, these risks may be concentrated with certain counterparties, although counterparty nonperformance is not anticipated. 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 borrowing. These swap and cap agreements generally 31 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 income statement as part of interest expense. SDG&E would be exposed to interest-rate fluctuations on the underlying debt should other parties to the agreement not perform. Such nonperformance is not anticipated. At December 31, 1997, SDG&E had an agreement for a floating-to-fixed-rate swap associated with $45 million of variable-rate bonds maturing in 2002. SDG&E's pension fund periodically uses foreign-currency forward contracts to reduce its exposure to exchange-rate fluctuations associated with certain investments in foreign equity securities. These contracts generally have maturities ranging from three to six months. At December 31, 1997, and 1996, there were no foreign-currency forward contracts outstanding. In November 1996, SDG&E commenced price risk management activities, on a limited basis, in the area of hedging price volatility of natural gas requirements. SDG&E uses energy derivatives for both hedging and trading purposes within certain limitations imposed by company policies. These derivative financial instruments include forward contracts, swaps, options and other contracts which have maturities ranging from 30 days to nine months. Additional information on derivative financial instruments of SDG&E is provided in Note 8 of the notes to consolidated financial statements and under "Market Risk" below. Sempra Energy Trading Corp. derives a substantial portion of its revenue from trading activities in natural gas, petroleum and electricity. Trading profits are earned as Sempra Energy Trading acts as a dealer in structuring and executing transactions that permit its counterparties to manage their risk profiles. In addition, Sempra Energy Trading takes positions in energy markets based on the expectations 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. Additional information on derivative financial instruments of Sempra Energy Trading is provided in Note 3 of the notes to consolidated financial statements and under "Market Risk" below. Market Risk Market risk arises from the potential change in the value of financial instruments and physical commodities based on 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. SDG&E utilizes a variety of financial structures, products and terms which require the company to manage, on a portfolio basis, the resulting market risks inherent in these transactions, subject to parameters established by company policies. Market risks are monitored separately from the groups that create or actively manage these risk exposures to ensure compliance with the company's stated risk management policies at both the Enova and subsidiary levels. SDG&E measures the risk in its portfolio on a daily basis in accordance with value-at-risk methodologies, which simulate forward price curves in the energy markets to estimate the size and probability of future potential losses. The quantification of market risk using value-at-risk provides a consistent measure of risk across diverse energy markets and products. The use of this methodology requires a number of key assumptions, including the selection of a confidence level for losses and the holding period chosen for the value-at-risk calculation. SDG&E expresses value-at-risk as the amount of SDG&E's earnings at risk based on a 95 percent confidence level using a time horizon of the average life of the portfolio. As of December 31, 1997, SDG&E's value- 32 at-risk for its price-risk management activities was $2.8 million (net of income taxes) of SDG&E's net earnings. Since this is not an absolute measure of risk under all conditions for all products, SDG&E performs alternative scenario analyses to estimate the economic impact of a sudden market movement on the value of the portfolio. This and the professional judgment of experienced business and risk managers is used to supplement the value-at-risk methodology. Based upon the ongoing policies and controls discussed above, SDG&E does not anticipate a material adverse effect on its financial position or results of operations as a result of market fluctuations. A Risk Management Committee, composed of Enova and Pacific Enterprises officers, is responsible for monitoring operating performance and compliance with established risk management policies for Sempra Energy Solutions and its subsidiaries. Sempra Energy Trading has established position and stop-loss limits for each line of business to monitor its market risk and traders are required to maintain positions within these market-risk limits. The position limits are monitored during the day by Sempra Energy Trading's senior management, which determines whether to adjust its market-risk profile. All of Sempra Energy Trading's market-risk sensitive instruments are entered into for trading purposes. The following table provides the potential changes in net principal transaction revenues resulting from hypothetical 10-percent increases and 10-percent decreases in the applicable commodity prices for significant commodity market-price sensitive instruments held on December 31, 1997. This quantitative information about market risk is limited because it does not take into account potential hedging transactions or changes to the market-risk profile of the portfolio by management in reaction to such changes in market conditions. Additionally, it does not take into account anticipated management reaction to breaches of counterparty credit limitations caused by the shocks within a given risk category. Further, inherent limitations arise from assuming that hypothetical 10-percent increases and 10-percent decreases in commodity prices move in the same direction, and this information does not recognize co-movements in prices. The following table presents the impact on Sempra Energy Trading's net principal transaction revenues resulting from a 10-percent increase and a 10-percent decrease in the respective December 31, 1997 commodity prices: In thousands of dollars - ----------------------------------------------------------------------- Commodity 10% Increase 10% Decrease - ----------------------------------------------------------------------- Crude oil and derivatives $ 3,288 $ (3,288) Natural gas (2,441) 2,441 Emission credits (81) 81 Electricity (540) 540 - ----------------------------------------------------------------------- SDG&E's payments to the externally managed nuclear decommissioning trust funds expose SDG&E to market risk. Market risk can result from fluctuations in the volatility and liquidity in markets in which these instruments are traded. These fluctuations can also correspondingly affect the level of funding of the decommissioning trust. Credit Risk Credit risk relates to the risk of loss that would be incurred as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. SDG&E and Sempra Energy Trading avoid concentration of counterparties and maintain credit policies with regard to counterparties that management believes significantly minimize 33 overall credit risk. These policies include an evaluation of potential counterparties' financial condition (including credit rating), collateral requirements under certain circumstances, and the use of standardized agreements which allow for the netting of positive and negative exposures associated with a single counterparty. The companies monitor credit risk exposure through an approval process and the assignment of credit limits. These credit limits are established based on risk and return considerations under terms customarily available in the industry. ELECTRIC INDUSTRY RESTRUCTURING Background In September 1996, the state of California enacted a law restructuring California's electric utility industry (AB 1890). The legislation adopts the December 1995 CPUC policy decision that restructures the industry to stimulate competition and reduce rates. In May 1997, the CPUC issued a decision providing for direct access to be available to all California electric customers on January 1, 1998. The CPUC concluded that there were no technical or operational barriers to justify limiting direct access availability once electric restructuring commenced. The decision allowed customers to begin choosing electricity providers in November 1997. In December 1997, the CPUC agreed to delay the initiation of electric restructuring until March 31, 1998, to allow California's Power Exchange (PX) and Independent System Operator (ISO) to resolve computer software problems and conduct additional user training. Beginning on March 31, 1998, customers will be given the choice to continue to purchase electricity from their local utility under regulated tariffs, to enter into contracts with other energy service providers (i.e., private generators, brokers, etc.) or buy their power from the independent PX that serves as a wholesale power pool allowing all energy producers to participate competitively. The PX obtains power from qualifying facilities, nuclear units and, lastly, from the lowest-bidding suppliers. The ISO will schedule the power transactions and access to the transmission system. To facilitate this, the utilities will transfer the operational control of their transmission facilities to the ISO. The local utility will continue to provide distribution services, regardless of which source the consumer chooses. These customer choices will, in effect, open up the service territories of all California utilities. This will allow Enova, through Sempra Energy Solutions, to pursue customers outside of SDG&E's traditional service territory to provide electricity and other energy-related services. This also allows other energy-service providers to enter SDG&E's service territory to compete for generation customers. Transition Costs Both the CPUC decision and the California legislation allow utilities, within certain limits, the opportunity to recover their stranded costs incurred for certain above-market CPUC-approved facilities, contracts and obligations through the establishment of a nonbypassable competition transition charge (CTC). The CPUC's direction is that traditional cost-of-service regulation will move toward performance-based regulation. Utilities are allowed a reasonable opportunity to recover their stranded costs through December 31, 2001. Stranded costs such as reasonable employee-related costs directly caused by restructuring and purchased-power contracts (including those with qualifying facilities) may be recovered beyond 2001, subject to a reasonableness review. SDG&E's transition-cost application, filed in October 1996, identified $2 billion of estimated stranded costs, including generation, purchased-power and qualifying facilities' contracts, and regulatory assets. The amount includes sunk costs, as well as ongoing costs the CPUC finds necessary to maintain generation facilities through December 31, 2001. These identified transition costs were determined to be 34 reasonable by independent auditors selected by the CPUC, with $73 million identified as requiring further action before being deemed recoverable transition costs. Through December 31, 1997, SDG&E has recovered transition costs of $0.2 billion for nuclear generation and $0.1 billion for nonnuclear generation. Additionally, overcollections of $0.1 billion recorded in the Energy Cost Adjustment Clause (ECAC) and the Electric Revenue Adjustment Mechanism (ERAM) balancing accounts as of December 31, 1997, have been applied to transition cost recovery, leaving approximately $1.6 billion for future CTC recovery. Included therein is $0.4 billion for post-2001 purchased-power-contract payments that may be recovered after 2001, subject to an annual reasonableness review. Outside of the exceptions discussed above, transition costs not recovered by December 31, 2001, will not be collected from customers. Such costs, if any, would be written off as a charge against earnings. AB 1890 clarifies that all existing and future consumers must pay CTC, except for a segment of self-generators and irrigation districts. SDG&E has very few, if any, of these types of customers and does not anticipate a material impact from the exemption. During the 1998-2001 period, the recovery of transition costs is limited by the rate freeze (discussed below). Management believes that the rates within the rate freeze and the proceeds from the sale of electric-generating assets (discussed below) will be sufficient to recover all of SDG&E's approved transition costs by December 31, 2001. In November 1997, the CPUC issued a decision allowing SDG&E the opportunity to recover all of its sunk nonnuclear generation costs, with the exception of $39 million in fixed costs relating to gas transportation to power plants, which SDG&E believes will be recovered through contracts with the ISO. The decision does not include generation plant additions made after December 20, 1995. Instead, SDG&E must file an application seeking a CPUC reasonableness review thereof. In October 1997, SDG&E filed an application with the CPUC seeking recovery of $14.5 million in 1996 capital additions for the Encina and South Bay power plants. A final CPUC decision is expected in 1998. Rate-Reduction Bonds AB 1890 required a 10-percent rate reduction for residential and small-commercial customers beginning in January 1998. AB 1890 also provided for the issuance of rate-reduction bonds by an agency of the state of California to enable California's investor-owned electric utilities (IOUs) to use the proceeds to finance 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 electricity bills. In September 1997, SDG&E and the other California IOUs received a favorable ruling by the Internal Revenue Service on the tax treatment of the bond transaction. The ruling states, among other things, that the receipt of the bond proceeds does not result in gross income to SDG&E at the time of issuance, but rather the proceeds are taxable over the life of the bonds. The Securities and Exchange Commission determined that these bonds should be reflected on the utilities' balance sheets as debt, even though the bonds are not secured by, or payable from, utility assets, but rather by the revenue streams collected from customers. SDG&E formed a subsidiary, SDG&E Funding LLC, to facilitate the issuance of the rate-reduction bonds. In exchange for the bond proceeds, SDG&E sold to SDG&E Funding all of its rights to the revenue streams. Consequently, the revenue streams are not the property of SDG&E nor are they available to satisfy any claims of SDG&E's creditors. There was no gain or loss recorded from the issuance of the bonds or the receipt of the proceeds. SDG&E has begun to use a portion of the proceeds to redeem its higher cost debt, described herein under "Liquidity and Capital Resources - Financing Activities." In December 35 1997, the California Supreme Court dismissed a petition submitted by a coalition of consumer groups to overturn the CPUC's Rate-Reduction Bond financing orders. A related coalition of consumer groups has also put together a California ballot initiative that, among other things, would possibly result in an additional 10-percent rate reduction, require that this rate reduction be achieved through the elimination or reduction of CTC payments and prohibit the collection of the charge on customer bills that would finance the rate reduction. SDG&E cannot predict the final outcome of the initiative. If the initiative were to be voted into law and upheld by the courts, the financial impact on SDG&E could be substantial. Electric Rates AB 1890 included a rate freeze for all customers. Until the earlier of March 31, 2002, or when transition cost recovery is complete, SDG&E's average system rate will be frozen at 9.64 cents per kilowatt-hour, except for the impacts of natural gas price changes and the mandatory 10-percent rate reduction. As a result of significant increases in natural gas prices during the first quarter of 1997, SDG&E received CPUC authority to increase rates, but rates could not be increased above 9.985 cents per kwh. With the 10-percent rate reduction beginning on January 1, 1998, the maximum system-average rate became 9.43 cents per kwh. SDG&E's ability to recover its transition costs is dependent on its total revenues under the rate freeze exceeding normal cost-of-service revenues during the transition period by at least the amount of the CTC less any proceeds from the sale of electric-generating assets (discussed below). During the transition period, SDG&E will not earn awards from special programs, such as DSM, unless total revenues are also adequate to cover the awards. Fuel-price volatility is the most significant variable in the ability of SDG&E to recover its transition costs and program awards. Balancing Accounts In October 1997, the CPUC issued a decision eliminating the ECAC and the ERAM balancing accounts, effective December 31, 1997. As of December 31, 1997, net overcollections for these accounts of $130 million have been transferred to the interim transition-cost-balancing account to be applied to CTC recovery, subject to a reasonableness review. The decision eliminates further ECAC proceedings for generation costs incurred beginning in January 1998. Additionally, the decision eliminates all other electric balancing accounts, except for those associated with the administration of DSM, low-income assistance, and research and development (R&D) programs, which will be used to assist in the administration of public-purpose funds (discussed below). In addition, SDG&E has requested the retention of the Electric Vehicle balancing account through December 31, 1998. The elimination of ERAM and ECAC resulted in earnings volatility that began in the first quarter of 1997. Although no effect in 1997 was seen for the full year, quarterly earnings fluctuated significantly, as was the case for the other California IOUs. The largest impacts were reduced first-quarter earnings and increased third-quarter earnings. This quarterly volatility pattern is expected to continue in the future. Beginning in 1998, annual earnings also will be affected by sales volumes. Regulatory Accounting Standards SDG&E had been accounting for the economic effects of regulation on all of its utility operations in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." Under SFAS No. 71, a regulated entity records 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 revenues for amounts due to customers. 