-----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, US+iO+fPaiaHu7evyoLNVo765FgqRz3mOkWx78QXvhVLklmHzULmMbFRBd93tPnk yNbWIY66SkxrqYMph3NfDA== 0000086521-99-000052.txt : 19991115 0000086521-99-000052.hdr.sgml : 19991115 ACCESSION NUMBER: 0000086521-99-000052 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19990930 FILED AS OF DATE: 19991112 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SAN DIEGO GAS & ELECTRIC CO CENTRAL INDEX KEY: 0000086521 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 951184800 STATE OF INCORPORATION: CA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-03779 FILM NUMBER: 99749049 BUSINESS ADDRESS: STREET 1: 8326 CENTURY PARK COURT CITY: SAN DIEGO STATE: CA ZIP: 92123 BUSINESS PHONE: 6196962000 MAIL ADDRESS: STREET 1: P O BOX 1831 CITY: SAN DIEGO STATE: CA ZIP: 92112 10-Q 1 QUARTERLY REPORT FORM 10-Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q [ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 1999 ------------------------------------- Commission file number 1-3779 --------------------------------------------- SAN DIEGO GAS & ELECTRIC COMPANY ---------------------------------------------------------- (Exact name of registrant as specified in its charter) California 95-1184800 - ------------------------------- ------------------- (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 8326 Century Park Court, San Diego, California 92123 - ------------------------------------------------------------------- (Address of principal executive offices) (Zip Code) (619) 696-2000 ---------------------------------------------------------- (Registrant's telephone number, including area code) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ----- ----- Common stock outstanding: Wholly owned by Enova Corporation PART I - FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS. SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED STATEMENTS OF INCOME (Unaudited) (Dollars in millions)
Three Months Ended September 30, ------------------ 1999 1998 ------------------ Operating Revenues: Electric $438 $481 Natural gas 82 82 ------------------ Total operating revenues 520 563 ------------------ Expenses: Purchased power - net 174 39 Electric fuel 7 70 Natural gas purchased for resale 29 30 Operation and maintenance 111 126 Depreciation and decommissioning 52 134 Other taxes and franchise payments 20 21 Income taxes 45 55 ------------------ Total 438 475 ------------------ Operating Income 82 88 ------------------ Other Income and (Deductions): Regulatory interest - net (1) (1) Allowance for equity funds used during construction 1 1 Income taxes on nonoperating income (11) (2) Other - net 26 4 ------------------ Total 15 2 ------------------ Income Before Interest Charges 97 90 ------------------ Interest Charges: Long-term debt 21 23 Other 15 3 ------------------ Total 36 26 ------------------ Net Income 61 64 Preferred Dividend Requirements 2 2 ------------------ Earnings Applicable to Common Shares $ 59 $ 62 ================== See notes to Consolidated Financial Statements.
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED STATEMENTS OF INCOME (Unaudited) (Dollars in millions)
Nine Months Ended September 30, ------------------ 1999 1998 ------------------ Operating Revenues: Electric $1,443 $1,454 Natural gas 277 284 ------------------ Total operating revenues 1,720 1,738 ------------------ Expenses: Purchased power - net 327 198 Electric fuel 64 137 Natural gas purchased for resale 119 120 Operation and maintenance 337 391 Depreciation and decommissioning 510 511 Other taxes and franchise payments 60 64 Income taxes 83 106 ------------------ Total 1,500 1,527 ------------------ Operating Income 220 211 ------------------ Other Income and (Deductions): Regulatory interest - net (3) (1) Allowance for equity funds used during construction 3 3 Income taxes on nonoperating income (22) (11) Other - net 49 21 ------------------ Total 27 12 ------------------ Income Before Interest Charges 247 223 ------------------ Interest Charges: Long-term debt 63 74 Other 20 8 ------------------ Total 83 82 ------------------ Net Income 164 141 Preferred Dividend Requirements 5 5 ------------------ Earnings Applicable to Common Shares $ 159 $ 136 ================== See notes to Consolidated Financial Statements.
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS (Dollars in millions)
Balance at ------------------------- September 30, December 31, 1999 1998 (Unaudited) ------- ------- ASSETS Utility plant - at original cost $4,431 $4,903 Less accumulated depreciation and decommissioning (2,274) (2,603) ------- ------- Utility plant - net 2,157 2,300 ------- ------- Nuclear decommissioning trust 509 494 ------- ------- Current assets: Cash and temporary investments 299 284 Accounts receivable 197 199 Due from affiliates 559 110 Inventories 56 77 Regulatory balancing accounts undercollected - net -- 9 Other 14 17 ------- ------- Total current assets 1,125 696 ------- ------- Deferred taxes recoverable in rates 93 194 Regulatory assets 239 511 Deferred charges and other assets 49 62 ------- ------- Total $4,172 $4,257 ======= ======= CAPITALIZATION AND LIABILITIES Capitalization: Common equity $1,283 $1,124 Preferred stock not subject to mandatory redemption 78 78 Preferred stock subject to mandatory redemption 25 25 Long-term debt 1,440 1,548 ------- ------- Total capitalization 2,826 2,775 ------- ------- Current liabilities: Long-term debt due within one year 66 72 Accounts payable 157 165 Taxes payable 69 -- Dividends payable 2 102 Interest accrued 12 9 Regulatory balancing accounts overcollected - net 149 -- Other 123 185 ------- ------- Total current liabilities 578 533 ------- ------- Customer advances for construction 47 41 Deferred income taxes - net 249 397 Deferred investment tax credits 54 89 Deferred credits and other liabilities 418 422 Commitments and contingent liabilities (Note 3) ------- ------- Total $4,172 $4,257 ======= ======= See notes to Consolidated Financial Statements.
