UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2004
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Commission file number 1-3779
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SAN DIEGO GAS & ELECTRIC COMPANY
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(Exact name of registrant as specified in its charter)
California 95-1184800
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
8330 Century Park Court, San Diego, California 92123
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(Address of principal executive offices)
(Zip Code)
(619) 696-2000
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(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period
that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days.
Yes X No
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Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Exchange Act).
Yes No X
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Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date.
Common stock outstanding: Wholly owned by Enova Corporation
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INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This Quarterly Report contains statements that are not historical fact
and constitute forward-looking statements within the meaning of the
Private Securities Litigation Reform Act of 1995. The words
"estimates," "believes," "expects," "anticipates," "plans," "intends,"
"may," "could," "would" and "should" or similar expressions, or
discussions of strategy or of plans are intended to identify forward-
looking statements. Forward-looking statements are not guarantees of
performance. They involve risks, uncertainties and assumptions. Future
results may differ materially from those expressed in these forward-
looking statements.
Forward-looking statements are necessarily based upon various
assumptions involving judgments with respect to the future and other
risks, including, among others, local, regional and national economic,
competitive, political, legislative and regulatory conditions and
developments; actions by the California Public Utilities Commission,
the California Legislature, the California Department of Water
Resources, and the Federal Energy Regulatory Commission; capital market
conditions, inflation rates, interest rates and exchange rates; energy
and trading markets, including the timing and extent of changes in
commodity prices; weather conditions and conservation efforts; war and
terrorist attacks; business, regulatory and legal decisions; the status
of deregulation of retail natural gas and electricity delivery; the
timing and success of business development efforts; and other
uncertainties, all of which are difficult to predict and many of which
are beyond the control of the company . Readers are cautioned not to
rely unduly on any forward-looking statements and are urged to review
and consider carefully the risks, uncertainties and other factors which
affect the company's business described in this report and other
reports filed by the company from time to time with the Securities and
Exchange Commission.
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PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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8 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1. GENERAL This Quarterly Report on Form 10-Q is that of San Diego Gas & Electric Company (SDG&E or the company). SDG&E's common stock is wholly owned by Enova Corporation, which is a wholly owned subsidiary of Sempra Energy, a California-based Fortune 500 holding company. The financial statements herein are the Consolidated Financial Statements of SDG&E and its sole subsidiary, SDG&E Funding LLC. Sempra Energy also indirectly owns all of the common stock of Southern California Gas Company (SoCalGas). SDG&E and SoCalGas are collectively referred to herein as "the California Utilities." 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. Specifically, certain December 31, 2003 income tax liabilities have been reclassified from Deferred Income Taxes to current Income Taxes Payable and to Deferred Credits and Other Liabilities to conform to the current presentation of these items. Information in this Quarterly Report is unaudited and should be read in conjunction with the Annual Report on Form 10-K for the year ended December 31, 2003 (Annual Report) and the Quarterly Report on Form 10-Q for the first quarter of 2004. The company's significant accounting policies are described in Note 1 of the notes to Consolidated Financial Statements in the Annual Report. The same accounting policies are followed for interim reporting purposes. SDG&E accounts for the economic effects of regulation on utility operations in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." NOTE 2. NEW ACCOUNTING STANDARDS Stock-Based Compensation: On March 31, 2004, the Financial Accounting Standards Board (FASB) issued a proposed Exposure Draft (ED) to amend SFAS 123, "Accounting for Stock-Based Compensation." The proposed statement would eliminate the choice of accounting for share-based compensation transactions using Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees," whereby no expense is recorded for most stock options and instead generally require that such transactions be accounted for using a fair-value- based method, whereby expense is recorded for stock options. It would also prohibit application by restating prior periods and would require