36 The SEC indicated a concern that the California IOUs may not meet the criteria of SFAS No. 71 with respect to their electric-generation net regulatory assets. SDG&E has ceased the application of SFAS No. 71 to its generation business, in accordance with the conclusion by the Emerging Issues Task Force of the Financial Accounting Standards Board that the application of SFAS No. 71 should be discontinued when deregulatory legislation is issued that determines that a portion of an entity's business will no longer be regulated. SDG&E's discontinuance of SFAS No. 71 applied to its generation business will not result in a write-off of its net regulatory assets, since the CPUC has approved the recovery of these assets by the distribution portion of its business, subject to the rate freeze. Consumer Education In August 1997, the CPUC authorized $89 million in rate recovery to fund California's Customer Education Program (CEP). SDG&E's share of this amount is approximately $9 million. The CEP's objective is to provide information to California electric customers to help them compare and choose among electric products and services in a competitive environment. The CEP began in September 1997 and is expected to end by May 31, 1998. Public-Purpose Programs The CPUC has established a new administrative structure and initial funding levels to manage DSM, renewable-energy, low-income assistance and R&D programs beginning in January 1998. The CPUC has formed independent boards to oversee a competitive bidding process to administer DSM and low-income programs. On an interim basis, the CPUC has required that the California IOUs transfer their administration of DSM and low-income programs to these boards by October 1998, and January 1999, respectively. Until the transition to a fully competitive energy-service market is complete, customers will be required to provide the funding. For 1998, SDG&E will be funded $32 million and $12 million for DSM and renewables programs, respectively. Low-income assistance funding will remain at 1996 authorized levels. The California Energy Commission will be allocated most of the $63 million authorized to administer the R&D programs, of which SDG&E will be funded $4 million. SDG&E's earnings potential from DSM programs will be reduced when the transition to the competitive market is complete. Federal Restructuring Activities In October 1997, the FERC approved key elements of the California IOUs' restructuring proposal effective January 1, 1998. This includes 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, on an interim basis, the establishment of the California PX to operate as an independent wholesale power pool. The California IOUs will pay to the PX a 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 eligible for transition-cost recovery. The IOUs have jointly guaranteed $300 million of commercial loans to the PX and ISO for their development and initial start-up. SDG&E's share of the guarantee is $30 million. ELECTRIC GENERATION In November 1997, SDG&E's Board of Directors approved a plan to auction the company's power plants and other electric-generating assets, enabling SDG&E to continue to concentrate its business on the transmission and distribution of electricity and natural gas as California opens its electric utility industry to competition in 1998. The plan includes the divestiture of SDG&E's fossil power plants - the Encina (Carlsbad, California) and South Bay (Chula Vista, California) 37 plants - and its combustion turbines, as well as its 20-percent interest in the San Onofre Nuclear Generating Station (SONGS) and its portfolio of long-term purchased-power contracts, including those with qualifying facilities. The power plants, including the interest in SONGS, have a net book value as of December 31, 1997, of $800 million ($200 million for fossil and $600 million for SONGS) and a combined generating capacity of 2,400 megawatts. The proceeds from the auction will be applied directly to SDG&E's transition costs. In December 1997, SDG&E filed with the CPUC for its approval of the auction plan. The sale of the nonnuclear generating assets is expected to be completed by the end of the first quarter of 1999. Although the other California IOUs are required by the CPUC to divest themselves of at least 50 percent of their fossil power plants as a part of industry restructuring, SDG&E is not under the same mandate. Other companies in the free market, not bound by the rules that apply to the state's regulated utilities, are expected to have a greater opportunity to provide competitive generation services with SDG&E's plants. The FERC has ruled that it has jurisdiction over all electricity sales into the California PX, meaning that the buyers of divested California power plants would qualify as wholesale power generators. The FERC's ruling has increased the interest in the nonnuclear plants owned by the other California IOUs, and is expected to have the same impact on SDG&E's fossil plants. As previously discussed, subsidiaries of Enova Energy and Houston Industries have formed a joint venture to build, own and operate a 480- megawatt natural gas-fired power plant in Boulder City, Nevada, 40 miles southeast of Las Vegas. The joint venture, called El Dorado Energy, plans to sell the plant's electricity into the wholesale market to utilities throughout the western United States. The new plant will employ an advanced combined-cycle gas-turbine technology, enabling it to become one of the more efficient and environmentally friendly power plants in the nation. Its proximity to existing natural gas pipelines and electric transmission lines will allow El Dorado to actively compete in the deregulated electric-generation market. Construction on the $280 million project, which will be funded 50 percent each by Enova and Houston Industries, began in the first quarter of 1998, with an expected operational date set for the fourth quarter of 1999. AFFILIATE TRANSACTION GUIDELINES In December 1997, the CPUC issued a decision on the rules governing transactions between a regulated utility and its affiliates that are not regulated by the CPUC. The decision adopts guidelines that are more favorable to consumers and less restrictive to utilities and their affiliates than the conditions that were recommended in October 1997 by a CPUC administrative law judge's proposed decision and an alternate decision by two CPUC commissioners. Key elements of the decision include: allowing the unregulated affiliates to operate within the utility's service territory without limitation; permitting utilities to share logos with their parent company and unregulated affiliates as long as proper disclaimers to California customers clearly communicate the utility-affiliate relationship; and allowing officers or board of directors of the parent company to also hold positions with the utility or unregulated affiliate, but not both. The rules adopted require separating functions between the utility and the affiliates with the exception of sharing certain corporate support services. These guidelines include transactions between affiliated utilities. However, these transactions have been addressed by the CPUC in the Enova/Pacific Enterprises business combination proceedings and the draft decision arising from that proceeding would exclude transactions between SDG&E and SoCalGas from the guidelines. 38 PERFORMANCE-BASED RATEMAKING (PBR) Background The CPUC has affirmed its belief that the new competitive environment should be based on policies that encourage efficient operation and improved productivity rather than on reasonableness reviews and disallowances. SDG&E has been participating in a PBR process for base rates, gas procurement, and electric generation and dispatch. SDG&E has applied to extend the Gas Procurement mechanism. The Generation and Dispatch mechanism has been terminated. SDG&E has filed a proposal for a new Distribution PBR mechanism to replace the current experimental Base-Rate PBR when it terminates at the end of 1998. Base Rates In December 1997, the CPUC approved $6.5 million in performance rewards for SDG&E's 1996 PBR. The CPUC has eliminated the price-performance benchmark indicator, which compares SDG&E's average electric-system rate to a national average, from SDG&E's Base-Rate PBR effective in 1997 due to the electric-rate freeze. For the 1998 PBR, all customer sharing amounts will be credited to the transition-cost balancing account rather than refunded to customers. In December 1997, the CPUC eliminated SDG&E's 1999 General Rate Case filing requirement, and replaced it with a 1999 Cost of Service study in its new Distribution PBR application for electric distribution and gas operations (filed in January 1998 to begin in 1999). The Distribution PBR, which includes six categories of performance indicators, will measure SDG&E's ability to provide efficient, safe and reliable utility transmission (gas only) and distribution services. The application requests a $60 million increase in SDG&E's revenue requirements ($35 million for electric distribution and $25 million for gas). The electric distribution increase does not affect rates and, therefore, reduces the amount available to recover transition costs. Under the new mechanism, all customer-sharing amounts will be reflected as reductions to future rates rather than refunded directly to customers. SDG&E's ability to control its costs within the limits of the revenues authorized by the study will impact future earnings. 1998 Revenues In December 1997, the CPUC approved a $67 million increase in SDG&E's authorized electric distribution revenue requirements and a $7 million increase in gas base rates, effective on January 1, 1998. The electric distribution increase, which reflects 1998 PBR escalations, does not affect rates and, therefore, reduces the amount available to recover transition costs. Natural Gas In September 1997, SDG&E filed with the CPUC its application for a permanent Gas Procurement PBR mechanism. The filing proposes a mechanism structured around a commodity price cap plus an incremental adjustment, designed to recover transportation costs to the California border. SDG&E is holding settlement discussions with the CPUC's Office of Ratepayer Advocates over the proposed new mechanism. NATURAL GAS OPERATIONS The ongoing restructuring of the natural gas utility industry has allowed customers to bypass utilities as suppliers and, to a lesser extent, as transporters of natural gas. Currently, nonutility electricity producers and other large customers may use a natural gas utility's facilities to transport gas purchased from other suppliers. Also, smaller customers may form groups to buy natural gas from another supplier. In January 1998, the CPUC opened a rulemaking proceeding designed to open the natural gas industry to all customers, expanding the opportunities of residential and small commercial customers to have access to competing natural gas suppliers. The rulemaking will allow 39 smaller customers to receive the price and service benefits already realized by larger customers. A potential benefit from future natural gas reform, benefiting both customers and industry participants, would be the opportunity for energy providers to offer integrated retail electric and natural gas service to develop synergies between the two energy markets. In developing a natural gas retail restructuring proposal, the CPUC has provided several guiding principles: replace traditional regulation with competition in those markets where competition or the potential for competition exists, thereby allowing market forces to dictate prices; reform regulation for those utility functions that are not fully competitive; maintain a standard of consumer protection in both competitive and noncompetitive markets; and maintain supply reliability and ensure the safety of consumers' natural gas service. Hearings on the proposed restructuring are scheduled to begin in April 1998, with a final CPUC decision expected to be issued before the end of 1998. Enova's nonutility subsidiaries are involved in several projects to develop natural gas systems in the United States and in Mexico. Discussion on these activities is included herein under "Liquidity and Capital Resources - Investing Activities." COST OF CAPITAL In October 1997, SDG&E filed with the CPUC its 1998 Market Indexed Capital Adjustment Mechanism (MICAM). MICAM, approved by the CPUC in 1996, adjusts SDG&E's authorized cost of capital based on changes in interest rates. For the current MICAM review, interest-rate movements over the corresponding 12 months did not trigger the mechanism to change, resulting in SDG&E's 1998 cost of capital remaining at 1997 authorized levels of 11.60 percent for the rate of return on equity and 9.35 percent for the rate of return on rate base. Beginning in 1998, MICAM only applies to electric distribution and gas rate base, and excludes the rates of return on nuclear and nonnuclear generating assets (recovered as transition costs), which are authorized at rates of 7.14 percent and 6.75 percent, respectively. During 1998, the CPUC will conduct proceedings to establish separate rates for the electric and gas components. SDG&E's authorized capital structure, which excludes the rate-reduction bonds, remains 49.75 percent common equity, 44.5 percent long-term debt and 5.75 percent preferred stock. Electric transmission rates are regulated by the FERC. SDG&E's 1998 rate of return for transmission is 9.54 percent. RESOURCE PLANNING Sources of Fuel and Energy SDG&E's primary sources of fuel and purchased power include natural gas from Canada and the Southwest, surplus power from other utilities in the Southwest and the Northwest, and uranium from Canada. Although short-term natural gas supplies are volatile due to weather and other conditions, these sources should provide SDG&E with an adequate supply of competitively priced natural gas. SDG&E has been involved in litigation concerning its long-term contracts for natural gas with four Canadian suppliers. SDG&E has settled with one supplier, with gas being delivered under the terms of the settlement agreement. The remaining suppliers have ceased deliveries pending legal resolution. A U.S. Court of Appeals has upheld a U.S. District Court's decision to invalidate the contracts with two of the suppliers, although the value of the gas delivered has not yet been determined by the court. SDG&E has long-term pipeline capacity commitments related to these contracts for natural gas supplies. If the supply of Canadian natural gas to SDG&E is not resumed, SDG&E intends to use the capacity in other ways, including the release of a portion of this capacity to third parties. SDG&E cannot predict the final outcome of the litigation, but does not expect that an unfavorable outcome would 40 have a material effect on its financial condition, results of operations or liquidity. Additional information on Canadian gas litigation is discussed in Note 9 of the notes to consolidated financial statements. San Onofre Nuclear Generating Station In January 1996, the CPUC approved the accelerated recovery of the existing capital costs of Units 2 and 3. The decision allowed SDG&E to recover its remaining investment in the units at a lower rate of return (7.14 percent) over an eight-year period beginning in 1996, rather than over the life of the units' license, which extends to 2013. The accelerated recovery began in April 1996. At December 31, 1997, approximately $600 million was not yet recovered. California electric-industry-restructuring legislation requires that all generation-related stranded assets, which includes the uneconomic sunk costs of Units 2 and 3, be recovered by 2001. The 1996 decision also includes a performance incentive plan that encourages continued, efficient operation of the plant. Under this plan, customers will pay about $0.04 per kilowatt-hour through December 31, 2003. This pricing structure replaces the traditional method of recovering the units' operating expenses and capital improvements. This is intended to make the units more competitive with other sources. The California Coastal Commission (CCC) approved the SONGS owners' preliminary plan to provide 150 acres of wetlands restoration, 150 acres of kelp reef and other mitigation that was ordered by the CCC in April 1997. SDG&E's share of the cost is estimated to be $23 million. Additional information is included under "Water Quality" below. While conducting routine inspections of Unit 3 during its scheduled refueling in the second quarter of 1997, it was noted that, in several areas, the thickness of the heat transfer tubes' structural supports was significantly reduced, apparently due to erosion. In June 1997, the Nuclear Regulatory Commission approved the removal of the affected tubes from service as a corrective action and the unit's return to service. Unit 2, which also had this inspection during its scheduled refueling in the first quarter of 1997, showed no signs of this type of erosion. As a precautionary measure, Unit 2 was shut down in January 1998 for a 30-day mid-cycle outage for an inspection of its steam generators. The SONGS owners have scheduled a 30-day outage for Unit 3 in March 1998, for this inspection. The discovery of such problems in the future could increase the possibility that the units would be removed from service prior to 2013. ENVIRONMENTAL MATTERS SDG&E's 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. SDG&E incurs significant costs to operate its facilities in compliance with these laws and regulations, and to clean up the environment as a result of prior operations of SDG&E or of others. The costs of compliance with environmental laws and regulations are normally recovered in customer rates. However, restructuring of the California electric-utility industry (see "Electric Industry Restructuring" above) will change the way utility rates are set and costs are recovered. SDG&E has proposed a change in the hazardous waste memorandum account to exclude cleanup costs related to electric- generation activities, as described below. Capital costs related to environmental regulatory compliance for electric generation are intended to be included in transition costs for recovery through 2001. However, depending on the final outcome of industry restructuring and the impact of competition, the costs of compliance with future environmental regulations may not be fully recoverable. Capital expenditures to comply with environmental laws and regulations were $4 million in 1997, $6 million in 1996 and $4 million 41 in 1995, and are expected to be $38 million in the aggregate over the next five years. These expenditures primarily include the estimated cost of retrofitting SDG&E's power plants to reduce air emissions. However, in November 1997 SDG&E announced a plan to auction its power plants and other electric-generating resources. Additional information on SDG&E's plan to divest its electric-generating assets is discussed in Note 10 of the notes