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (Unaudited) (Dollars in millions)
Nine Months Ended September 30, ------------------ 1999 1998 ------ ------ Cash Flows from Operating Activities Net income $ 164 $ 141 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 510 511 Application of balancing accounts to stranded costs (66) (86) Portion of depreciation arising from sales of generating plants (295) -- Deferred income taxes (130) (125) Non-cash rate reduction bond revenue - net (50) (67) Other - net 57 7 Net change in other working capital components (232) (98) ------ ------ Net cash (used) provided by operating activities (42) 283 ------ ------ Cash Flows from Investing Activities: Utility construction expenditures (165) (160) Net proceeds from sales of generating plants 454 -- Contributions to decommissioning funds (13) (16) Other - net - 2 ------ ------ Net cash provided (used) by investing activities 276 (174) ------ ------ Cash Flows from Financing Activities: Dividends paid (105) (138) Issuance of long-term debt 16 -- Payment on long-term debt (130) (202) Increase in short-term debt -- -- ------ ------ Net cash used by financing activities (219) (340) ------ ------ Increase (decrease) in cash and temporary investments 15 (231) Cash and temporary investments, January 1 284 536 ------ ------ Cash and temporary investments, September 30 $ 299 $ 305 ====== ====== Supplemental Disclosure of Cash Flow Information: Interest payments (net of amounts capitalized) $ 85 $ 87 ====== ====== Income tax payments (net of refunds) $ 266 $ 113 ====== ====== Dividend to parent of intercompany receivable $ -- $ 100 ====== ====== See notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) 1. GENERAL This Quarterly Report on Form 10-Q is that of San Diego Gas & Electric Company (SDG&E or the Company), the sole subsidiary of Enova Corporation (Enova). Enova is a wholly owned subsidiary of Sempra Energy, a California-based Fortune 500 energy services company. The financial statements herein are the Consolidated Financial Statements of SDG&E and its subsidiary, SDG&E Funding LLC. The accompanying Consolidated Financial Statements have been prepared in accordance with the interim-period-reporting requirements of Form 10-Q. Results of operations for interim periods are not necessarily indicative of results for the entire year. In the opinion of management, the accompanying statements reflect all adjustments necessary for a fair presentation. These adjustments are only of a normal recurring nature. Certain changes in classification have been made to prior presentations to conform to the current financial statement presentation. The Company's significant accounting policies, as well as those of its subsidiaries, are described in the notes to Consolidated Financial Statements in the Company's 1998 Annual Report. The same accounting policies are followed for interim reporting purposes. This Quarterly Report should be read in conjunction with the Company's 1998 Annual Report and its Quarterly Reports on Form 10-Q for the three-month periods ended March 31, and June 30, 1999. SDG&E has been accounting for the economic effects of regulation on all utility operations in accordance with Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71), as described in the notes to Consolidated Financial Statements in the Company's 1998 Annual Report. In conformity with generally accepted accounting principles for regulated enterprises and the policies of the California Public Utilities Commission (CPUC), SDG&E has ceased the application of SFAS No. 71 to its generation business, in accordance with the conclusion of the Financial Accounting Standards Board that the application of SFAS No. 71 should be discontinued when legislation is issued that determines that a portion of an entity's business will no longer be subject to cost-based regulation. The discontinuance of SFAS No. 71 did not result in a write-off of SDG&E's generation assets, since the CPUC also approved the recovery of the stranded costs related to these assets by the distribution portion of its business. (See further discussion in Note 3.) 2. BUSINESS COMBINATIONS PE/Enova On June 26, 1998 (pursuant to an October 1996 agreement) Enova and Pacific Enterprises(PE), the parent company of the Southern California Gas Company (SoCalGas) completed a business combination in which the two companies became subsidiaries of a new company named Sempra Energy. As a result of the combination, (i) each outstanding share of common stock of Enova was converted into one share of common stock of Sempra Energy, (ii) each outstanding share of common stock of PE was converted into 1.5038 shares of common stock of Sempra Energy and (iii) the preferred stock and/or preference stocks of SDG&E, PE and SoCalGas remained outstanding. Additional information on the business combination is discussed in the Company's 1998 Annual Report. No expenses were incurred in connection with the above for the nine months and three months ended September 30, 1999. During the nine- month and three-month periods ended September 30, 1998, expenses of $34 million, after tax, and $5 million, after tax, respectively, were incurred. As a result of the business combination, Enova dividended its nonutility subsidiaries to Sempra Energy during 1998 and early 1999. SDG&E is now the sole direct subsidiary of Enova. KN Energy On February 22, 1999, Sempra Energy and KN Energy, Inc. (KN Energy) announced that their respective boards of directors had approved Sempra Energy's acquisition of KN Energy, subject to approval by the shareholders of both companies and by various federal and state regulatory agencies. On June 21, 1999, Sempra Energy and KN Energy announced that they had agreed to terminate the proposed acquisition. 