9 that expense be recognized only for those options that actually vest. If passed, the proposed ED would be effective for the company in 2005. SFAS 132 (revised 2003), "Employers' Disclosures about Pensions and Other Postretirement Benefits": This statement revises employers' disclosures about pension plans and other postretirement benefit plans, effective in 2004. It requires disclosures beyond those in the original SFAS 132 related to the assets, obligations, cash flows and net periodic benefit cost of defined benefit pension plans and other defined postretirement plans. In addition, it requires interim-period disclosures regarding the amount of net periodic benefit cost recognized and the total amount of the employers' contributions paid and expected to be paid during the current fiscal year. It does not change the measurement or recognition of those plans. The following table provides the components of benefit costs for the three months and six months ended June 30:
10 Note 6 of the notes to Consolidated Financial Statements in the Annual Report discusses the company's expected contribution to its pension plan and other postretirement benefit plans in 2004. $2 million and $1 million of contributions have been made to its other postretirement benefit plans for the six months and the quarter, respectively, ended June 30, 2004. There was no contribution made to its pension plan for the six months ended June 30, 2004. SFAS 143, "Accounting for Asset Retirement Obligations": Beginning in 2003, SFAS 143 requires entities to record liabilities for future costs expected to be incurred when assets are retired from service, if the retirement process is legally required. It also requires the reclassification of estimated removal costs, which have historically been recorded in accumulated depreciation, to a regulatory liability. At June 30, 2004 and December 31, 2003, the estimated removal costs recorded as a regulatory liability were $868 million and $846 million, respectively. The change in the asset retirement obligations for the six months ended June 30, 2004 is as follows (dollars in millions): Balance as of January 1, 2004 $ 326 Accretion expense (interest) 11 Payments (6) ------ Balance as of June 30, 2004 $ 331* ====== * The current portion of the obligation is included in Other Current Liabilities on the Consolidated Balance Sheets. SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities": Effective July 1, 2003, SFAS 149 amended and clarified accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS 133. Under SFAS 149 natural gas forward contracts that are subject to unplanned netting generally do not qualify for the normal purchases and normal sales exception, whereby derivatives are not required to be marked to market when the contract is usually settled by the physical delivery of natural gas. ("Netting" refers to contract settlement by paying or receiving the monetary difference between the contract price and the market price at the date on which physical delivery would have occurred.) In addition, effective January 1, 2004, power contracts that are subject to unplanned netting and that do not meet the normal purchases and normal sales exception under SFAS 149 will continue to be marked to market. Implementation of SFAS 149 did not have a material impact on reported net income. Additional information on derivative instruments is provided in Note 4. SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity": The company adopted SFAS 150 beginning July 1, 2003 by reclassifying $24 million of mandatorily redeemable preferred stock to Deferred Credits and Other Liabilities and to Other Current Liabilities on the Consolidated Balance Sheets.
11 FASB Interpretation No. (FIN) 46, "Consolidation of Variable Interest Entities an interpretation of Accounting Research Bulletin (ARB) No. 51": FIN 46 requires the primary beneficiary of a variable interest entity's activities to consolidate the entity. Contracts under which SDG&E acquires power from generation facilities otherwise unrelated to SDG&E could result in a requirement for SDG&E to consolidate the entity that owns the facility. As permitted by the interpretation, SDG&E is continuing the process of determining whether it has any such situations and, if so, gathering the information that would be needed to perform the consolidation. The effects of this, if any, are not expected to significantly affect the financial position of SDG&E and there would be no effect on results of operations or liquidity. FASB Staff Position (FSP) 106-1 and 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003": Issued January 12, 2004, FSP 106-1 allowed the company to make a one-time election during the first quarter of 2004 to defer accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) until authoritative guidance on the accounting for federal subsidies was issued. In May 2004, FSP 106-1 was superseded by FSP 106-2, which provides guidance on the accounting for the effects of the Act by employers whose prescription drug benefits are actuarially equivalent to the drug benefit under Medicare Part D. In such a case, the employer includes the federal subsidy in measuring the accumulated postretirement benefit obligation (APBO). The resulting reduction in the APBO is recognized as an actuarial gain and the employer's share of future costs under the plan is reflected in current period service cost. FSP 106-2 also provides disclosure guidance about the effects of the subsidy for an employer who offers postretirement prescription drug coverage, but is unable to determine whether the plan's provisions are actuarially equivalent to the Medicare Part D benefit. For the company, FSP 106-2 is effective for the quarter ending September 30, 2004. The company has not yet determined whether the benefits provided by the plans are actuarially equivalent, and, at June 30, 2004, the APBO and net periodic postretirement benefit costs do not reflect any amount associated with the subsidy.