to consolidated financial statements. Hazardous Wastes In 1994, the CPUC approved the Hazardous Waste Collaborative, which allows utilities to recover cleanup costs of hazardous waste contamination at sites where the utility may have responsibility or liability under the law to conduct or participate in any required cleanup. In general, utilities are allowed to recover 90 percent of their cleanup costs and any related costs of litigation with responsible parties. SDG&E has asked the CPUC that beginning on January 1, 1998, the hazardous waste memorandum account be modified to exclude cleanup costs related to electric-generation activities. Electric- generation-related cleanup costs are intended to be eligible for transition cost recovery. A CPUC decision is still pending. SDG&E lawfully disposed of hazardous wastes at facilities owned and operated by other entities. Operations at these facilities may result in actual or threatened risks to the environment or public health. Where the owner or operator of such a facility fails to complete any corrective action required by regulatory agencies to abate such risks, applicable environmental laws may impose an obligation to undertake corrective actions on SDG&E and others who disposed of hazardous wastes at the facility. During the early 1900s, SDG&E and its predecessors manufactured gas from coal and oil at its Station A facility and at two small facilities in Escondido and Oceanside. Certain amounts of residual by-products from the gas manufacturing process and subsurface hydrocarbon contamination were discovered on portions of the Station A site during an environmental assessment which was completed in 1996. A risk assessment has been completed for Station A and demolition was performed during 1997 at a cost of $1 million. Cleanup will commence in 1998, to be completed in 1999, and is estimated to cost $5 million for subsurface remediation. SDG&E also may be required to assess certain off-site contamination which, in part, may have originated from the gas manufacturing process or other operations at Station A. Not included in this estimate are potential costs related to a previously removed shallow underground tank-like structure found under a public street immediately west of Station A. Any potential costs related to this tank would be immaterial. SDG&E is completing negotiations for an appropriate site-remediation work plan for Station A with the County of San Diego Department of Environmental Health. The Escondido facility was remediated during 1990 through 1993 at a cost of $3 million and a site-closure letter from the Department of Environmental Health has been received. However, contaminants similar to those on the Escondido site have been observed on adjacent property. In 1997, SDG&E assessed the nature and extent of these off-site contaminants at a cost of $75,000. Hazardous contaminants were found on property to the east of the site and are believed to have originated from SDG&E operations. Remediation of these contaminants was initiated in 1997 and completed in 1998 at a total cost of $250,000. A site- closure letter has been requested from the Department of Environmental Health. Nonhazardous contaminants were determined to be present on property to the north, but may not require further action subject to future land-use decisions. Finally, potential contaminants resulting from the gas manufacturing process by-products were assessed at the Oceanside facility, as well as on adjacent property. The cost to remediate the hazardous contaminants discovered in the assessment at the 42 property adjacent to the Oceanside facility and at the facility itself is estimated to be $150,000. Asbestos was used in the construction of SDG&E's Station B power plant, which closed in 1993. Activities to dismantle and decommission the facility require the removal of the asbestos in a manner complying with all applicable environmental, health and safety laws. This work also includes the removal or cleanup of paints containing heavy metals and small amounts of PCBs, fuel oil and other substances. These activities commenced in 1997 at a cost of $3 million. This work effort is expected to be completed in 1998 at an estimated additional cost of $3 million. Electric and Magnetic Fields (EMFs) In property-damage litigation in 1996, the California Supreme Court agreed with SDG&E and unanimously affirmed the 1995 California Court of Appeal decision that the CPUC has exclusive jurisdiction over EMF health and safety issues. The California Supreme Court also stated that scientific evidence is insufficient to conclude that EMFs pose a health hazard. In addition, in a December 1997 case involving Pacific Gas & Electric, the California Court of Appeal held that the CPUC has exclusive jurisdiction over EMF personal injury, as well as EMF property-damage cases. Plaintiffs have sought review of this case at the California Supreme Court, which request is still pending. Although scientists continue to research the possibility that exposure to EMFs causes adverse health effects, to date, science has demonstrated no cause-and-effect relationship between adverse health effects and exposure to the type of EMFs emitted by utilities, power lines and other electrical facilities. Some laboratory studies suggest that such exposure creates biological effects, but those effects have not been shown to be harmful. The studies that have most concerned the public are certain epidemiological studies, some of which have reported a weak correlation between childhood leukemia and the proximity of homes to certain power lines and equipment. Other epidemiological studies found no correlation between estimated exposure and any disease. Scientists cannot explain why some studies using estimates of past exposure report correlations between estimated EMF levels and disease, while others do not. To respond to public concerns, the CPUC has directed California utilities to adopt a low-cost EMF-reduction policy that requires reasonable design changes to achieve noticeable reduction of EMF levels that are anticipated from new projects. However, consistent with the major scientific reviews of the available research literature, the CPUC has indicated that no health risk has been identified. Air Quality The San Diego Air Pollution Control District (APCD) regulates air quality in San Diego County in conformance with the California and Federal Clean Air Acts. California's standards are more restrictive than federal standards. During 1996 and 1997, SDG&E installed equipment on South Bay Unit 1 in order to comply with the nitrogen oxide emission limits that the APCD imposed on electric-generating boilers through its Rule 69. Under this rule, SDG&E must maintain the total nitrogen oxide emissions from its entire system below a prescribed emissions cap, which decreases periodically through 2005. The estimated capital costs for compliance with the rule through 2005 are $60 million. The California Air Resources Board has expressed concern that Rule 69 does not meet the requirements of the California Clean Air Act and may advocate or propose more restrictive emissions limitations which will likely cause SDG&E's Rule 69 compliance costs to increase. Under a South Coast Air Quality Management District program called RECLAIM, SDG&E is required to reduce its nitrogen oxide emission levels 43 of the natural gas compressor engines at its Moreno gas-compression facility by 10 percent a year through 2003. This will be accomplished through the installation of new emission-monitoring equipment, operational changes to take advantage of low-emission engines and engine retrofits. The cost of complying with RECLAIM may be as much as $3 million. Water Quality Wastewater discharge permits issued by the Regional Water Quality Control Board (RWQCB) for SDG&E's Encina and South Bay power plants are required to enable SDG&E to discharge its cooling water and certain other wastewaters into the Pacific Ocean and into San Diego Bay. Wastewater discharge permits are prerequisite to the continued cooling-water and other wastewater discharges and, therefore, the continued operation of the power plants as they are currently configured. Increasingly stringent cooling-water and wastewater discharge limitations may be imposed in the future and SDG&E may be required to build additional facilities or modify existing facilities to comply with these requirements. Such facilities could include wastewater treatment facilities, cooling towers or offshore-discharge pipelines. Any required construction could involve substantial expenditures, and certain plants or units may be unavailable for electric generation during construction. In 1981, SDG&E submitted a demonstration study in support of its request for two exceptions to certain thermal discharge requirements imposed by the California Thermal Plan for Encina power plant Unit 5. In November 1994, the RWQCB issued a new discharge permit, subject to the results of certain additional thermal discharge and cooling water related studies, to be used in considering SDG&E's earlier thermal discharge exception requests. The results of these additional studies were submitted to the RWQCB and the United States Environmental Protection Agency in 1997. If SDG&E's exception requests are denied, SDG&E could be required to construct off-shore discharge facilities at a cost of $75 million to $100 million or to perform mitigation, the costs of which may be significant. In November 1996, the RWQCB issued a new discharge permit to SDG&E for the South Bay power plant. SDG&E filed an appeal to the State Water Resources Control Board (SWRCB) of various provisions which SDG&E considers unduly stringent. The SWRCB has not yet formally acted on the appeal. However, the SWRCB sponsored workshops with the RWQCB and the Environmental Health Coalition in November and December 1997, as a result of which several important issues may be resolved in 1998. As with the Encina power plant, increasingly stringent cooling-water and wastewater discharge limitations may require SDG&E to build additional facilities to comply with these requirements. To comply with its current permit, in 1997 SDG&E diverted its in-plant wastewater discharges from San Diego Bay to the sanitary sewer at a cost of $2 million. During 1997, in conjunction with its permit requirements to treat wastewater at its Encina and South Bay power plants, SDG&E evaluated whether any remediation activities may be required at the power plants based on currently available records and other information. In addition, SDG&E evaluated whether remediation is required at its Silvergate plant, which was shut down in 1984. As a result of these evaluations, only minor and localized remediation efforts were required. However, these evaluations did not include an extensive sampling and analysis of the property at such sites. Extensive sampling and analysis may identify additional contamination or other environmental conditions requiring remediation. As previously discussed, in December 1997, SDG&E filed an application with the CPUC to divest its electric-generating assets, including its Encina and South Bay power plants, gas combustion turbines and its interest in the San Onofre Nuclear Generating Station. As a part 44 of the sale of any such facilities, SDG&E will complete an environmental baseline analysis of such sites, which may identify significant contamination or other environmental conditions requiring abatement or remediation. The California Coastal Commission (CCC) required a study of the offshore impact on the marine environment from the cooling-water discharge by SONGS Units 2 and 3 as a condition of granting a construction permit. The study concluded that some environmental damage is caused by the discharge. To mitigate the damage, the CCC ordered Southern California Edison, SDG&E and the cities of Anaheim and Riverside to improve the plant's fish-protection system, build a 300- acre artificial reef to help restore kelp beds and restore 150 acres of coastal wetlands. SDG&E and Edison asked the CCC to reconsider and modify this mitigation plan to reduce the size of the artificial reef and shorten the monitoring period based on new studies that show that the environmental damage is much less than anticipated. During 1997 the CCC ordered that the plant owners proceed with a mitigation program that includes the enhanced fish-protection system, a 150-acre artificial reef and restoration of 150 acres of coastal wetlands. In addition, plant owners must deposit $3.6 million with the state for the enhancement of marine fish hatchery programs and pay for state monitoring and oversight of the mitigation projects. SDG&E's share of the cost is estimated to be $23 million. The pricing structure contained in the CPUC's decision regarding accelerated recovery of SONGS Units 2 and 3 (see "San Onofre Nuclear Generating Station" above) likely will accommodate most of these added mitigation costs. NEW ACCOUNTING STANDARDS In June 1997, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 130, "Reporting Comprehensive Income." This statement, which is effective for 1998 financial statements, requires reporting and display of comprehensive income and its components (revenues, expenses, gains and losses) in a full set of general-purpose financial statements. The term "comprehensive income" describes all changes in equity of a business enterprise during a period 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. Upon adoption, financial statements for earlier periods provided for comparative purposes must be restated. The impact on Enova and SDG&E of the adoption of this new accounting standard is considered immaterial to the companies' financial statements. Also in June 1997, the FASB issued SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information." This statement, which is effective for 1998 financial statements, requires that public companies report certain information about operating segments in complete sets of financial statements of the enterprise and in condensed financial statements of interim periods. It also requires certain information about the company's products and services, geographic areas in which they operate, and their major customers. Under SFAS No. 131, operating segments are to be determined consistent with the way that management organizes and evaluates financial information internally for making operating decisions and assessing performance. Upon adoption, statements for earlier periods provided for comparative purposes must reflect this information. The impact of the adoption of this new accounting standard is the potential redefinition of the company's segments. The company estimates that the primary segments upon adoption of SFAS No. 131 will be electric operations, gas operations, energy services and other. 45 INFORMATION REGARDING FORWARD-LOOKING STATEMENTS This Annual Report to Shareholders includes forward-looking statements within the definition of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. When used in this "Management's Discussion and Analysis of Financial Condition and Results of Operations," the words "estimates," "expects," "anticipates," "plans" and "intends," variations of such words, and similar expressions are intended to identify forward-looking statements that involve risks and uncertainties. Although Enova and SDG&E believe that their expectations are based on reasonable assumptions, they can give no assurance that those expectations will be realized. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include political developments affecting state and federal regulatory agencies, the pace and substance of electric-industry deregulation in California and in the United States, the ability to effect a coordinated and orderly implementation of both state legislation and the CPUC's restructuring regulations, the consummation and timing of the proposed business combination of Enova and Pacific Enterprises, the timing and level of proceeds of sales of SDG&E's electric-generating assets, the level of sales of electricity, the rate of growth of nonutility subsidiary revenues, international political developments, environmental regulations, and the timing and extent of changes in interest rates and prices for natural gas and electricity. 46 Item 8. Financial Statements and Supplementary Data - Enova Corporation ENOVA CORPORATION STATEMENTS OF CONSOLIDATED INCOME In thousands except per share amounts
For the years ended December 31 1997 1996 1995 ------------ ------------ ------------ Operating Revenues Electric $1,769,421 $1,590,882 $1,503,926 Gas 398,127 348,035 310,142 Other 49,459 54,557 56,608 ------------ ------------ ------------ Total operating revenues 2,217,007 1,993,474 1,870,676 ------------ ------------ ------------ Operating Expenses Electric fuel 163,765 134,350 100,256 Purchased power 441,490 310,731 341,727 Gas purchased for resale 183,208 152,408 113,355 Maintenance 87,597 57,652 91,740 Depreciation and decommissioning 347,438 332,490 278,239 Property and other taxes 43,419 44,764 45,566 General and administrative 223,032 262,058 210,207 Other 222,727 212,245 209,358 Income taxes 160,161 151,813 134,578 ------------ ------------ ------------ Total operating expenses 1,872,837 1,658,511 1,525,026 ------------ ------------ ------------ Operating Income 344,170 334,963 345,650 ------------ ------------ ------------ Other Income and (Deductions) Allowance for equity funds used during construction 5,192 5,898 6,435 Taxes on nonoperating income 9,959 3,339 (27) Other - net 1,653 (3,265) (5,876) ------------ ------------ ------------ Total other income 16,804 5,972 532 ------------ ------------ ------------ Income Before Interest Charges and Preferred Dividends 360,974 340,935 346,182 ------------ ------------ ------------ Interest Charges and Preferred Dividends Long-term debt 85,617 89,198 95,523 Short-term debt and other 19,474 17,516 20,215 Allowance for borrowed funds used during construction (2,306) (3,288) (2,865) Preferred dividend requirements of SDG&E 6,582 6,582 7,663 ------------ ------------ ------------ Net interest charges and preferred dividends 109,367 110,008 120,536 ------------ ------------ ------------ Income From Continuing Operations 251,607 230,927 225,646 Discontinued Operations, Net of Income Taxes -- -- 148 ------------ ------------ ------------ Earnings Applicable to Common Shares $ 251,607 $ 230,927 $ 225,794 ============ ============ ============ Average Common Shares Outstanding 114,322 116,572 116,535 ============ ============ ============ Earnings Per Common Share (basic and diluted) $ 2.20 $ 1.98 $ 1.94 ============ ============ ============ Dividends Declared Per Common Share $ 1.56 $ 1.56 $ 1.56 ============ ============ ============ See notes to consolidated financial statements.