3. MATERIAL CONTINGENCIES ELECTRIC INDUSTRY RESTRUCTURING -- CALIFORNIA PUBLIC UTILITIES COMMISSION In September 1996, the State of California enacted a law restructuring California's electric utility industry (AB 1890). The legislation adopted the December 1995 CPUC policy decision restructuring the industry to stimulate competition and reduce rates. Beginning on March 31, 1998, customers of California investor-owned utilities (IOUs) were given the opportunity to choose to continue to purchase their electricity from the local utility under regulated tariffs, to enter into contracts with other energy-service providers (direct access) or to buy their power from the independent Power Exchange (PX) that serves as a wholesale power pool allowing all energy producers to participate competitively. The PX obtains its power from qualifying facilities, from nuclear units and, lastly, from the lowest-bidding suppliers. The California IOUs are obligated to sell their power supply, including owned generation and purchased- power contracts, to the PX. The IOUs are also obligated to purchase from the PX the power that they distribute. SDG&E's obligation to bid into and purchase from the PX after the conclusion of the rate freeze continued during the interim post-rate-freeze period (discussed below). An Independent System Operator (ISO) schedules power transactions and access to the transmission system. The local utility continues to provide distribution service regardless of which energy source the customer chooses. Purchases from the PX/ISO are included in purchased-power expenses and PX/ISO power revenues have been netted therein on the Statements of Consolidated Income presented herein. Revenues from the PX/ISO reflect sales at market prices of energy from SDG&E's power plants and from long-term purchased-power contracts to the PX/ISO commencing April 1, 1998. As discussed in the notes to Consolidated Financial Statements contained in the Company's 1998 Annual Report, the IOUs have been given a reasonable opportunity to recover their stranded costs via a competition transition charge (CTC) to customers through December 31, 2001. In June 1999, SDG&E completed the recovery of its stranded costs, other than the above-market portion of qualifying facilities and other purchased-power contracts that were in effect at December 31, 1995, and San Onofre Nuclear Generating Station (SONGS) costs as described below. These costs will continue to be collected in rates. Recovery of the other stranded costs was effected by, among other things, the sale of SDG&E's fossil power plants and combustion turbines during the quarter ended June 30, 1999. The South Bay Power Plant sale to the San Diego Unified Port District for $110 million was completed on April 23, 1999. Duke South Bay, a subsidiary of Duke Energy Power Services, will manage the plant for the Port District. The sale of the Encina Power Plant and 17 combustion-turbine generators to Dynegy Inc. and NRG Energy Inc. for $356 million was completed on May 21, 1999. SDG&E will operate and maintain both the South Bay and Encina facilities for the new owners until April 2001 and May 2001, respectively. Stranded costs included the cost of SONGS as of December 31, 1995. SDG&E retains ownership of its 20-percent interest in SONGS. Subsequent SONGS costs are recoverable only from the sales of power produced therefrom, at rates previously fixed by the CPUC through December 31, 2002 and as determined by the market thereafter. If approved by the CPUC, SDG&E is planning to auction its interest in SONGS. A major issue being addressed is how to handle the decommissioning trust to ensure that adequate funding is available at the time the plant is decommissioned. AB 1890 also required a 10-percent reduction of residential and small commercial customers' rates beginning in January 1998, and provided for the issuance of rate-reduction bonds by an agency of the State of California to enable the IOUs to achieve this rate reduction. In December 1997, $658 million of rate-reduction bonds were issued on SDG&E's behalf 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 non-bypassable charge on their electric bills. In 1997, SDG&E formed a subsidiary, SDG&E Funding LLC, to facilitate the issuance of the bonds. In exchange for the bond proceeds, SDG&E sold to SDG&E Funding LLC all of its rights to revenue streams collected from such customers. Consequently, the transaction is structured to cause such revenue streams not to be the property of SDG&E nor to be available to satisfy any claims of SDG&E's creditors. The sizes of the rate-reduction bond issuances were set so as to make the IOUs neutral as to the 10-percent rate reduction, and were based on a four-year period to recover stranded costs. Because SDG&E recovered its stranded costs in only 18 months (due to the greater- than-anticipated plant-sale proceeds), it is deemed that its bond issuance should have been smaller. Accordingly, SDG&E will return to its customers over $400 million that it has collected or will collect from its customers. The timing of the return will differ from the timing of the collection, but the specific timing of the repayment and the interest rate thereon are the subject of a CPUC proceeding and are expected to be resolved in early 2000. This refund will not affect SDG&E's net income, except to the extent that the interest associated with the refund (12.63 percent if not reduced as a result of the CPUC proceeding) differs from the return earned by the Company on the funds. The bonds and their repayment schedule are not affected by this refund. AB 1890 also includes a rate freeze for all IOU customers. Beginning in 1998, SDG&E's system-average rates were fixed at 9.43 cents per kwh. The rate freeze would have stayed in place until January 1, 2002. However, in connection with completion of its stranded cost recovery (described above), SDG&E filed with the CPUC for a mechanism to deal with electric rates after the end of the rate freeze. SDG&E is requesting authority to reduce base rates (the non-commodity portion of rates) to all electric customers. If approved, base electric rates will decrease beyond the original 10-percent rate reduction described above. The portion of the electric rate representing the commodity cost is simply passed through to customers and will fluctuate with the price of electricity from the PX. Except for the interim protection mechanism described below, customers will no longer be protected from commodity price spikes. In April 1999, SDG&E filed an all-party settlement (including energy service providers, the CPUC's Office of Ratepayer Advocates (ORA), and the Utility Consumers Action Network (UCAN)) detailing proposed implementation plans for