12 NOTE 3. COMPREHENSIVE INCOME The following is a reconciliation of net income to comprehensive income. Three months Six months ended ended June 30, June 30, ----------------------------------- (Dollars in millions) 2004 2003 2004 2003 - ----------------------------------------------------------------- Net income $ 31 $ 42 $ 82 $ 89 Minimum pension liability adjustments -- -- -- (6)* ----------------------------------- Comprehensive income $ 31 $ 42 $ 82 $ 83 - ----------------------------------------------------------------- * This amount does not equal the change in the reported balance of accumulated other comprehensive income due to rounding. NOTE 4. FINANCIAL INSTRUMENTS As described in Note 8 of the notes to Consolidated Financial Statements in the Annual Report, the company follows the guidance of SFAS 133 as amended by SFAS 138 and 149 (collectively SFAS 133) to account for its derivative instruments and hedging activities. Derivative instruments and related hedged items are recognized as either assets or liabilities on the balance sheet, measured at fair value. SFAS 133 provides for hedge accounting treatment when certain criteria are met. For derivative instruments designated as fair value hedges, the gain or loss is recognized in earnings in the period of change together with the offsetting gain or loss on the hedged item attributable to the risk being hedged. For derivative instruments designated as cash flow hedges, the effective portion of the derivative gain or loss is included in Other Comprehensive Income, but not reflected in the Statements of Consolidated Income until the corresponding hedged transaction is settled. The ineffective portion is reported in earnings immediately. The company utilizes natural gas and energy derivatives to manage commodity price risk associated with servicing its load requirements. These contracts allow the company to predict with greater certainty the effective prices to be received by the company and the prices to be charged to its customers. The company also periodically enters into interest-rate swap agreements to moderate exposure to interest-rate changes and to lower the overall cost of borrowing. The use of derivative financial instruments is subject to certain limitations imposed by company policy and regulatory requirements. Contracts that meet the definition of normal purchase and sales generally are long-term contracts that are settled by physical delivery and, therefore, are eligible for the normal purchases and sales
13 exception of SFAS 133. The contracts are accounted for under accrual accounting and recorded in Revenues or Cost of Sales on the Statements of Consolidated Income when physical delivery occurs. Due to the adoption of SFAS 149, the company has determined that its natural gas contracts entered into after June 30, 2003 generally do not qualify for the normal purchases and sales exception. However, the effect of this is minimal. Fixed-priced Contracts and Other Derivatives Fixed-priced Contracts and Other Derivatives on the Consolidated Balance Sheets primarily reflect SDG&E's unrealized gains and losses related to long-term delivery contracts for purchased power and natural gas transportation. The California Utilities have established offsetting regulatory assets and liabilities to the extent that these gains and losses are included in the calculation of future rates. If gains and losses are not recoverable or payable through future rates, the company applies hedge accounting if certain criteria are met. If a contract no longer meets the requirements of SFAS 133, the unrealized gains and losses and the related regulatory asset or liability will be amortized over the remaining contract life. The changes in Fixed-price Contracts and Other Derivatives on the Consolidated Balance Sheets for the six months ended June 30, 2004 were primarily due to physical deliveries under long-term purchased-power and natural gas transportation contracts. The transactions associated with fixed-price contracts and other derivatives had no material impact to the Statements of Consolidated Income for the six months ended June 30, 2004 and 2003. NOTE 5. REGULATORY MATTERS ELECTRIC INDUSTRY REGULATION The restructuring of California's electric utility industry has significantly affected the company's electric utility operations. In addition, the power crisis of 2000-2001 caused the California Public Utilities Commission (CPUC) to adjust its plan for restructuring the electricity industry. The background of these issues is described in the Annual Report. The California Department of Water Resources' (DWR) operating agreement with SDG&E, approved by the CPUC, provides that SDG&E is acting as a limited agent on behalf of the DWR in undertaking energy sales and natural gas procurement functions under the DWR contracts allocated to SDG&E's customers. Legal and financial responsibility associated with these activities continues to reside with the DWR. Therefore, the revenues and costs associated with the contracts are not included in the Statements of Consolidated Income. On May 27, 2004, the CPUC denied Southern California Edison's (Edison) Petition to Modify the CPUC decision that allocates charges related to the DWR bonds issued in connection with the power crisis to customers of California's three investor-owned utilities (IOUs) based on energy usage. Edison did not appeal the decision on its application for