47 ENOVA CORPORATION CONSOLIDATED BALANCE SHEETS In thousands of dollars
Balance at December 31 1997 1996 -------------- -------------- ASSETS Utility plant - at original cost $5,888,539 $5,704,464 Accumulated depreciation and decommissioning (2,952,455) (2,630,093) -------------- -------------- Utility plant - net 2,936,084 3,074,371 -------------- -------------- Investments in partnerships and unconsolidated subsidiaries 516,113 271,035 -------------- -------------- Nuclear decommissioning trust 399,143 328,042 -------------- -------------- Current assets Cash and temporary investments 624,375 173,079 Accounts receivable 231,678 186,529 Notes receivable 27,083 33,564 Inventories 67,074 63,437 Other 89,826 47,094 -------------- -------------- Total current assets 1,040,036 503,703 -------------- -------------- Deferred taxes recoverable in rates 184,837 189,193 -------------- -------------- Deferred charges and other assets 157,711 282,893 -------------- -------------- Total $5,233,924 $4,649,237 ============== ============== CAPITALIZATION AND LIABILITIES Capitalization (see Statements of Consolidated Capital Stock and of Long-Term Debt) Common equity $1,570,383 $1,569,670 Preferred stock not subject to mandatory redemption 78,475 78,475 Preferred stock subject to mandatory redemption 25,000 25,000 Long-term debt 2,057,033 1,479,338 -------------- -------------- Total capitalization 3,730,891 3,152,483 -------------- -------------- Current liabilities Current portion of long-term debt 121,700 69,902 Accounts payable 163,395 175,815 Dividends payable 46,050 47,213 Interest accrued 23,160 21,259 Regulatory balancing accounts overcollected - net 58,063 35,338 Other 146,267 158,317 -------------- -------------- Total current liabilities 558,635 507,844 -------------- -------------- Customer advances for construction 37,661 34,666 Accumulated deferred income taxes - net 501,030 497,400 Accumulated deferred investment tax credits 62,332 64,410 Deferred credits and other liabilities 343,375 392,434 Contingencies and commitments (Notes 9 and 10) -- -- -------------- -------------- Total $5,233,924 $4,649,237 ============== ============== See notes to consolidated financial statements.
48 ENOVA CORPORATION STATEMENTS OF CONSOLIDATED CASH FLOWS
In thousands of dollars For the years ended December 31 1997 1996 1995 --------- --------- ---------- Cash Flows from Operating Activities Income from continuing operations $ 251,607 $ 230,927 $ 225,646 Adjustments to reconcile income from continuing operations to net cash provided by operating activities Depreciation and decommissioning 347,438 332,490 278,239 Amortization of deferred charges and other assets 6,246 6,556 12,068 Amortization of deferred credits and other liabilities (37,802) (38,399) (32,975) Allowance for equity funds used during construction (5,192) (5,898) (6,435) Deferred income taxes and investment tax credits 18,749 (6,875) (42,237) Other - net 55,817 73,850 57,475 Changes in working capital components Accounts and notes receivable (38,668) (7,440) 7,141 Inventories (3,637) 4,522 7,648 Other current assets (23,322) (14,242) (5,609) Interest and taxes accrued (30,350) (28,199) 23,131 Accounts payable and other current liabilities (24,470) 49,427 26,983 Regulatory balancing accounts 22,725 (37,313) 59,030 Cash flows provided by discontinued operations -- -- 6,148 ----------- --------- --------- Net cash provided by operating activities 539,141 559,406 616,253 ----------- --------- --------- Cash Flows from Financing Activities Dividends paid (179,586) (181,849) (180,625) Issuances of long-term debt 677,850 228,946 124,641 Repayment of long-term debt (171,133) (286,668) (165,871) Short-term borrowings - net -- -- (89,325) Redemption of common stock (74,122) (480) (241) Redemption of preferred stock -- (15,155) (18) ---------- ----------- ---------- Net cash provided (used) by financing activities 253,009 (255,206) (311,439) ---------- ----------- ---------- Cash Flows from Investing Activities Utility construction expenditures (197,184) (208,850) (220,748) Contributions to decommissioning funds (22,038) (22,038) (22,038) Other - net (121,632) 3,338 3,874 Discontinued operations -- -- 5,122 ---------- ----------- ---------- Net cash used by investing activities (340,854) (227,550) (233,790) ---------- ----------- ---------- Net increase 451,296 76,650 71,024 Cash and temporary investments, beginning of year 173,079 96,429 25,405 ---------- ----------- ---------- Cash and temporary investments, end of year $ 624,375 $ 173,079 $ 96,429 ========== =========== ========== Supplemental Schedule of Noncash Investing and Financing Activities Real estate investments $ 125,726 $ 96,832 $ 50,496 Cash paid (309) -- (2,550) ----------- ----------- --------- Liabilities assumed $ 125,417 $ 96,832 $ 47,946 =========== =========== ========= See notes to consolidated financial statements. 49
ENOVA CORPORATION STATEMENTS OF CONSOLIDATED CHANGES IN CAPITAL STOCK AND RETAINED EARNINGS In thousands of dollars For the years ended December 31, 1995, 1996, 1997
Preferred Stock ----------------------------- Not Subject Subject to Premium on to Mandatory Mandatory Common Capital Retained Redemption Redemption Stock Stock Earnings --------- --------- --------- --------- -------- Balance, January 1, 1995 $ 93,493 $ 25,000 $ 291,341 $ 564,508 $ 618,581 Earnings applicable to common shares 225,794 Long-term incentive plan activity-net 117 1,530 Preferred stock retired (880 shares) (18) 8 Common stock dividends declared (181,809) - ----------------------------- --------- --------- --------- --------- --------- Balance, December 31, 1995 93,475 25,000 291,458 566,046 662,566 Earnings applicable to common shares 230,927 Long-term incentive plan activity-net 113 582 Preferred stock retired (150,000 shares) (15,000) (155) Common stock dividends declared (181,867) - ----------------------------- --------- --------- --------- --------- --------- Balance, December 31, 1996 78,475 25,000 291,571 566,473 711,626 Earnings applicable to common shares 251,607 Long-term incentive plan activity-net 172 1,158 Common stock retired (3,062,490 shares) (7,656) (66,145) Common stock dividends declared (178,423) - ----------------------------- --------- --------- --------- --------- --------- Balance, December 31, 1997 $ 78,475 $ 25,000 $ 284,087 $ 501,486 $ 784,810 ============================= ========= ========= ========= ========= ========= See notes to consolidated financial statements.
50 ENOVA CORPORATION STATEMENTS OF CONSOLIDATED CAPITAL STOCK In thousands of dollars except call price
Balance at December 31 1997 1996 ----------- ---------- COMMON EQUITY Common stock, without par value, authorized 300,000,000 shares, outstanding: 1997, 113,634,744 shares; 1996, 116,628,735 shares $ 284,087 $ 291,571 Premium on capital stock 501,486 566,473 Retained earnings 784,810 711,626 ----------- ---------- Total common equity $1,570,383 $1,569,670 =========== ========== PREFERRED STOCK (A) Trading Call Not subject to mandatory redemption Symbol(B) Price $20 par value, authorized 1,375,000 shares --------- -------- 5% Series, 375,000 shares outstanding SDOPrA $24.00 $ 7,500 $ 7,500 4.50% Series, 300,000 shares outstanding SDOPrB $21.20 6,000 6,000 4.40% Series, 325,000 shares outstanding SDOPrC $21.00 6,500 6,500 4.60% Series, 373,770 shares outstanding -- $20.25 7,475 7,475 Without par value (C) $1.70 Series, 1,400,000 shares outstanding -- $25.85(D) 35,000 35,000 $1.82 Series, 640,000 shares outstanding SDOPrH $26.00(D) 16,000 16,000 ----------- ---------- Total not subject to mandatory redemption $ 78,475 $ 78,475 =========== ========== Subject to mandatory redemption Without par value (C) $1.7625 Series, 1,000,000 shares outstanding(E) -- $25.00(D) $ 25,000 $ 25,000 =========== =========== (A) All series of preferred stock have cumulative preferences as to dividends. The $20 par value preferred stock has two votes per share, whereas the no par value preferred stock is nonvoting. The $20 par value preferred stock has a liquidation value at par. The no par value preferred stock has a liquidation value of $25 per share. (B) All listed shares are traded on the American Stock Exchange. (C) SDG&E is authorized to issue 10,000,000 shares total (both subject to and not subject to mandatory redemption). Enova is authorized to issue 30,000,000 shares total, of which no shares were issued and outstanding at December 31, 1997. (D) The $1.70 and $1.7625 series are not callable until 2003; the $1.82 series is not callable until November 1998. All other series are currently callable. (E) 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. See notes to consolidated financial statements.
51 ENOVA CORPORATION STATEMENTS OF CONSOLIDATED LONG-TERM DEBT In thousands of dollars
First Call Balance at December 31 Date 1997 1996 ----------------- ---------- ---------- SDG&E First mortgage bonds 5.5% Series I, due March 1, 1997 4/15/67 $ -- $ 25,000 8.75% Series II, due March 1, 2023(A) 9/1/97 -- 25,000 9.625% Series JJ, due April 15, 2020 4/15/00 54,260 100,000 6.8% Series KK, due June 1, 2015(B) Non-callable 14,400 14,400 8.5% Series LL, due April 1, 2022 4/1/02 43,725 60,000 7.625% Series MM, due June 15, 2002 Non-callable 80,000 80,000 6.1% and 6.4% Series NN, due September 1, 2018 and 2019(A) 9/1/02 118,615 118,615 Various % Series OO, due December 1, 2027(C) (D) 250,000 250,000 5.9% Series PP, due June 1, 2018(A) 6/1/03 70,795 70,795 Variable % Series QQ, due June 1, 2018(A) (E) -- 14,915 5.85% Series RR, due June 1, 2021(B) 6/1/03 60,000 60,000 5.9% Series SS, due September 1, 2018(A) 9/1/03 92,945 92,945 Variable % Series TT, due September 1, 2020(A) (E) 57,650 57,650 Variable % Series UU, due September 1, 2020(A) (E) 16,700 16,700 -------------- ---------- ---------- Total 859,090 986,020 ---------- ---------- Unsecured bonds 5.90% Series CPCFA96A, due June 1, 2014(B) Non-callable 129,820 129,820 Variable % Series CV96A, due July 1, 2021(C) (E) 38,900 38,900 Variable % Series CV96B, due December 1, 2021(C) (E) 60,000 60,000 Variable % Series CV97A, due March 1, 2023(C) (E) 25,000 -- -------------- ---------- ---------- Total 253,720 228,720 ---------- ---------- Rate reduction bonds (F) 658,000 -- Capitalized leases 95,301 105,315 Other long-term debt 465 528 Unamortized discount on long-term debt (6,178) (2,128) Current portion of long-term debt (72,575) (33,639) ---------- ---------- Total SDG&E 1,787,823 1,284,816 ---------- ---------- Other Subsidiaries Debt incurred to acquire limited partnerships, various rates, payable annually through 2008 312,862 219,051 Other long-term debt 5,473 11,734 Current portion of long-term debt (49,125) (36,263) --------- --------- Total Other Subsidiaries 269,210 194,522 --------- --------- Total Enova $2,057,033 $1,479,338 =========== ========== (A) Issued to secure SDG&E's obligation under a series of loan agreements with the City of San Diego under which the city loaned the proceeds from the sale of industrial- development revenue bonds to the company to finance certain qualified facilities. All series are tax-exempt except QQ and UU. (B) Issued to secure SDG&E's obligation under a series of loan agreements with the California Pollution Control Financing Authority under which the Authority loaned proceeds from the sale of tax-exempt pollution-control revenue bonds to the company to finance certain qualified facilities. (C) Issued to secure SDG&E's obligation under a series of loan agreements with the City of Chula Vista under which the city loaned the proceeds from the sale of tax-exempt industrial-development revenue bonds to the company to finance certain qualified facilities. (D) The first call date for $75 million is December 1, 2002. The remaining $175 million of the bonds is currently variable rate and is callable at various dates within one year. Of this, $45 million is subject to a floating-to-fixed rate swap, which expires December 15, 2002 (Note 8). (E) Callable at various dates within one year. 52 (F) Issued to facilitate 10-percent rate reduction mandated by California's electric restruturing law. Issued in December 1997 at an average interest rate of 6.26 percent. Bonds are secured by the revenue streams collected from customers over 10 years and are not secured by utility assets. See notes to consolidated financial statements.