lifting the rate freeze. Included in the settlement is an interim customer-protection mechanism for residential and small commercial customers that capped rates between July 1999 and September 1999, regardless of how high the PX price had moved during that period. The resulting undercollection (which amounted to less than $1 million) is being recovered through a balancing account mechanism. A CPUC decision adopting the all-party settlement was issued in May 1999 and became effective July 1, 1999. The interim rate-freeze period runs until the CPUC issues its decision on the pending legal and policy issues of ending the rate freeze. This decision is expected during the first quarter of 2000. Thus far, electric-industry deregulation has been confined to generation. Transmission and distribution have remained subject to traditional cost-of-service regulation. However, the CPUC is exploring the possibility of opening up electric distribution to competition. During 1999, the CPUC will be conducting a rulemaking, one objective of which may be to develop a coordinated proposal for the state legislature regarding how various distribution competition issues should be addressed. The Company will actively participate in this effort. ELECTRIC INDUSTRY RESTRUCTURING -- FEDERAL ENERGY REGULATORY COMMISSION In October 1997, the Federal Energy Regulatory Commission (FERC) approved key elements of the California IOUs' restructuring proposal. This included the transfer by the IOUs of the operational control of their transmission facilities to the ISO, which is under FERC jurisdiction. The FERC also approved the establishment of the California PX to operate as an independent wholesale power pool. NATURAL GAS INDUSTRY RESTRUCTURING The natural gas industry experienced an initial phase of restructuring during the 1980s by deregulating natural gas sales to noncore customers. On January 21, 1998, the CPUC released a staff report initiating a project to assess the current market and regulatory framework for California's natural gas industry. The general goals of the plan are to consider reforms to the current regulatory framework emphasizing market-oriented policies benefiting California's natural gas consumers. In August 1998, California enacted a law prohibiting the CPUC from enacting any natural gas industry restructuring decision for core (residential and small commercial) customers prior to January 1, 2000; the CPUC continues to study the issue. During the implementation moratorium, the CPUC has been holding hearings throughout the state and intends to give the legislature a draft ruling before adopting a final market-structure policy. SDG&E and SoCalGas have been actively participating in this effort and have argued in support of competition intended to maximize benefits to customers rather than to protect competitors. In October 1999, the State of California enacted a law (AB 1421) which requires that gas utilities provide "bundled basic gas service" (including transmission, storage, distribution, purchasing, revenue- cycle services and after-meter services) to all core customers, unless the customer chooses to purchase gas from a non-utility provider. The law prohibits the CPUC from unbundling distribution- related gas services (metering, billing, etc.) and after-meter services (leak investigation, inspecting customer piping and appliances, pilot relighting, carbon monoxide investigation, etc.) for most customers. The objective is to preserve both customer safety and customer choice. 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 $9.5 billion of coverage is provided by the Nuclear Regulatory Commission Secondary Financial Protection Program and provides for loss sharing among utilities owning nuclear reactors if a costly accident occurs. SDG&E could be assessed up to $36 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 $2.75 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 12 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 $4.5 million. CANADIAN NATURAL GAS SDG&E had been involved in negotiations and litigation with four Canadian suppliers concerning contract terms and prices. SDG&E has settled with all of the suppliers. One of the four is delivering natural gas under the terms of the settlement agreement through 2003; the other three have ceased deliveries and the contracts were terminated. Although these contracts were intended to supply SDG&E to a level approximating the related committed long-term pipeline capacity, SDG&E intends to continue using the pipeline capacity in other ways, including the transport of replacement natural gas and the release of a portion of this capacity to third parties. 4. COMPREHENSIVE INCOME AND OTHER SHAREHOLDERS' EQUITY In conformity with generally accepted accounting principles, the Company has adopted Statement of Financial Accounting Standards No. 130, "Reporting Comprehensive Income." Comprehensive income for the three-month and nine-month periods ended September 30, 1999 and 1998 was equal to net income. 5. SEGMENT INFORMATION The Company has three separately managed reportable segments: electric transmission and distribution, electric generation, and natural gas service. The accounting policies of the segments are the same as those described in the notes to Consolidated Financial Statements in the Company's 1998 Annual Report. Segment performance is evaluated by management based on reported operating income. Intersegment transactions are generally recorded the same as sales or transactions with third parties. Interest expense and income tax expense are not allocated to the reportable segments. Interest revenue is included in other income on the Statements of Consolidated Income herein. It is not allocated to the reportable segments. There were no significant changes in segment assets for the nine months ended September 30, 1999, except as described in Note 3 concerning the sale of SDG&E's power plants. - --------------------------------------------------------------------- Three months ended Nine months ended September 30, September 30, ---------------------------------------- (Dollars in millions) 1999 1998 1999 1998 - --------------------------------------------------------------------- Revenues: Electric trans. and dist. $ 406 $ 276 $ 887 $ 793 Electric generation 32 205 556 661 Natural gas 82 82 277 284 --------------------------------------- Total $ 520 $ 563 $1,720 $1,738 --------------------------------------- Segment Income: Electric trans. and dist. $ 112 $ 117 $ 261 $ 234 Electric generation 4 9 (11) 33 Natural gas 11 17 53 50 --------------------------------------- Total segment income 127 143 303 317 Interest expense (36) (26) (83) (82) Income tax expense (56) (57) (105) (117) Nonoperating income 26 4 49 23 --------------------------------------- Net income $ 61 $ 64 $ 164 $ 141 --------------------------------------- ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion should be read in conjunction with the financial statements contained in this Form 10-Q and Management's Discussion and Analysis of Financial Condition and Results of Operations contained in the Company's 1998 Annual Report. INFORMATION REGARDING FORWARD-LOOKING STATEMENTS This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. The words "estimates," "believes," "expects," "anticipates," "plans" and "intends," variations of such words, and similar expressions are intended to identify forward-looking statements that involve risks and uncertainties which could cause actual results to differ materially from those anticipated. These statements are necessarily based upon various assumptions involving judgments with respect to the future including, among others, local, regional, national and international economic, competitive, political and regulatory conditions and developments; technological developments; capital market conditions; inflation rates; interest rates; energy markets; weather conditions; business, regulatory or legal decisions; the pace of deregulation of retail natural gas and electricity industries; the timing and success of business development efforts; and other uncertainties -- all of which are difficult to predict and many of which are beyond the control of the Company. Accordingly, while the Company believes that the assumptions are reasonable, there can be no assurance that they will approximate actual experience, or that the expectations will be realized. Readers are urged to review and consider carefully the risks, uncertainties and other factors which affect the Company's business described in this quarterly report and other reports filed by the Company from time to time with the Securities and Exchange Commission. Readers are cautioned not to put undue reliance on any forward-looking statements. For those statements, the Company claims the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. BUSINESS COMBINATIONS See Note 2 of the notes to Consolidated Financial Statements regarding the PE/Enova business combination and the agreement to terminate the KN Energy acquisition. CAPITAL RESOURCES AND LIQUIDITY The Company's utility operations continue to be a major source of liquidity. In addition, working capital requirements are met through the issuance of short-term and long-term debt. These capital resources are expected to remain available. Major changes in cash flows not described elsewhere are described below. Cash and cash equivalents at September 30, 1999 are available for investment in utility plant, the retirement of debt, and other corporate purposes. CASH FLOWS FROM OPERATING ACTIVITIES The decrease in cash flows from operations is primarily due to transactions related to the recovery of stranded electric costs as described elsewhere herein, partially offset by relative overcollections of regulatory balancing accounts. CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures for property, plant and equipment are estimated to be $240 million for the full year 1999 and will be financed primarily by internally generated funds. These expenditures will largely represent investment in rate base. Construction, investment and financing programs are continuously reviewed and revised in response to changes in competition, customer growth, inflation, customer rates, the cost of capital, and environmental and regulatory requirements. Included in cash flows from investing activities are the proceeds from SDG&E's plant sales. See additional discussion in Note 3 of the notes to Consolidated Financial Statements. CASH FLOWS FROM FINANCING ACTIVITIES The decrease in net cash used in financing activities was primarily due to a decrease in dividends paid to Sempra Energy during the nine- month period ended September 30, 1999, compared to the same period in 1998, and greater long-term debt repayments in 1998. RESULTS OF OPERATIONS The tables below summarize the components of electric and natural gas volumes and revenues by customer class for the nine months ended September 30, 1999 and 1998. Electric Distribution (Dollars in millions, volumes in millions of Kwhrs)
1999 1998 ------------------------------------------ Volumes Revenue Volumes Revenue ------------------------------------------ Residential 4,753 $ 491 4,766 $ 484 Commercial 4,733 446 5,195 500 Industrial 1,523 116 2,496 190 Direct access 2,304 88 438 30 Street and highway lighting 57 5 64 6 Off-system sales 290 7 661 14 ------------------------------------------ 13,660 1,153 13,620 1,224 Balancing and other 290 230 ------------------------------------------ Total 13,660 $1,443 13,620 $1,454 ------------------------------------------
Gas Sales, Transportation & Exchange (Dollars in millions, volumes in billion cubic feet)
Gas Sales Transportation & Exchange Total -------------------------------------------------------------------- Throughput Revenue Throughput Revenue Throughput Revenue -------------------------------------------------------------------- 1999: Residential 30 $ 210 -- $ -- 30 $ 210 Commercial and industrial 19 82 13 11 32 93 Utility electric generation 18 7* 15 4 33 11 -------------------------------------------------------------- 67 $ 299 28 $ 15 95 314 Balancing accounts and other (37) -------- Total $ 277 - ------------------------------------------------------------------------------------------ 1998: Residential 26 $ 198 -- $ -- 26 $ 198 Commercial and industrial 15 80 15 13 30 93 Utility electric generation 45 7* -- -- 45 7 -------------------------------------------------------------- 86 $ 285 15 $ 13 101 $ 298 Balancing accounts and other (14) --------- Total $ 284 - ------------------------------------------------------------------------------------------ * margin only