14 rehearing to the courts and, therefore, the decision has become final and unappealable. In October 2003, the CPUC initiated a proceeding to consider a permanent methodology for allocating the DWR's revenue requirement beginning in 2004 through the remaining life of the DWR contracts. An interim allocation based on the current 2003 methodology was utilized beginning January 1, 2004, and will remain in effect until a decision is reached on a permanent methodology. In April 2004, Edison, Pacific Gas & Electric (PG&E) and a northern California consumer advocacy group proposed a limited joint settlement to allocate the DWR revenue requirement among the IOUs. This settlement proposes to shift more than $1 billion in additional costs to SDG&E customers and would have a significant impact on commodity rates over the remaining eight-year life of the DWR contracts. On July 19, 2004, the CPUC issued a proposed decision and an alternate decision recommending permanent allocations of DWR contract costs to the IOUs. Neither proposed decision would adopt the settlement; instead, both would permanently allocate 12.5 percent of the fixed costs of the contracts to SDG&E for the remaining life of the contracts (2004-2013). This would shift a total of $976 million in additional costs to SDG&E customers over an eight-year period. Although these proposed decisions would have no effect on SDG&E's net income, they would adversely affect its customer rates and SDG&E's cash flows. In the near term the effect on SDG&E's cash flows would be minor, but would become significant in the later years unless rate ceilings were increased to provide more-contemporaneous recovery. The CPUC may consider these draft decisions at its August 19, 2004 meeting. SDG&E's long-term resource plan identifies the forecasted needs for capacity resources within its service territory to support transmission grid reliability. An updated 10-year resource plan was filed on July 9, 2004, in a CPUC proceeding to consider utility resource planning, including energy efficiency, contracted power, demand response, qualifying facilities, renewable generation and distributed generation. SDG&E's updated long-term resource plan incorporates the resources approved as a result of the May 2003 Request for Proposals (RFP) discussed below, and recognizes updated goals to reach 20% renewable resources by 2010. The updated plan recommends a 500-kV transmission line addition in 2010. In order to satisfy SDG&E's recognized near-term need for grid reliability and capacity, in May 2003 SDG&E issued an RFP for the years 2005-2007 for at least 69 megawatts (MWs) of electric capacity in 2005 increasing to 291 MWs in 2007. As a result of its RFP, in October 2003, SDG&E filed a motion requesting CPUC authorization to enter into five new electric resource contracts (including two under which SDG&E would take ownership, on a turnkey basis, of new generating assets, including a 550-MW plant (Palomar) being developed by Sempra Energy Resources, an affiliate, for completion in 2006), as more fully described in the Annual Report. A June 9, 2004 CPUC decision approved all five proposed contracts, along with an additional demand response contract. The decision authorized SDG&E to recover the costs of both contracted resources and turnkey resources, but did not adopt SDG&E's specific cost recovery, ratemaking and revenue requirement proposals for the proposed turnkey resources.
15 On July 15, 2004, three parties filed requests for rehearing of the decision. SDG&E filed its response on July 30, 2004, opposing the request. The CPUC is expected to rule on the requests in the next few months. In August 2004, SDG&E will file its revenue requirement and ratemaking proposals for the 45-MW combustion turbine which SDG&E will acquire as a turnkey project (Ramco facility) and will file for the Palomar facility later in 2004. The decision did not approve SDG&E's proposals for a return on equity (ROE) for SDG&E's new generation investments higher than SDG&E's ROE on distribution assets, an equity offset for the debt equivalency of purchase power contracts, and an equity buildup for construction. These matters may be re-introduced for consideration in future CPUC proceedings. NATURAL GAS INDUSTRY RESTRUCTURING (GIR) As discussed in the Annual Report, in December 2001 the CPUC issued a decision related to GIR, with implementation anticipated during 2002. On April 1, 2004, after many delays and changes, the CPUC issued a decision that adopts tariffs to implement the 2001 decision. However, by that same decision, the CPUC stayed implementation of the GIR tariffs until it issues a decision in Phase I of the Natural Gas Market Order Instituting Ratemaking (OIR) discussed below. At that time, the CPUC will reconcile the GIR market structure with whatever structure results from the Phase I decision of the Natural Gas Market OIR. NATURAL GAS MARKET OIR The CPUC's Natural Gas Market OIR was approved on January 22, 2004, and will be addressed in two concurrent phases. The schedule calls for a Phase I decision by September 2004 and a Phase II decision by the end of 2004. Further discussion of Phase I and Phase II is included in the Annual Report. The focus of the Gas OIR is the period from 2006 to 2016. Since GIR (discussed above) would end in August 2006 and there is overlap between GIR and the OIR issues, a number of parties (including SoCalGas) have requested the CPUC not to implement GIR. The California Utilities have made comprehensive filings in the OIR outlining a proposed market structure that will help create access to new natural gas supply sources (such as LNG) for California. In the Phase I filing, SoCalGas and SDG&E proposed a framework to provide firm tradable access rights for intrastate natural gas transportation; provide SoCalGas with continued balancing account protection for intrastate transmission and distribution revenues, thereby eliminating throughput risk; and integrate the transmission systems of SoCalGas and SDG&E so as to have common rates and rules. The California Utilities have proposed that the investments necessary to access new sources of supply be included in ratebase and that the total amount of the investments would not exceed $200 million. In addition, the California Utilities have filed a recommended methodology and framework to be used by the CPUC for granting pre- approval of new interstate transportation agreements. A draft Phase I decision was issued on July 20, 2004. The draft decision recommends that the utilities' pre-approval procedures be approved with some modifications and that several issues, including supply access rate treatment, firm access rights and transmission system integration, be