53 ENOVA CORPORATION STATEMENTS OF CONSOLIDATED FINANCIAL INFORMATION BY SEGMENTS OF BUSINESS
In thousands of dollars At December 31 or for the years then ended 1997 1996 1995 - ---------------------------------- ----------- ----------- ----------- Operating Revenues (A) $ 2,217,007 $ 1,993,474 $ 1,870,676 =========== =========== =========== Operating Income Electric operations $ 257,706 $ 269,038 $ 263,346 Gas operations 59,382 39,724 51,654 Other 27,082 26,201 30,650 ----------- ----------- ----------- Total $ 344,170 $ 334,963 $ 345,650 =========== =========== =========== Depreciation and Decommissioning Electric operations $ 286,804 $ 279,251 $ 227,616 Gas operations 37,078 35,027 33,225 Other 23,556 18,212 17,398 ----------- ----------- ----------- Total $ 347,438 $ 332,490 $ 278,239 =========== =========== =========== Utility Plant Additions (B) Electric operations $ 160,689 $ 167,166 $ 171,151 Gas operations 36,495 41,684 49,597 ----------- ----------- ----------- Total $ 197,184 $ 208,850 $ 220,748 =========== =========== =========== Identifiable Assets Utility plant - net Electric operations $ 2,487,472 $ 2,625,620 $ 2,737,201 Gas operations 448,612 448,751 441,140 ----------- ----------- ----------- Total 2,936,084 3,074,371 3,178,341 ----------- ----------- ----------- Inventories Electric operations 50,354 47,445 53,828 Gas operations 15,036 15,633 14,131 Other 1,684 359 -- ----------- ----------- ----------- Total 67,074 63,437 67,959 ----------- ----------- ----------- Other identifiable assets Electric operations 770,885 697,145 802,172 Gas operations 128,525 161,252 148,714 Other (C) 699,191 488,102 434,940 ----------- ----------- ----------- Total 1,598,601 1,346,499 1,385,826 ----------- ----------- ----------- Other Utility Assets 632,165 164,930 116,498 ----------- ----------- ----------- Total Assets $ 5,233,924 $ 4,649,237 $ 4,748,624 =========== =========== =========== (A) The detail to operating revenues is provided in the Statements of Consolidated Income. The gas operating revenues shown therein include $14 million in 1997, $9 million in 1996 and $9 million in 1995, representing the gross margin on sales to the electric segment. These margins arose from interdepartmental transfers of $144 million in 1997, $111 million in 1996 and $85 million in 1995, based on transfer pricing approved by the California Public Utilities Commission in tariff rates. (B) Excluding allowance for equity funds used during construction. (C) Includes $378 million in real estate investments. Utility income taxes and corporate expenses are allocated between electric and gas operations in accordance with regulatory accounting requirements. See notes to consolidated financial statements.
54 ENOVA CORPORATION QUARTERLY FINANCIAL DATA (UNAUDITED) In thousands except per share amounts
Quarter ended March 31 June 30 September 30 December 31 - ------------------------------------------------------------------------------------------ 1997 Operating revenues $ 507,930 $ 501,481 $ 581,058 $ 626,538 Operating expenses 438,535 416,241 485,699 532,362 ----------- ---------- ---------- ----------- Operating income 69,395 85,240 95,359 94,176 Other income and (deductions) 6,086 (124) (3,425) 14,267 Net interest charges and preferred dividends 26,615 28,738 26,868 27,146 ----------- ---------- ---------- ----------- Earnings applicable to common shares $ 48,866 $ 56,378 $ 65,066 $ 81,297 Average common shares outstanding 116,452 113,616 113,616 113,643 Earnings per common share (basic and diluted)* $ 0.42 $ 0.50 $ 0.57 $ 0.72 1996 Operating revenues $ 465,897 $ 470,967 $ 507,593 $ 549,017 Operating expenses 372,905 396,442 420,307 468,857 ----------- ---------- ---------- ----------- Operating income 92,992 74,525 87,286 80,160 Other income 1,168 11 4,373 420 Net interest charges and preferred dividends 28,108 27,186 28,914 25,800 ----------- ---------- ---------- ----------- Earnings applicable to common shares $ 66,052 $ 47,350 $ 62,745 $ 54,780 Average common shares outstanding 116,570 116,565 116,566 116,587 Earnings per common share (basic and diluted)* $ 0.57 $ 0.41 $ 0.54 $ 0.47 These amounts are unaudited, but in the opinion of Enova reflect all adjustments necessary for a fair presentation. * The sum of quarterly earnings per share does not equal the annual total due to rounding.
Quarterly Common Stock Data (Unaudited)
1997 1996 First Second Third Fourth First Second Third Fourth Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter Market price High 23 24 3/8 25 1/4 27 1/8 24 3/4 23 1/8 23 23 Low 21 5/8 21 3/8 23 3/8 23 15/16 21 5/8 20 3/8 20 1/2 21 5/8 Dividends declared $0.39 $0.39 $0.39 $0.39 $0.39 $0.39 $0.39 $0.39
55 ENOVA CORPORATION Ratings at December 31, 1997 (Unaudited)
Issue Standard & Poor's Moody's Bonds A+ A1 Commercial paper A-1 P-1 Preferred stock A a2 The presentation of these ratings is not a recommendation to buy, sell or hold these securities.
56 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Enova Corporation: We have audited the accompanying consolidated balance sheets and the statements of consolidated capital stock and of consolidated long- term debt of Enova Corporation and subsidiaries as of December 31, 1997 and 1996, and the related statements of consolidated income, consolidated changes in capital stock and retained earnings, consolidated cash flows, and consolidated financial information by segments of business for each of the three years in the period ended December 31, 1997. These consolidated 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 Enova Corporation and subsidiaries as of December 31, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. /S/ DELOITTE & TOUCHE LLP DELOITTE & TOUCHE LLP San Diego, California February 23, 1998 57 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ENOVA CORPORATION NOTE 1: BUSINESS COMBINATION In October 1996 Enova Corporation and Pacific Enterprises (PE), parent company of Southern California Gas Company (SoCalGas), announced an agreement to combine the two companies. As a result of the combination, (i) each outstanding share of common stock of Enova will be converted into one share of common stock of the new company, (ii) each outstanding share of common stock of PE will be converted into 1.5038 shares of common stock of the new company and (iii) the preferred stock and preference stock of SDG&E, PE and SoCalGas will remain outstanding. The combination was unanimously approved by the boards of directors of both companies and subsequently was approved by the shareholders of both companies. The combination will be a tax-free transaction and is expected to be accounted for as a pooling of interests. Enova and PE have selected Sempra Energy as the name of the new combined company, with the corporate headquarters to be located in San Diego, California. Headquarters for SDG&E and SoCalGas, whose names will be retained, will remain in San Diego and Los Angeles, California, respectively. Consummation of the combination is conditional upon the approvals of the California Public Utilities Commission and various other regulatory bodies, with completion expected in the summer of 1998. On February 23, 1998, the CPUC's administrative law judge handling the proceeding issued a draft decision that proposed approval of the combination. Among other things, the draft decision proposed 50/50 sharing of the net cost savings resulting from the combination between shareholders and customers, but only for five years rather than the 10 years sought. The draft decision would reduce the net shareable savings from $1.1 billion to $340 million. The CPUC decision is scheduled for the end of March 1998. Additional information concerning Enova/PE joint activities is discussed in Note 3. NOTE 2: SIGNIFICANT ACCOUNTING POLICIES Nature of Operations On January 1, 1996, Enova Corporation (referred to herein as Enova, which includes the parent and its wholly owned subsidiaries) became the parent of SDG&E and its unregulated subsidiaries (referred to herein as nonutility subsidiaries). SDG&E's outstanding common stock was converted on a share-for-share basis into Enova common stock. SDG&E's debt securities, preferred and preference stock were unaffected and remain with SDG&E. The consolidated financial statements include Enova and its wholly owned subsidiaries. The subsidiaries include SDG&E, Califia, Enova Financial, Enova Energy, Enova Technologies, Enova International and Pacific Diversified Capital. In 1997, nonutility subsidiaries contributed 8 percent to operating income (8 percent in 1996 and 9 percent in 1995). Utility Plant and Depreciation Utility plant represents the buildings, equipment and other facilities used by SDG&E to provide electric and gas 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 industry restructuring and its effect on utility plant is included in Note 10. Utility plant in service by major functional categories at December 31, 1997, are: electric generation $1.8 billion, electric distribution $2.3 billion, electric transmission $0.7 billion, other electric $0.3 billion and gas operations $0.8 billion. The corresponding amounts at December 31, 1996, were essentially the same as 1997. Accumulated depreciation and decommissioning of electric and gas utility plant in service at December 31, 1997, are $2.6 billion and $0.4 billion, respectively, and at December 31, 1996, were $2.2 billion and $0.4 billion, respectively. 58 Depreciation expense is based on the straight-line method over the useful lives of the assets or a shorter period prescribed by the California Public Utilities Commission (CPUC) (for SONGS, see below). The provisions for depreciation as a percentage of average depreciable utility plant (by major functional categories) in 1997 and (in 1996, 1995, respectively) are: electric generation 8.83 (7.57, 4.04), electric distribution 4.39 (4.38, 4.36), electric transmission 3.28 (3.25, 3.21), other electric 6.02 (5.95, 5.89) and gas operations 4.03 (4.07, 4.06). The increases for electric generation in 1997 and 1996 reflect the accelerated recovery of San Onofre Nuclear Generating Station (SONGS) Units 2 and 3 approved by the CPUC in April 1996. Inventories Included in inventories at December 31, 1997, are SDG&E's $43 million of materials and supplies ($40 million in 1996), and $22 million of fuel oil and natural gas ($23 million in 1996). Materials and supplies are valued at average cost; fuel oil and natural gas are valued by the last-in first-out (LIFO) method. Other Current Assets Included in other current assets at December 31, 1997, is $44 million for Enova's current and deferred income taxes ($47 million in 1996). Included therein is SDG&E's portion of $26 million ($33 million in 1996). Short-term Borrowings There were no short-term borrowings at December 31, 1997, and 1996. At December 31, 1997, SDG&E had $50 million of bank lines available to support commercial paper. Commitment fees are paid on the unused portion of the lines and there are no requirements for compensating balances. Other Current Liabilities Included in other current liabilities at December 31, 1997, is Califia's $21 million current portion of deferred lease revenue ($33 million in 1996) and $35 million for SDG&E's accrued vacation and sick leave ($33 million in 1996). In 1996 the $21 million noncurrent portion of Califia's deferred lease revenue is included in "Deferred Credits and Other Liabilities." The deferred revenue is amortized over the lease terms that end in 1998. Allowance for Funds Used During Construction (AFUDC) The allowance represents the cost of funds used to finance the construction of utility plant and is added to the cost of utility plant. AFUDC also increases income, as an offset to interest charges shown in the Statements of Consolidated Income, although it is not a current source of cash. The average rate used to compute AFUDC was 9.35 percent in 1997, 9.36 percent in 1996 and 9.74 percent in 1995. Effects of Regulation SDG&E's accounting policies conform with generally accepted accounting principles for regulated enterprises and reflect the policies of the CPUC and the Federal Energy Regulatory Commission. SDG&E has been preparing its 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 revenues for amounts due to customers. To the extent that a portion of SDG&E's operations is no longer subject to SFAS No. 71, or recovery is no longer probable as a result of changes in regulation or SDG&E's 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 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 10, California enacted a law restructuring the electric utility industry. The law adopts the December 1995 CPUC policy decision, and allows California utilities the opportunity to recover existing utility plant and regulatory assets over a transition period that ends in 2001. SDG&E has ceased the application of SFAS No. 71 with respect to its electric-generation business. SDG&E continues to evaluate the applicability of SFAS No. 121 as industry restructuring progresses. Additional information 59 concerning regulatory assets and liabilities is described below in "Revenues and Regulatory Balancing Accounts" and in Note 10. Revenues and Regulatory Balancing Accounts Revenues from utility customers have consisted of deliveries to customers and the changes in regulatory balancing accounts. 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 previously were eliminated by balancing accounts authorized by the CPUC. This is still the case for natural gas sales. However, as a result of California's electric-restructuring law, beginning in 1997 overcollections recorded in the Energy Cost Adjustment Clause (ECAC) and Electric Revenue Adjustment Mechanism (ERAM) balancing accounts were transferred to the interim transition cost-balancing account, which is being applied to transition cost recovery (see Note 10). At December 31, 1997, overcollections of $130 million were included in this account. Of this amount, $98 million of overcollections were recorded at December 31, 1996. The elimination of ECAC and ERAM resulted in quarter-to-quarter earnings volatility in 1997. This earnings volatility will continue in future years. Additional information on industry restructuring is included in Note 10. Deferred Charges and Other Assets Deferred charges include SDG&E's unrecovered premium on early retirement of debt and other regulatory- related expenditures that SDG&E expects to recover in future rates, excluding generation operations (discussed above). These items are amortized as recovered in rates. The net regulatory assets associated with SDG&E's generation operations at December 31, 1997, were credited to the interim transition cost balancing account. Deferred Credits and Other Liabilities Other liabilities at December 31, 1997, include $117 million of accumulated decommissioning costs associated with SONGS Unit 1 ($96 million in 1996), which was permanently shut down in 1992. Additional information on SONGS Unit 1 decommissioning costs is included in Note 5. Discontinued Operations Enova's financial statements for periods prior to 1996 reflect the June 1995 sale of Wahlco Environmental Systems, Inc. as discontinued operations, in accordance with Accounting Principles Board Opinion No. 30, "Reporting the Effects of a Disposal of a Segment of Business." Discontinued operations are summarized in the table below: In millions of dollars 1995 - --------------------------------------------------------------------- Revenues $ 24 Loss from operations before income taxes -- Loss on disposal before income taxes (12) Income tax benefits 12 The loss on disposal of Wahlco reflects the sale of Wahlco and Wahlco's 1995 net operating losses prior to the sale. Use of Estimates in the Preparation of Financial Statements The preparation of 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 Temporary investments 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 to conform to the current year's format. 60 NOTE 3: SIGNIFICANT ACQUISITIONS AND JOINT VENTURES Sempra Energy Trading On December 31, 1997, Enova and Pacific Enterprises completed their acquisition (50% interest each) of Sempra Energy Trading (formerly AIG Trading Corporation), a leading natural gas and power marketing firm headquartered in Greenwich, Connecticut, for a total cost of $225 million. Sempra Energy Trading's primary business focus is wholesale trading and marketing of natural gas, power and oil to customers primarily in North America. Sempra Energy Trading had net assets of $30 million at December 31, 1997. An allocation of the purchase price has not yet been completed. The difference between the cost and underlying equity in the net assets will be amortized over a period of not more than 15 years. As of December 31, 1997, Sempra Energy Trading's trading assets and trading liabilities approximate the following: In millions of dollars - --------------------------------------------------------------------- Trading Assets Unrealized gains on swaps and forwards $ 497 Due from commodity clearing organization and clearing brokers 41 OTC commodity options purchased 33 Due from trading counterparties 16 - --------------------------------------------------------------------- Total $ 587 ===================================================================== Trading Liabilities Unrealized losses on swaps and forwards $ 487 Due to trading counterparties 41 OTC commodity options written 29 - --------------------------------------------------------------------- Total $ 557 ===================================================================== The notional amounts of Sempra Energy Trading's financial instruments are provided below and include a maturity profile as of December 31, 1997, based upon the expected timing of the future cash flows. The notional amounts do not necessarily represent the amounts exchanged by parties to the financial instruments and do not measure Sempra Energy Trading'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, Sempra Energy Trading is exposed to much smaller amounts potentially subject to risk.