Electric revenues decreased 9 percent and 1 percent for the three-month and nine-month periods ended September 30, 1999 compared to the corresponding periods in 1998, respectively. The decrease for the three-month period is primarily due to the reduction in base electric rates from the elimination of the rate freeze effective July 1, 1999. The decrease for the nine- month period is primarily due to the January 1998 application to stranded cost recovery of the $130 million balance in the Interim Transition Cost Balancing Account (ITCBA), which had been transferred from the then-discontinued Energy Cost Adjustment Clause(ECAC) and Electric Revenue Adjustment Mechanism (ERAM) balancing accounts at December 31, 1997 and the decrease in revenues discussed above. Natural gas revenues for the three-month period ended September 30, 1999 were equal to the same period in 1998. Natural gas revenues decreased 2 percent for the nine-month period ended September 30, 1999 compared to the same period in 1998. Residential sales for the nine-month period increased primarily due to greater volumes. The increase in balancing accounts and other is primarily due to greater overcollections in 1999 versus the same period for 1998. As discussed in Note 3, PX/ISO power revenues have been netted against purchased-power expenses, including purchases from the PX/ISO. The PX/ISO began operations in April 1998. Cost of natural gas distributed decreased 3 percent and 1 percent for the three-month and nine-month periods ended September 30, 1999 compared to the corresponding periods in 1998. The decreases were primarily due to decreases in volumes, partially offset by higher prices of natural gas. Under the current regulatory framework, changes in revenue resulting from changes in core-market volumes and the cost of natural gas do not affect net income. Depreciation and decommissioning expense decreased 61 percent for the three-month period ended September 30, 1999, compared to the same period in 1998. Depreciation and decommissioning was consistent for the nine-month period ended September 30, 1999 compared to 1998. The decrease for the three-month period is due to the accelerated recovery of generation assets due to the sale of SDG&E's fossil power plants and combustion turbines. As a result of the sale, there was no depreciation expense recorded in the third quarter of 1999 related to stranded generation facilities. Nine-month results include the accelerated recovery of generation assets discussed above, offset by the January 1998 application to stranded cost recovery of the ITCBA. Operating income decreased 7 percent for the three-month period ended September 30, 1999 compared to the same period in 1998. The decrease is primarily due to lower electric sales during the quarter. Operating income increased 4 percent for the nine-month period ended September 30, 1999, compared to the same period in 1998, primarily due to lower business combination costs, as previously discussed. Income tax expense decreased for the nine-month period ended September 30, 1999, compared to the corresponding period in 1998. The decrease is primarily due to the contribution to a local government agency of the land related to one of the sold generating plants, partially offset by higher income before taxes. The land contribution also resulted in a significant decrease in the Company's effective income tax rate. YEAR 2000 ISSUES Most companies are affected by the inability of many automated systems and applications to process the year 2000 and beyond. The Year 2000 issues are the result of computer programs and other automated processes using two digits to identify a year, rather than four digits. Any of the Company's computer programs that include date-sensitive software may recognize a date using "00" as representing the year 1900, instead of the year 2000, or "01" as 1901, etc., which could lead to system malfunctions. The Year 2000 issue impacts both Information Technology ("IT") systems and also non-IT systems, including systems incorporating embedded processors. To address this problem, in 1996, both Pacific Enterprises and Enova Corporation established company-wide Year 2000 programs. These programs were consolidated into Sempra Energy's overall Year 2000 readiness effort. Sempra Energy established a central Year 2000 Program Office, which reports to Sempra Energy's Chief Information Technology Officer and reports periodically to the audit committee of the Board of Directors. The Company's State of Readiness Sempra Energy has identified all significant IT and non-IT systems (including embedded systems) that might not be Year 2000 ready and categorized them in the following areas: IT applications, computer hardware and software infrastructure, telecommunications, embedded systems, and third parties. The Company evaluated its exposure in all of these areas. These systems and applications are being tracked and measured through four key phases: inventory, assessment, remediation/testing, and Year 2000 readiness. The Company has prioritized so that, when possible, critical systems were assessed and modified/replaced first. Critical systems are those applications and systems, including embedded processor technology, which, if not appropriately remediated, may have a significant impact on energy delivery, revenue collection, or the safety of personnel, customers or facilities. The Company's Year 2000 testing effort includes functional testing of Year 2000 dates and validating that changes have not altered existing functionality. The Company uses an independent, internal review process to verify that the appropriate testing has occurred. The Company's Year 2000 project is currently on schedule, with critical energy delivery systems for both SoCalGas and SDG&E Year 2000 Ready since June 30, 1999. The Company defines "Year 2000 Ready" as suitable for continued use into the year 2000 with no significant operational problems. Sempra Energy's current schedule for Year 2000 testing and readiness for non-critical systems is to be completed by the end of 1999. In certain cases, this schedule is