16 addressed by separate applications. A final CPUC decision in Phase I is expected in September 2004. COST OF SERVICE FILINGS In 2002, the California Utilities filed Cost Of Service applications with the CPUC, seeking rate increases reflecting forecasts of 2004 capital and operating costs, as further discussed in the Annual Report. SDG&E is requesting revenue increases of $64 million. On December 19, 2003, settlements were filed with the CPUC for SDG&E that, if approved, would resolve most of the Cost of Service issues. A CPUC decision is expected later this year. The SDG&E settlement would reduce its electric rate revenues by $19.6 million from 2003 rate revenues and increase its natural gas rate revenues by $1.8 million from 2003 rate revenues. A CPUC order has provided that the new rates will be retroactive to January 1, 2004. Beginning in the first quarter of 2004, SDG&E generally is recognizing revenue consistent with the proposed settlement, except for amounts related to pension costs, which are pending the CPUC decision and CPUC acceptance of a related compliance filing. Resolution of the pension matter consistent with the proposed settlement would result in the recording of additional income at that time. To the extent, if any, that the final CPUC decision varies from the method used to recognize revenue prior to that decision, an accounting adjustment will be recorded at that time. To date, the impacts of accounting consistent with the settlement have not had a material effect on the financial statements. The remaining issues are included in Phase II of the Cost of Service proceeding. In addition to recommending changes in the performance- based regulation (PBR) formulas, the CPUC's Office of Ratepayers Advocates (ORA) also proposed the possibility of performance penalties, without the possibility of performance awards. Hearings took place in June 2004. On July 21, 2004, all of the active parties in Phase II who dealt with post test year ratemaking and performance incentives filed for adoption of an all-party settlement agreement for most of the Phase II issues, including annual inflation adjustments and revenue sharing. The agreement does not cover performance incentives. The settlement requires the California Utilities to file their next rate cases based on a 2008 test year. For the interim years of 2005-2007, the Consumer Price Index will be used to adjust the escalatable authorized base rate revenues within identified floors and ceilings. It is anticipated that the CPUC will address this matter in its decision related to Phase II of this proceeding expected by year-end 2004. SDG&E had filed for continuation of existing PBR mechanisms for service quality and safety that would otherwise expire at the end of 2003. In January 2004, the CPUC issued a decision that extended 2003 service and safety targets through 2004, but did not determine the applicability of rewards or penalties. Edison has received the CPUC's decision on its Cost of Service application. This decision sets rates for San Onofre Nuclear Generating Station (SONGS), 20 percent of which is owned by SDG&E. As discussed in the Annual Report, SDG&E's SONGS ratebase restarted at $0 on January 1, 2004 and, therefore, SDG&E's earnings from SONGS will generally be limited to a return on new capital additions. Edison has applied for permission to replace SONGS' steam generator, which would increase the
17 total cost of SONGS by an estimated $800 million ($160 million for SDG&E). SDG&E has the option of not participating in the project and has informed Edison of its intention to exercise this option. This would reduce SDG&E's ownership percentage in SONGS. The reduction in SDG&E's ownership percentage is subject to arbitration, which is expected to occur prior to year-end. If the proposed reduction of SDG&E's ownership percentage resulting from the arbitration is unacceptable, SDG&E could elect to participate in the replacement project. PERFORMANCE-BASED REGULATION As further described in the Annual Report, under PBR, the CPUC requires future income potential to be tied to achieving or exceeding specific performance and productivity goals, rather than relying solely on expanding utility plant to increase earnings. PBR and demand-side management (DSM) rewards are not included in the company's earnings before CPUC approval is received. The cumulative amount of rewards subject to refund based on the outcome of the Border Price Investigation described below is $8.2 million. At June 30, 2004, the following performance incentives were pending CPUC approval and, therefore, were not included in the company's earnings (dollars in millions): Program ----------------------------------- DSM/Energy Efficiency* $ 37.7 2003 Distribution PBR 8.2 Natural gas PBR Year 10 1.5 ----------------------------------- Total $ 47.4 ----------------------------------- * Dollar amounts shown do not include interest, franchise fees or uncollectible amounts. SOUTHERN CALIFORNIA FIRES Several major wildfires that began on October 26, 2003 severely damaged SDG&E's infrastructure, causing a significant number of customers to be without utility services. On October 27, 2003, then governor Gray Davis declared a State of Emergency for the State of California. The declaration authorized the establishment of catastrophic event memorandum accounts (CEMA) to record all incremental costs (costs not already included in rates) associated with the repair of facilities and the restoration of service. Incremental electric distribution and natural gas related costs are recovered through the CEMA. Electric transmission related costs are recovered through the annual FERC true- up proceeding. Total costs incurred related to the wildfires were $66 million, of which $58 million is under CPUC jurisdiction while $8 million is electric transmission subject to FERC jurisdiction. Of that $58 million, $38 million is incremental and recoverable through the CEMA.