Within One to Five Five to Ten After In millions of dollars One Year Years Years Ten Years Total - -------------------------------------------------------------------------------- Forwards and commodity swaps $3,175 $458 $90 $74 $3,797 Futures 856 189 -- -- 1,045 Options purchased 704 52 -- -- 756 Options written 592 62 -- -- 654 - -------------------------------------------------------------------------------- Total $5,327 $761 $90 $74 $6,252 ================================================================================
Enova and Pacific Enterprises have jointly and severally guaranteed certain trading obligations of Sempra Energy Trading with credit worthy counterparties in connection with authorized transactions and in connection with funding. The total obligations guaranteed by the companies as of December 31, 1997, are $190 million. Sempra Energy Solutions In January 1998 Sempra Energy Solutions completed the acquisition of CES/Way International, a leading national energy-service 61 provider. In September 1997 Sempra Energy Solutions formed a joint venture with Bangor Hydro to build, own and operate a $40 million natural gas distribution system in Bangor, Maine. In December 1997, Sempra Energy Solutions signed a partnership agreement with Frontier Utilities to build and operate a $55 million natural gas distribution system in North Carolina. Enova International Gas Distribution Projects Enova International, Pacific Enterprises International and Proxima S.A. de C.V., partners in the Mexican companies Distribuidora de Gas Natural 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 plans to invest $50 million in the gas distribution project in Chihuahua over the next five years. El Dorado Power Project In December 1997 Enova Power Corporation, a subsidiary of Enova Energy, and Houston Industries Power Generation (HIPG) formed a joint venture, El Dorado Energy, to build, own and operate a 480-megawatt natural gas-fired plant in Boulder City, Nevada. Total cost of construction is expected to be $280 million, with each company providing 50 percent of the funding. Enova Power and HIPG each will be responsible for 50 percent of the plant's fuel procurement and output marketing. Construction on the plant is expected to begin in the first quarter of 1998 and be completed in the fourth quarter of 1999. NOTE 4: LONG-TERM DEBT Amounts and due dates of long-term debt are shown on the Statements of Consolidated Long-Term Debt. Excluding capital leases, which are described in Note 9, maturities of long-term debt for SDG&E are $66 million due in 1998, $65 million due in 1999, 2000 and 2001, and $145 million due in 2002. Total maturities of long-term debt for nonutility subsidiaries are $49 million for 1998, $53 million for 1999, $44 million for 2000, $35 million for 2001 and $34 million for 2002. SDG&E has CPUC authorization to issue an additional $185 million in long-term debt. First Mortgage Bonds First mortgage bonds are secured by a lien on substantially all of SDG&E's utility plant. Additional first mortgage bonds may be issued upon compliance with the provisions of the bond indenture, which provides for, among other things, the issuance of an additional $1.3 billion of first mortgage bonds at December 31, 1997. Certain first mortgage bonds may be called at SDG&E's option. First mortgage bonds totaling $249 million have variable-interest- rate provisions. During 1997, SDG&E retired $127 million of first mortgage bonds, of which $102 million were retired prior to scheduled maturity. Unsecured Bonds During 1997, SDG&E issued $25 million of unsecured bonds. Unsecured bonds totaling $124 million have variable-interest-rate provisions. 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. 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. Additional information on rate-reduction bonds and electric industry restructuring is discussed in Note 10. Other At December 31, 1997, SDG&E had $340 million of bank lines, providing a committed source of long-term borrowings, with no debt outstanding. Bank lines, unless renewed by SDG&E, expire in 1998 ($60 million) and in 2000 ($280 million). Commitment fees are paid on the unused portion of the lines and there are no requirements for compensating balances. 62 Nonutility loans (Enova Financial and Califia) of $318 million and $231 million at December 31, 1997, and 1996, respectively, are secured by real estate and equipment. SDG&E's interest payments, including those applicable to short-term borrowings, amounted to $89 million in 1997, $93 million in 1996 and $100 million in 1995. Nonutility interest payments amounted to $12 million in 1997, $12 million in 1996 and $14 million in 1995. 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, 1997, SDG&E had such an agreement, maturing in 2002, with underlying debt of $45 million. See additional information in Note 8. 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. NOTE 5: FACILITIES UNDER JOINT OWNERSHIP SONGS and the Southwest Powerlink transmission line are owned jointly with other utilities. SDG&E's interests at December 31, 1997, are: In millions of dollars - ---------------------------------------------------------------------- Southwest Project SONGS Powerlink - ---------------------------------------------------------------------- Percentage ownership 20 89 Utility plant in service $1,143 $ 217 Accumulated depreciation $ 593 $ 96 Construction work in progress $ 9 $ -- SDG&E's share of operating expenses is included in the Statements of Consolidated Income. Each participant in the projects must provide its own financing. The amounts specified above for SONGS include nuclear production, transmission and other facilities. 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 Code and other regulatory bodies. SDG&E's share of decommissioning costs for the SONGS units is estimated to be $401 million in current dollars and is based on studies performed and updated periodically by outside consultants. The most recent study was performed in 1993. A new study is planned for 1998. A new escalation methodology was utilized to estimate the liability in 1997. This methodology was authorized by the CPUC in its 1996 Performance-Based Ratemaking decision for Southern California Edison (principal owner of SONGS), and incorporates an internal rate of return calculation that results in higher escalation amounts. Although electric industry restructuring legislation requires that stranded costs, which include SONGS plant costs, be amortized in rates by 2001, the recovery of decommissioning costs is allowed until the time as 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 SDG&E's share of future decommissioning costs. The depreciation and decommissioning expense reflected on the Statements of Consolidated Income includes $22 million of decommissioning expense for each of the years 1997, 1996 and 1995. The amounts collected in rates are invested in externally managed trust funds. In accordance with SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities," the securities held by the trust are considered available for sale and are adjusted to market value ($399 million at December 31, 1997, and $328 million at December 31, 1996) and shown on the Consolidated Balance Sheets. The fair values reflect unrealized gains of $89 million and $50 million at December 31, 1997, and 1996, respectively. The corresponding accumulated accrual is included on the Consolidated Balance Sheets in 63 "Accumulated Depreciation and Decommissioning" for SONGS Units 2 and 3 and in "Deferred Credits and Other Liabilities" for Unit 1. SONGS Unit 1 was permanently shut down in 1992. 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 SDG&E's future balance sheets include a liability for the estimated decommissioning costs, and a related increase in the cost of utility plant. Additional information regarding SONGS is included in Notes 9 and 10. NOTE 6: EMPLOYEE BENEFIT PLANS Pension Plan SDG&E has a defined-benefit pension plan, which covers substantially all of its employees. Benefits are related to the employees' compensation. Plan assets consist primarily of common stocks and bonds. SDG&E funds the plan based on the projected unit credit actuarial cost method. Net pension cost consisted of the following for the years ended December 31: In thousands of dollars 1997 1996 1995 - ---------------------------------------------------------------------- Cost related to current service $16,756 $18,547 $14,598 Interest on projected benefit obligation 39,089 37,253 30,760 Return on plan assets (119,554) (72,829) (132,674) Net amortization and deferral 63,500 25,315 93,708 - ---------------------------------------------------------------------- Cost pursuant to general accounting standards (209) 8,286 6,392 Regulatory adjustment -- (15,286) 608 - ---------------------------------------------------------------------- Net cost (benefit) $ (209) $(7,000) $7,000 ====================================================================== The plan's status was as follows at December 31: In thousands of dollars 1997 1996 - ---------------------------------------------------------------------- Accumulated benefit obligation Vested $495,278 $435,029 Non-vested 11,637 12,321 - ---------------------------------------------------------------------- Total $506,915 $447,350 ====================================================================== Plan assets at fair value $699,000 $598,610 Projected benefit obligation 589,911 539,391 - ---------------------------------------------------------------------- Plan assets less projected benefit obligation 109,089 59,219 Unrecognized effect of accounting change (761) (950) Unrecognized prior service cost 28,444 31,315 Unrecognized actuarial gains (204,061) (157,082) - ---------------------------------------------------------------------- Net liability $(67,289) $(67,498) ====================================================================== The projected benefit obligation assumes a 7.25 percent actuarial discount rate in 1997 (7.50 percent in 1996) and a 5.0 percent average annual compensation increase. The expected long-term rate of return on plan assets is 8.5 percent. The increase in the total accumulated benefit obligation and projected benefit obligation at December 31, 1997, is due primarily to a decrease in the actuarial discount rate. SDG&E's annual cost for a supplemental retirement plan for a limited number of key employees was approximately $3 million in 1997, 1996 and 1995. 64 Post-Retirement Health Benefits SDG&E provides certain health and life insurance benefits to retired employees. These benefits are accrued during the employee's years of service, up to the year of benefit eligibility. SDG&E is recovering the cost of these benefits based upon actuarial calculations and funding limitations. The costs for the benefits were $4 million in 1997, $5 million in 1996 and $5 million in 1995. These costs include $2 million of amortization per year for the unamortized transition obligation (arising from the initial implementation of this accounting policy) of approximately $31 million, which is being amortized through 2012. Savings Plan Essentially all employees are eligible to participate in SDG&E's savings plan. Eligible employees may make a contribution of 1 percent to 15 percent of their base pay to the savings plan for investment in mutual funds or in Enova common stock. SDG&E contributes amounts equal to up to 3 percent of participants' compensation for investment in Enova common stock. SDG&E's annual compensation expense for this plan was $3 million in 1997, $2 million in 1996 and $2 million in 1995. Stock-Based Compensation Enova has a long-term incentive stock compensation plan that provides for aggregate awards of up to 2,700,000 shares of Enova common stock. The plan terminates in April 2005. In each of the last 10 years, 49,000 shares to 75,000 shares of stock were issued to officers and key employees, subject to forfeiture over four years if certain corporate goals are not met. The long-term incentive stock compensation plan also provides for the granting of stock options. In October 1997, Enova rescinded all options granted in October 1996. There were no stock options outstanding at December 31, 1997. As permitted by SFAS No. 123, "Accounting for Stock-Based Compensation," SDG&E has adopted the disclosure-only requirements of SFAS No. 123 and continues to account for stock-based compensation by applying the provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." 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. SDG&E's compensation expense for this plan was approximately $1 million in 1997, $1 million in 1996 and $2 million in 1995. 65 NOTE 7: INCOME TAXES Income tax payments totaled $162 million in 1997, $176 million in 1996 and $148 million in 1995. The components of accumulated deferred income taxes at December 31 are as follows: In thousands of dollars 1997 1996 - ---------------------------------------------------------------------- Deferred tax liabilities Differences in financial and tax bases of utility plant $567,804 $628,617 Loss on reacquired debt 30,535 26,399 Other 91,708 80,033 - ---------------------------------------------------------------------- Total deferred tax liabilities 690,047 735,049 - ---------------------------------------------------------------------- Deferred tax assets Unamortized investment tax credits 62,144 66,729 Equipment leasing activities 8,494 22,333 Regulatory balancing accounts 27,903 37,010 Unbilled revenue 22,365 21,923 Other 89,856 123,158 - --------------------------------------------------------------------- Total deferred tax assets 210,762 271,153 - --------------------------------------------------------------------- Net deferred income tax liability 479,285 463,896 Current portion (net asset) 21,745 33,504 - --------------------------------------------------------------------- Non-current portion (net liability) $501,030 $497,400 ===================================================================== The components of income tax expense are as follows: In thousands of dollars 1997 1996 1995 - --------------------------------------------------------------------- Current Federal $93,040 $115,410 $134,212 State 38,413 39,939 42,630 - --------------------------------------------------------------------- Total current taxes 131,453 155,349 176,842 - --------------------------------------------------------------------- Deferred Federal 23,222 434 (23,914) State 1,600 (1,518) (13,464) - --------------------------------------------------------------------- Total deferred taxes 24,822 (1,084) (37,378) - --------------------------------------------------------------------- Deferred investment tax credits - net (6,073) (5,791) (4,859) - --------------------------------------------------------------------- Total income tax expense $150,202 $148,474 $134,605 ===================================================================== Federal and state income taxes are allocated between operating income and other income. 66 The reconciliation of the statutory federal income tax rate to the effective income tax rate is as follows: 1997 1996 1995 - --------------------------------------------------------------------- Statutory federal income tax rate 35.0 % 35.0 % 35.0 % Depreciation 8.1 6.3 5.5 State income taxes - net of federal income tax benefit 7.0 6.9 5.5 Tax credits (10.8) (9.5) (7.6) Equipment leasing activities (2.3) (2.8) (2.8) Repair allowance (1.9) (1.2) (3.0) Other - net 2.3 4.4 4.8 - --------------------------------------------------------------------- Effective income tax rate 37.4 % 39.1 % 37.4 % ===================================================================== NOTE 8: FINANCIAL INSTRUMENTS Fair Value The fair values of financial instruments (cash, temporary investments, funds held in trust, notes receivable, investments in limited partnerships, dividends payable, short- and long-term debt, deposits from customers, and preferred stock subject to mandatory redemption) are not materially different from the carrying amounts, except for long-term debt. The carrying amounts and fair value of long- term debt are $2.1 billion and $2.2 billion, respectively, at December 31, 1997, and $1.5 billion and $1.5 billion, respectively, at December 31, 1996. The fair values of SDG&E's first mortgage bonds 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 values of the future cash flows, discounted at rates available for similar notes with comparable maturities. The fair values of the rate-reduction bonds issued in December 1997 are estimated to approximate carrying value due to the relatively short period of time between the issuance date and the valuation date, and the relative market stability during those periods. Off-Balance-Sheet Financial Instruments Enova's policy is to use derivative financial instruments to reduce its exposure to fluctuations in interest rates, foreign-currency exchange rates and natural gas prices. These financial instruments expose Enova to market and credit risks which may at times be concentrated with certain counterparties, although counterparty nonperformance is not anticipated. Interest-Rate-Swap Agreements SDG&E periodically enters into interest- rate-swap agreements to moderate its exposure to interest-rate changes and to lower its overall cost of borrowing. These swap 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 income statement as part of interest expense. At December 31, 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 derivative 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 $2 million at December 31, 1997, and at December 31, 1996. Foreign-Currency Forward Exchange Contracts SDG&E's pension fund periodically uses foreign-currency forward contracts to reduce its exposure to exchange-rate fluctuations associated with certain investments in foreign equity securities. These contracts generally have maturities ranging from three to six months. At December 31, 1997, there were no foreign-currency forward contracts outstanding. 