dependent upon the efforts of third parties, such as suppliers (including energy producers) and customers. Accordingly, delays by third parties may cause the Company's schedule to change. In addition, a continued readiness management process has been implemented to monitor and review the progress of Year 2000 readiness of the Company's systems. The Costs to Address the Company's Year 2000 Issues Sempra Energy's budget for the Year 2000 program is $48 million, of which $44 million has been spent. As the Company continues to assess its systems and as the remediation and testing efforts progress, cost estimates may change. The Company's Year 2000 readiness effort is being funded entirely by operating cash flows. The Risks of the Company's Year 2000 Issues Based upon its current assessment and testing of the Year 2000 issue, the Company believes the reasonably likely worst case Year 2000 scenarios to have the following impacts upon Sempra Energy and its operations. With respect to the Company's ability to provide energy to its domestic utility customers, the Company believes that the scenario is for small, localized interruptions of utility service which are restored in a time frame that is within normal service levels. With respect to services that are essential to Sempra Energy's operations, such as customer service, business operations, supplies and emergency response capabilities, the scenario is for minor disruptions of essential services with rapid recovery and all essential information and processes ultimately recovered. To assist in preparing for and mitigating these possible scenarios, Sempra Energy is a member of several industry-wide efforts established to deal with Year 2000 problems affecting embedded systems and equipment used by the nation's natural gas and electric power companies. Successful contingency drills were held with eight west-coast natural gas pipeline companies on August 24, 1999 and with the North American Electric Reliability Council (NERC) on September 9, 1999. Under these efforts, participating utilities are working together to assess specific vendors' system problems and to test plans. These assessments are being shared by the industry as a whole to facilitate Year 2000 problem solving. A portion of this risk is due to the various Year 2000 Ready schedules of major suppliers and customers. The Company continues to contact its major suppliers and customers to survey their Year 2000 remediation programs. While risks related to the lack of Year 2000 readiness by third parties could materially and adversely affect the Company's business, results of operations and financial condition, the Company expects its Year 2000 readiness efforts to reduce significantly the Company's level of uncertainty about the impact of third party Year 2000 issues on both its IT systems and its non-IT systems. The Company's Contingency Plans The Company's contingency plans for Year-2000-related interruptions have been completed and were submitted to the CPUC on July 1, 1999. These plans will continue to be revised and improved during the remainder of 1999. The contingency plans include emergency backup and recovery procedures, replacing electronic applications with manual processes, and identification of alternate suppliers, along with increasing inventory levels. In addition, the following key contingency actions will be taken. ? Only critical system changes will be implemented during December 1999 and January 2000. ? An hour-by-hour plan will be developed to cover key contingency actions. ? On-site staffing will be in place at key operational and administrative locations. ? Designated standby staff will be on-call with thirty-minute availability. ? Emergency Operations Centers will be activated on December 31, 1999. ? Walk-through drills are being held during the fourth quarter of 1999. Due to the speculative and uncertain nature of contingency planning, there can be no assurances that such plans actually will be sufficient to reduce the risk of material impacts on the Company's operations due to Year 2000 issues. FACTORS INFLUENCING FUTURE PERFORMANCE Because of the ratemaking and regulatory process, electric and natural gas industry restructuring, and the changing energy marketplace, there are several factors that will influence the Company's future financial performance. These factors are discussed in this section. Industry Restructuring See discussion of industry restructuring in Note 3 of the notes to Consolidated Financial Statements. Electric-Generation Assets and Electric Rates Note 3 of the notes to Consolidated Financial Statements describes regulatory and legislative actions that affect SDG&E's electric rates, and the related sale of its fossil plants and recovery of the cost of all SDG&E generation-related assets. Performance-Based Regulation (PBR) To promote efficient operations and improved productivity and to move away from reasonableness reviews and disallowances, the CPUC has been directing utilities to use PBR. PBR has replaced the general rate case and certain other regulatory proceedings for both SoCalGas and SDG&E. Under PBR, regulators require future income potential to be tied to achieving or exceeding specific performance and productivity goals, as well as cost reductions, rather than relying solely on expanding utility rate base in a market where a utility already has a highly developed infrastructure. SDG&E continues to participate in PBR for its electric distribution and natural gas businesses. In December 1998, the CPUC approved SDG&E's Cost of Service proceeding, resulting in an authorized revenue increase of $12 million (an electric distribution increase of $18 million and a natural gas decrease of $6 million). New rates became effective on January 1, 1999. On May 13, 1999 the CPUC adopted a decision on the PBR design issues of SDG&E's distribution PBR application, incorporating the rate-indexing mechanism proposed by SDG&E, but also approving tighter bands for sharing enhanced earnings than previously in effect for SDG&E. The decision also adopted an all-party settlement on various performance incentives, allowing SDG&E the opportunity to accrue up to $14.5 million annually in performance rewards or penalties. Certain intervenors requested a