67 Energy Derivatives SDG&E uses energy derivatives for both hedging and trading purposes within certain limitations imposed by company policies. These derivative financial instruments include forward contracts, swaps, options and other contracts which have maturities ranging from 30 days to nine months. SDG&E's accounting policy is to adjust 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 gas revenue or expense, whichever is appropriate, on the Consolidated Income Statement. As of December 31, 1997, the net fair value of open positions was $5.9 million. The net unrealized profit of these open positions was $0.3 million. These positions hedge approximately 6 percent of SDG&E's annual total purchased-gas volumes. The average fair value of derivative financial instruments during 1997 was an obligation of $0.2 million. The net gains arising from these activities during 1997 were $2.5 million. Information on derivative financial instruments of Sempra Energy Trading is provided in Note 3. Market and Credit Risk SDG&E and Sempra Energy Trading utilize a variety of financial structures, products and terms which require the company to manage, on a portfolio basis, the resulting market risks inherent in these transactions, subject to parameters established by company policies. Market risks are monitored separately from the groups that create or actively manage these risk exposures to ensure compliance with the company's stated risk management policies. Credit risk relates to the risk of loss that would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. SDG&E and Sempra Energy Trading avoid concentration of counterparties and maintain credit policies with regard to counterparties that management believes significantly minimize overall credit risk. A Risk Management Committee, composed of Enova and Pacific Enterprises officers, is responsible for monitoring operating performance and compliance with established risk management policies for Sempra Energy Solutions and its subsidiaries. NOTE 9: CONTINGENCIES AND COMMITMENTS Purchased-Power Contracts SDG&E buys electric power under several short-term and long-term contracts. Purchases are for up to 7 percent of plant capacity under contracts with other utilities and up to 100 percent of plant capacity under contracts with nonutility suppliers. No one supplier provides more than 3 percent of SDG&E's total system requirements. The contracts expire on various dates between 1998 and 2025. At December 31, 1997, the estimated future minimum payments under the contracts were: In millions of dollars - --------------------------------------------------------------------- 1998 $234 1999 232 2000 200 2001 183 2002 134 Thereafter 2,462 - --------------------------------------------------------------------- Total minimum payments $3,445 ===================================================================== These payments 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 energy payments, under the contracts were $421 million in 1997, $296 million in 1996 68 and $329 million in 1995. Payments under purchased-power contracts increased in 1997 due to increased sales volume and lower nuclear generation availability. In November 1997, SDG&E announced a plan to auction its power plants and other electric-generating resources, which include its long-term purchased-power contracts. Additional information on SDG&E's plan to divest its electric-generating assets is discussed in Note 10. Natural Gas Contracts SDG&E has a contract with Southern California Gas Company (SoCalGas) that provides SDG&E with intrastate transportation capacity on SoCalGas' pipelines. This contract is currently being renegotiated and continues on a month-to-month basis under the original terms until a new agreement is reached. The commitment presumes a contract renewal for one year. SDG&E's long-term contracts with interstate pipelines for transportation capacity expire on various dates between 2007 and 2023. SDG&E's contract with SoCalGas for 8 billion cubic feet of natural gas storage capacity expires in March 1998. A new agreement has been reached for 6 billion cubic feet of natural gas storage capacity from April 1998 through March 1999. 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 one supplier, with gas being delivered under the terms of the settlement agreement. The remaining suppliers have ceased deliveries pending legal resolution. A U.S. Court of Appeals has upheld a U.S. District Court's invalidation of the contracts with two of these suppliers, although the value of the gas delivered has not yet been determined by the court. At December 31, 1997, the future minimum payments under natural gas contracts were: Transportation Natural In millions of dollars and Storage Gas - ---------------------------------------------------------------------- 1998 $65 $19 1999 15 17 2000 14 19 2001 14 21 2002 14 24 Thereafter 234 25 - ---------------------------------------------------------------------- Total minimum payments $356 $125 ====================================================================== Total payments under the contracts were $125 million in 1997, $100 million in 1996 and $95 million in 1995. 69 Leases SDG&E has nuclear fuel, office buildings, a generating facility and other properties that are financed by long-term capital leases. Utility plant includes $198 million at December 31, 1997, and $200 million at December 31, 1996, related to these leases. The associated accumulated amortization is $102 million and $95 million, respectively. SDG&E and nonutility subsidiaries also lease office facilities, computer equipment and vehicles under operating leases. Certain leases on office facilities contain escalation clauses requiring annual increases in rent ranging from 2 percent to 7 percent. The minimum rental commitments payable in future years under all noncancellable leases are: Operating Capitalized Leases Leases In millions of dollars Enova SDG&E SDG&E - --------------------------------------------------------------------- 1998 $35 $13 $26 1999 12 12 26 2000 12 12 20 2001 8 8 12 2002 8 8 12 Thereafter 36 36 20 - --------------------------------------------------------------------- Total future rental commitment $111 $89 116 - --------------------------------------------------------------------- Imputed interest (6% to 9%) (21) - --------------------------------------------------------------------- Net commitment $95 ===================================================================== Enova's rental payments totaled $81 million in 1997, $88 million in 1996 and $85 million in 1995. Included in these amounts are SDG&E payments of $43 million, $46 million and $44 million, respectively. Environmental Issues SDG&E's 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. SDG&E incurs significant costs to operate its facilities in compliance with these laws and regulations. The costs of compliance with environmental laws and regulations have been recovered in customer rates. Capital expenditures to comply with environmental laws and regulations were $4 million in 1997, $6 million in 1996 and $4 million in 1995, and are expected to be $38 million over the next five years. These expenditures primarily include the estimated cost of retrofitting SDG&E's power plants to reduce air emissions. SDG&E has been associated with various sites which may require remediation under federal, state or local environmental laws. SDG&E is unable to determine 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. Environmental liabilities that may arise from these assessments are recorded when remedial efforts are probable, and the costs can be estimated. 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. The decision allows recovery of 90 percent of cleanup costs and related third-party litigation costs and 70 percent of the related insurance-litigation expenses. As discussed in Note 10, restructuring of the California electric-utility industry will change the way utility rates are set and costs are recovered. Both the CPUC and state legislation have indicated that the California utilities will be allowed an opportunity to recover existing utility plant and regulatory assets over a transition period that ends in 2001. SDG&E has asked the CPUC that beginning on January 1, 1998, the collaborative account be modified, and that electric- generation-related cleanup costs be eligible for transition cost recovery. A CPUC decision is still pending. Depending on the final outcome of industry restructuring and the impact of competition, the 70 costs of compliance with environmental regulations may not 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 using the DOE services are contributing 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. SDG&E's annual contribution is $1 million, and will be recovered as part of decommissioning costs (see Note 10). Litigation Enova and its subsidiaries, including SDG&E, are 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 Enova's results of operations, financial condition or liquidity. Distribution System Conversion Under a CPUC-mandated program and through franchise agreements with various cities, SDG&E is committed, in varying amounts, to convert overhead distribution facilities to underground. As of December 31, 1997, the aggregate unexpended amount of this commitment was approximately $100 million. Capital expenditures for underground conversions were $17 million in 1997, $15 million in 1996 and $12 million in 1995. Concentration of Credit Risk SDG&E grants credit to its utility customers, substantially all of whom are located in its service territory, which covers all of San Diego County and an adjacent portion of Orange County. NOTE 10: INDUSTRY RESTRUCTURING In September 1996, the state of California enacted a law restructuring California's electric-utility industry (AB 1890). The legislation adopts the December 1995 CPUC policy decision restructuring the industry to stimulate competition and reduce rates. The new law supersedes the CPUC policy decision when in conflict. Beginning on March 31, 1998, customers will be able to buy their electricity through a power exchange that will obtain power from qualifying facilities, nuclear units and, lastly, from the lowest- bidding suppliers. The power exchange will serve as a wholesale power pool allowing all energy producers to participate competitively. An Independent System Operator will schedule power transactions and access to the transmission system. Consumers also may choose either to continue to purchase from their local utility under 71 regulated tariffs or to enter into private contracts with generators, brokers or others. The local utility will continue to provide distribution service regardless of which source the consumer chooses. Utilities are allowed a reasonable opportunity to recover their stranded costs through December 31, 2001. 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. 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. SDG&E's transition cost application filed in October 1996 identifies costs totaling $2 billion (net present value in 1998 dollars). These identified transition costs were determined to be reasonable by independent auditors selected by the CPUC, with $73 million requiring further action before being deemed recoverable transition costs. Of this amount, the CPUC has excluded from transition cost recovery $39 million in fixed costs relating to gas transportation to power plants, which SDG&E believes will be recovered through contracts with the ISO. Total transition costs include sunk costs, as well as ongoing costs the CPUC finds reasonable and necessary to maintain generation facilities through December 31, 2001. Both the CPUC policy decision and AB 1890 provide that above-market costs for existing purchased-power contracts may be recovered over the terms of the contracts or sooner. Qualifying facilities purchases include approximately 100 existing contracts, which extend as far as 2025. Other power purchases consist of two long-term contracts expiring in 2001 and 2013. Transition costs also include other items SDG&E has accrued under cost-of-service regulation. Nuclear decommissioning costs are nonbypassable until fully recovered, but are not included as part of transition costs. Through December 31, 1997, SDG&E has recovered transition costs of $0.2 billion for nuclear generation and $0.1 billion for nonnuclear generation. Additionally, overcollections of $0.1 billion recorded in the ECAC and ERAM balancing accounts as of December 31, 1997, have been applied to transition cost recovery, leaving approximately $1.6 billion for future recovery. Included therein is $0.4 billion for post-2001 purchased-power-contract payments that may be recovered after 2001, subject to an annual reasonableness review. SDG&E has 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, 1997, of $800 million ($200 million for fossil and $600 million for SONGS). The proceeds from the auction will be applied directly to SDG&E's transition costs. In December 1997, SDG&E filed with the CPUC for its approval of the auction plan. The sale of the nonnuclear-generating assets is expected to be completed by the end of the first quarter of 1999. During the 1998-2001 period, recovery of transition costs is limited by the rate freeze (discussed below). Management believes that the rates within the rate cap 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. The California legislation provides for a 10-percent reduction of residential and small commercial customers' rates, which began in January 1998, as a result of the utilities' receiving the proceeds of rate-reduction bonds issued by an agency of the state of California. 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 addition, the California legislation includes a rate freeze for all 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 June 1996 levels (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 cannot be increased above 9.43 cents per kwh, which includes the mandatory rate reduction and any impact of fuel cost changes. 72 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 the California investor-owned utilities may not meet the criteria of SFAS No. 71 with respect to their electric-generation net regulatory assets. SDG&E has ceased the application of SFAS No. 71 to its generation business, in accordance with the conclusion by the Emerging Issues Task Force of the Financial Accounting Standards Board that the application of SFAS 71 should be discontinued when deregulatory legislation is issued that determines that a portion of an entity's business will no longer be regulated. The discontinuance of SFAS No. 71 applied to the utilities' 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 business, subject to the rate cap. 73 Item 8. Financial Statements and Supplementary Data - San Diego Gas & Electric Company SAN DIEGO GAS & ELECTRIC COMPANY STATEMENTS OF CONSOLIDATED INCOME In thousands except per share amounts
For the years ended December 31 1997 1996 1995 ------------ ------------ ------------ Operating Revenues Electric $1,769,421 $1,590,882 $1,503,926 Gas 398,127 348,035 310,142 ------------ ------------ ------------ Total operating revenues 2,167,548 1,938,917 1,814,068 ------------ ------------ ------------ Operating Expenses Electric fuel 163,765 134,350 100,256 Purchased power 441,400 310,731 341,727 Gas purchased for resale 183,078 152,151 113,355 Maintenance 87,597 57,652 91,740 Depreciation and decommissioning 323,882 314,278 260,841 Property and other taxes 43,261 44,764 45,566 General and administrative 212,634 247,653 207,078 Other 177,760 166,391 166,303 Income taxes 217,083 202,185 172,202 ------------ ------------ ------------ Total operating expenses 1,850,460 1,630,155 1,499,068 ------------ ------------ ------------ Operating Income 317,088 308,762 315,000 ------------ ------------ ------------ Other Income and (Deductions) Allowance for equity funds used during construction 5,192 5,898 6,435 Taxes on nonoperating income (2,073) 4,227 (827) Other - net 4,243 (5,431) 923 ------------ ------------ ------------ Total other income and (deductions) 7,362 4,694 6,531 ------------ ------------ ------------ Income Before Interest Charges 324,450 313,456 321,531 ------------ ------------ ------------ Interest Charges Long-term debt 69,545 76,463 82,591 Short-term debt and other 13,825 12,635 17,886 Amortization of debt discount and expense, less premium 5,154 4,881 4,870 Allowance for borrowed funds used during construction (2,306) (3,288) (2,865) ------------ ------------ ------------ Net interest charges 86,218 90,691 102,482 ------------ ------------ ------------ Income From Continuing Operations 238,232 222,765 219,049 Discontinued Operations, Net of Income Taxes -- -- 14,408 ------------ ------------ ------------ Net Income (before preferred dividend requirements) 238,232 222,765 233,457 Preferred Dividend Requirements 6,582 6,582 7,663 ------------ ------------ ------------ Earnings Applicable to Common Shares $ 231,650 $ 216,183 $ 225,794 ============ ============ ============ See notes to consolidated financial statements.
74 SAN DIEGO GAS & ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS In thousands of dollars
Balance at December 31 1997 1996 -------------- -------------- ASSETS Utility plant - at original cost $5,888,539 $5,704,464 Accumulated depreciation and decommissioning (2,952,455) (2,630,093) -------------- ------------- Utility plant - net 2,936,084 3,074,371 -------------- ------------- Nuclear decommissioning trust 399,143 328,042 -------------- ------------- Current assets Cash and temporary investments 536,050 81,409 Accounts receivable 229,148 187,986 Due from affiliates 125,417 -- Inventories 65,390 63,078 Other 51,840 33,227 -------------- ------------- Total current assets 1,007,845 365,700 -------------- ------------- Deferred taxes recoverable in rates 184,837 189,193 -------------- ------------- Deferred charges and other assets 126,584 203,210 -------------- ------------- Total $4,654,493 $4,160,516 ============== ============= CAPITALIZATION AND LIABILITIES Capitalization Common equity $1,387,363 $1,404,136 Preferred stock not subject to mandatory redemption 78,475 78,475 Preferred stock subject to mandatory redemption 25,000 25,000 Long-term debt 1,787,823 1,284,816 -------------- ------------- Total capitalization 3,278,661 2,792,427 -------------- ------------- Current liabilities Current portion of long-term debt 72,575 33,639 Accounts payable 161,039 174,884 Due to affiliates -- 7,214 Dividends payable 45,968 47,131 Interest accrued 10,468 12,824 Regulatory balancing accounts overcollected-net 58,063 35,338 Other 114,388 110,743 -------------- ------------- Total current liabilities 462,501 421,773 -------------- ------------- Customer advances for construction 37,661 34,666 Accumulated deferred income taxes - net 471,890 487,119 Accumulated deferred investment tax credits 62,332 64,410 Deferred credits and other liabilities 341,448 360,121 Contingencies and commitments (Notes 9 and 10) -- -- -------------- ------------- Total $4,654,493 $4,160,516 ============== ============= See notes to consolidated financial statements. 75
SAN DIEGO GAS & ELECTRIC COMPANY STATEMENTS OF CONSOLIDATED CASH FLOWS
In thousands of dollars For the years ended December 31 1997 1996 1995 ------------ ------------ ------------ Cash Flows from Operating Activities Income from continuing operations $ 238,232 $ 222,765 $ 219,049 Adjustments to reconcile income from continuing operations to net cash provided by operating activities Depreciation and decommissioning 323,882 314,278 260,841 Amortization of deferred charges and other assets 6,247 5,926 12,068 Amortization of deferred credits and other liabilities (4,238) (3,901) (1,169) Allowance for equity funds used during construction (5,192) (5,898) (6,435) Deferred income taxes and investment tax credits 10,713 (16,369) (42,046) Other - net 19,416 25,570 21,108 Changes in working capital components Accounts and notes receivable (41,162) 19,573 9,159 Inventories (2,312) 4,881 7,648 Other current assets (4,464) (14,119) (5,550) Interest and taxes accrued (40,169) (24,897) 15,737 Accounts payable and other current liabilities (142,831) 50,235 25,288 Regulatory balancing accounts 22,725 (37,313) 59,030 Cash flows provided(used) by discontinued operations -- (11,544) 49,188 ----------- ------------- ------------ Net cash provided by operating activities 380,847 529,187 623,916 ----------- ------------- ------------ Cash Flows from Financing Activities Dividends paid (256,168) (188,700) (188,288) Issuances of long-term debt 677,850 226,646 123,734 Repayment of long-term debt (133,267) (257,772) (126,164) Short-term borrowings-net -- -- (58,325) Repurchase of common stock -- -- (241) Redemption of preferred stock -- (15,155) (18) ------------ ------------ ------------ Net cash provided (used) by financing activities 288,415 (234,981) (249,302) ------------ ------------ ------------ Cash Flows from Investing Activities Utility construction expenditures (197,184) (208,850) (220,748) Contributions to decommissioning funds (22,038) (22,038) (22,038) Other - net 4,601 (2,664) (2,456) Discontinued operations -- -- (120,222) ------------ ------------ ------------ Net cash used by investing activities (214,621) (233,552) (365,464) ------------ ------------ ------------ Net increase 454,641 60,654 9,150 Cash and temporary investments, beginning of year 81,409 20,755 11,605 ------------ ------------ ------------ Cash and temporary investments, end of year $ 536,050 $ 81,409 $ 20,755 ============ ============ ============ Supplemental Disclosure of Cash Flow Information Interest payments, net of amounts capitalized $ 88,574 $ 93,652 $ 104,373 ============ ============ ============ Net assets of affiliates transferred to parent $ -- $ 150,095 $ -- ============ ============ ============ See notes to consolidated financial statements.
76 SAN DIEGO GAS & ELECTRIC COMPANY STATEMENTS OF CONSOLIDATED CHANGES IN CAPITAL STOCK AND RETAINED EARNINGS
In thousands of dollars For the years ended December 31, 1995, 1996, 1997 Preferred Stock ----------------------------- Not Subject Subject to Premium on to Mandatory Mandatory Common Capital Retained Redemption Redemption Stock Stock Earnings --------- --------- --------- --------- -------- Balance, January 1, 1995 $ 93,493 $ 25,000 $ 291,341 $ 564,508 $ 618,581 Earnings applicable to common shares 225,794 Long-term incentive plan activity-net 117 1,530 Preferred stock retired (880 shares) (18) 8 Common stock dividends declared (181,809) - ---------------------------- --------- --------- --------- --------- --------- Balance, December 31, 1995 93,475 25,000 291,458 566,046 662,566 Earnings applicable to common shares 216,183 Transfer to Enova Corporation 342 (150,437) Preferred stock retired (150,000 shares) (15,000) (155) Common stock dividends declared (181,867) - ---------------------------- --------- --------- --------- --------- --------- Balance, December 31, 1996 78,475 25,000 291,458 566,233 546,445 Earnings applicable to common shares 231,650 Special dividend to Enova Corporation ( 70,000) Common stock dividends declared (178,423) - ---------------------------- --------- --------- --------- --------- --------- Balance, December 31, 1997 $ 78,475 $ 25,000 $ 291,458 $ 566,233 $ 529,672 ============================ ========= ========= ========= ========= ========= See notes to consolidated financial statements. 77
INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of San Diego Gas & Electric Company: We have audited the accompanying consolidated balance sheets of San Diego Gas & Electric Company and subsidiary as of December 31, 1997 and 1996, and the related statements of consolidated income, consolidated changes in capital stock and retained earnings, and consolidated cash flows for each of the three years in the period ended December 31, 1997. 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 San Diego Gas & Electric Company and subsidiary of December 31, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997 in conformity with generally accepted accounting principles. /S/ DELOITTE & TOUCHE LLP DELOITTE & TOUCHE LLP San Diego, California February 23, 1998 78 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SAN DIEGO GAS & ELECTRIC COMPANY Except as modified below, the Notes to Consolidated Financial Statements of Enova Corporation are incorporated herein by reference insofar as they relate to San Diego Gas & Electric Company: Note 1 -- Business Combination Note 2 -- Significant Accounting Policies Note 4 -- Long-Term Debt Note 5 -- Facilities Under Joint Ownership Note 6 -- Employee Benefit Plans Note 8 -- Financial Instruments Note 9 -- Contingencies and Commitments Note 10 -- Industry Restructuring Note 3: Significant Affiliate Transactions In January 1996 Enova Corporation (Enova) became the parent of San Diego Gas & Electric (SDG&E) and its subsidiaries. At that time SDG&E's ownership interests in its subsidiaries were transferred to Enova at book value. SDG&E's financial statements for periods prior to 1996 reflect the results of these subsidiaries as discontinued operations in accordance with Accounting Principles Board Opinion No. 30 "Reporting the Effects of a Disposal of a Segment of Business." Discontinued operations are summarized in the table below: Year Ended December 31, 1995 - ------------------------------------------------------ (millions of dollars) Revenues $81 Loss from operations before income taxes (24) Loss on disposal before income taxes (12) Income tax benefits 32 - ------------------------------------------------------ In December 1997 SDG&E and Enova signed a promissory note agreement for an amount not to exceed $400 million to be loaned by SDG&E to Enova due within one year. Interest on the outstanding balance under the note is accrued monthly at the current three-month commercial paper rate. As of December 31, 1997 $130 million had been issued and was outstanding under the promissory note agreement. In March 1997 SDG&E paid to Enova a special dividend of $70 million to be used for the repurchase of three million shares of Enova common stock. Note 4: Long-Term Debt The information contained in Enova Corporation's Statements of Consolidated Long-Term Debt is incorporated herein by reference. 79 Note 7: Income Taxes SDG&E's income tax payments totaled $217 million in 1997, $245 million in 1996 and $200 million in 1995. The components of accumulated deferred income taxes at December 31 are as follows: in thousands of dollars 1997 1996 - ------------------------------------------------------------------ Deferred tax liabilities Differences in financial and tax bases of utility plant $567,804 $628,617 Loss on reacquired debt 30,535 26,399 Other 65,675 63,081 - ------------------------------------------------------------------ Total deferred tax liabilities 664,014 718,097 - ------------------------------------------------------------------ Deferred tax assets Unamortized investment tax credits 64,873 68,239 Regulatory balancing accounts 27,903 37,010 Unbilled revenue 22,365 21,923 Other 90,232 123,534 - ------------------------------------------------------------------ Total deferred tax assets 205,373 250,706 - ------------------------------------------------------------------ Net deferred income tax liability 458,641 467,391 Current portion (net asset) 13,249 19,728 - ------------------------------------------------------------------ Non-current portion (net liability) $471,890 $487,119 ================================================================== The components of income tax expense are as follows: in thousands of dollars 1997 1996 1995 - --------------------------------------------------------------- Current Federal $164,642 $169,309 $170,212 State 43,801 45,018 44,863 - -------------------------------------------------------------- Total current taxes 208,443 214,327 215,075 - -------------------------------------------------------------- Deferred Federal 12,922 (8,666) (23,647) State 1,600 (1,518) (13,464) - -------------------------------------------------------------- Total deferred taxes 14,522 (10,184) (37,111) - -------------------------------------------------------------- Deferred investment tax credits - net (3,809) (6,185) (4,935) - -------------------------------------------------------------- Total income tax expense $219,156 $197,958 $173,029 ============================================================== Federal and state income taxes are allocated between operating income and other income. 80 The reconciliation of the statutory federal income tax rate to effective income tax rate is as follows: 1997 1996 1995 - ------------------------------------------------------------- Statutory federal income tax rate 35.0% 35.0% 35.0% Depreciation 7.1 5.7 5.0 State income taxes - net of federal income tax benefit 5.7 6.1 4.8 Tax credits (1.3) (2.1) (1.8) Repair allowance (1.6) (1.1) (2.8) Other - net 3.0 3.4 3.9 - ------------------------------------------------------------- Effective income tax rate 47.9% 47.0% 44.1% ============================================================= Note 11: Capital Stock The information contained in SDG&E's Statements of Changes in Capital Stock and Retained Earnings is incorporated herein by reference. The information contained in Enova Corporation's Statements of Consolidated Capital Stock as it relates to preferred and preference stock is incorporated herein by reference. Note 12: Segments of Business The information contained in Enova Corporation's Statements of Consolidated Financial Information by Segments of Business is incorporated herein by reference. 81 Note 13: Quarterly Financial Data (Unaudited) SAN DIEGO GAS & ELECTRIC In thousands
Quarter ended March 31 June 30 September 30 December 31 1997 Operating revenues $ 494,636 $ 491,892 $ 566,297 $ 614,723 Operating expenses 431,706 413,670 480,303 524,781 --------- --------- --------- --------- Operating income 62,930 78,222 85,994 89,942 Other income and (deductions) 164 (444) (17) 7,659 Net interest charges 21,165 22,875 21,058 21,120 --------- --------- --------- --------- Net income (before preferred dividend requirements) 41,929 54,903 64,919 76,481 Preferred dividend requirements 1,646 1,645 1,646 1,645 --------- --------- --------- --------- Earnings applicable to common shares $ 40,283 $ 53,258 $ 63,273 $ 74,836 ========= ========= ========= ========= 1996 Operating revenues $ 451,942 $ 458,221 $ 493,485 $ 535,269 Operating expenses 367,772 388,379 411,657 462,347 --------- --------- --------- --------- Operating income 84,170 69,842 81,828 72,922 Other income and (deductions) 1,396 (884) 4,372 (190) Net interest charges 22,994 22,786 24,073 20,838 --------- --------- --------- --------- Net income (before preferred dividend requirements) 62,572 46,172 62,127 51,894 Preferred dividend requirements 1,646 1,645 1,646 1,645 --------- --------- --------- --------- Earnings applicable to common shares $ 60,926 $ 44,527 $ 60,481 $ 50,249 ========= ========= ========= ========= These amounts are unaudited, but in the opinion of SDG&E reflect all adjustments necessary for a fair presentation.
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