rehearing of the rate-indexing mechanism. On November 4, 1999 the CPUC denied this request. The new PBR mechanism is effective retroactive to January 1, 1999 and remains in effect until December 31, 2002. SDG&E must file a new cost of service study and a request for a new PBR mechanism in December 2001. Cost of Capital Under PBR, annual Cost of Capital proceedings were replaced by an automatic adjustment mechanism if changes in certain indices exceed established tolerances. For SDG&E, electric-industry restructuring is changing the method of calculating the utility's annual cost of capital. SDG&E's May 1998 application to the CPUC for unbundled rates established new, separate rates of return for SDG&E's electric distribution and natural gas businesses. The application proposed a 12.00 percent rate of return on common equity (ROE), which would produce an overall ROR of 9.33 percent. A CPUC decision in June 1999 granted SDG&E an ROE of 10.6 percent (overall ROR of 8.75 percent). This resulted in annual revenue requirement reductions of $14.6 million and $4.8 million for electric distribution and gas sales, respectively, effective July 1, 1999. SDG&E filed an Application for Rehearing of this decision in July 1999, requesting that the ROE be increased to 10.8 percent after correcting computational errors in the original decision. The Application for Rehearing is pending. Annual Earnings Assessment Proceeding An application was filed in May 1999 to recover shareholder rewards for the Demand Side Management (DSM) programs and incentives earned for the energy-efficiency and low-income programs totaling $12 million ($10 million for electric and $2 million for gas). The revenue requirement increase is proposed to become effective on January 1, 2000. The DSM rewards and low-income program incentives will be collected and recorded in earnings over ten years. The energy-efficiency program incentives are recovered in one year. Rewards and incentives for these programs are subject to CPUC approval. A final decision is expected during the first quarter of 2000. The CPUC has extended interim utility administration of energy- efficiency and low-income programs through December 31, 2001. Biennial Cost Allocation Proceeding (BCAP) The BCAP determines how a utility's costs are allocated among various customer classes (residential, commercial, industrial, etc.). SDG&E filed the 1999 BCAP application in October 1998, with hearings held during the first half of 1999. At the conclusion of hearings, a joint BCAP recommendation was reached proposing, among other things, an overall natural gas rate reduction of $11 million for SDG&E. A CPUC decision is expected during the first quarter of 2000. ITEM 3. MARKET RISK There have been no significant changes in the risk issues affecting the Company subsequent to those discussed in the Annual Report on Form 10-K for 1998 except as to the sale of the power plants and related impact on stranded costs. "ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" herein includes discussion of various risk issues. PART II - OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS Except for the matters referred to in the Company's 1998 Annual Report or referred to elsewhere in this Quarterly Report on Form 10-Q for the three months ended September 30, 1999, neither the Company nor any of its affiliates is a party to, nor is its property the subject of, any material pending legal proceedings other than routine litigation incidental to its businesses. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits Exhibit 12 - Computation of ratios 12.1 Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends. Exhibit 27 - Financial Data Schedules 27.1 Financial Data Schedule for the nine months ended September 30, 1999. (b) Reports on Form 8-K None. SIGNATURE Pursuant to the requirement of the Securities Exchange Act of 1934, SDG&E has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. SAN DIEGO GAS & ELECTRIC COMPANY (Registrant) Date: November 12, 1999 By: /s/ E.A. Guiles ----------------------------- E.A. Guiles President EX-12 2 EXHIBIT 12.1 SAN DIEGO GAS & ELECTRIC COMPANY COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS (Dollars in millions)
For the Nine Months Ended 1994 1995 1996 1997 1998 9/30/99 -------- -------- -------- -------- --------- --------- Fixed Charges and Preferred Stock Dividends: Interest: Long-Term Debt $ 82 $ 82 $ 76 $ 70 $ 55 $37 Short-Term Debt & Other 9 18 13 14 13 22 Rate Reduction Bonds -- -- -- -- 41 26 Amortization of Debt Discount and Expense, Less Premium 5 5 5 5 8 6 Interest Portion of Annual Rentals 9 10 8 9 8 5 -------- -------- -------- ------- --------- ---------- Total Fixed Charges 105 115 102 98 125 96 -------- -------- -------- -------- --------- ---------- Preferred Dividend Requirements 8 8 7 7 7 5 Ratio of Income Before Tax to Net Income 1.83501 1.78991 1.88864 1.91993 1.73993 1.63909 -------- -------- -------- -------- --------- ---------- Preferred Dividends for Purpose of Ratio 14 14 13 13 11 8 -------- -------- -------- -------- --------- ---------- Total Fixed Charges and Preferred Stock Dividends For Purpose of Ratio $119 $129 $115 $111 $136 $104 ======== ======== ======== ======== ========= ========= Earnings: Net Income (before preferred dividend requirements) $206 $219 $223 $238 $191 $163 Add: Fixed charges (from above) 105 115 102 98 125 96 Less: Fixed charges capitalized 1 2 1 2 1 1 Taxes on Income 172 173 198 219 141 105 -------- -------- -------- -------- --------- ---------- Total Earnings for Purpose of Ratio $482 $505 $522 $553 $456 $363 ======== ======== ======== ======== ========= ========== Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends 4.06 3.92 4.54 5.00 3.36 3.49 ======== ======== ======== ======== ========= ==========
EX-27 3
UT THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONDENSED STATEMENT OF CONSOLIDATED INCOME, BALANCE SHEET AND CASH FLOWS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 0000086521 SAN DIEGO GAS & ELECTRIC COMPANY 1,000,000 9-MOS DEC-31-1999 SEP-30-1999 PER-BOOK 2,157 509 1,125 378 3 4,172 291 566 426 1,283 25 78 1,427 0 0 0 54 0 13 12 1,280 4,172 1,720 83 1,417 1,500 220 27 247 83 164 5 159 0 63 (42) 0 0
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