18 On June 28, 2004, SDG&E filed its CEMA application to recover incremental operating and maintenance costs and capital costs associated with the fire. In that application, SDG&E is requesting a revenue requirement of $20 million effective January 1, 2005, which includes $16 million in expenses recorded through May 31, 2004 and estimated to be incurred through the end of 2004, plus an additional $4 million for its capital-related costs, which will continue in future years until the $22 million of capital costs and the authorized return thereon are recovered. The company expects no significant effect on earnings from the fires. COST OF CAPITAL Effective January 1, 2003, SDG&E's authorized ROE is 10.9 percent and its return on ratebase is 8.77 percent, for SDG&E's electric distribution and natural gas businesses. The electric-transmission cost of capital is determined under a separate FERC proceeding. As discussed in the Annual Report, these rates will continue to be effective until 2008 unless market interest-rate changes are large enough to trigger an automatic adjustment. The Moody's Aa utility bond yield as published by Mergent Bond Record must average less than 6.24 percent or greater than 8.24 percent during the April-September timeframe of any given year to trigger an automatic adjustment. The Moody's Aa utility bond yield averaged 6.35 percent during the April- July 2004 time period and was 6.08 percent on July 30, 2004. BIENNIAL COST ALLOCATION PROCEEDING The BCAP determines the allocation of authorized costs between customer classes for natural gas transportation service provided by the company and adjusts rates to reflect variances in customer demand as compared to the forecasts previously used in establishing transportation rates. SDG&E filed with the CPUC its 2005 BCAP application in September 2003, requesting updated transportation rates effective January 1, 2005. In November 2003, an Assigned Commissioner Ruling delayed the BCAP applications until a decision is issued in the GIR implementation proceeding. As a result of the April 1, 2004 decision on GIR implementation as described in "Natural Gas Industry Restructuring," above, on May 27, 2004 the Administrative Law Judge (ALJ) in the 2005 BCAP issued a decision dismissing the BCAP applications. The California Utilities would be required to file new BCAP applications after the stay of the GIR implementation decision is lifted. BORDER PRICE INVESTIGATION In November 2002, the CPUC instituted an investigation into the Southern California natural gas market and the price of natural gas delivered to the California-Arizona border between March 2000 and May 2001. If the investigation determines that the conduct of any party to the investigation, including the California Utilities, contributed to the natural gas price spikes, the CPUC may modify the party's natural gas procurement incentive mechanism, reduce the amount of any shareholder award for the period involved, and/or order the party to issue a refund to ratepayers. Hearings began on June 29, 2004 and continued through July 15, 2004. A draft decision is expected in October 2004. The CPUC may hold a second round of hearings to consider
19 whether Sempra Energy or any of its non-utility subsidiaries contributed to the price spikes. Final decisions are expected by late 2004. The company believes that the CPUC will find that the California Utilities acted in the best interests of its core customers and that none of the Sempra Energy companies was responsible for the price spikes. CPUC INVESTIGATION OF ENERGY-UTILITY HOLDING COMPANIES The CPUC has initiated an investigation into the relationship between California's IOUs and their parent holding companies. The CPUC broadly determined that it could, in appropriate circumstances, require the holding company to provide cash to a utility subsidiary to cover its operating expenses and working capital to the extent they are not adequately funded through retail rates. This would be in addition to the requirement of holding companies to cover their utility subsidiaries' capital requirements, as the IOUs previously acknowledged in connection with the holding companies' formations. In January 2002, the CPUC ruled on jurisdictional issues, deciding that the CPUC had jurisdiction to create the holding company system and, therefore, retains jurisdiction to enforce conditions to which the holding companies had agreed. In an opinion issued May 21, 2004, the California Court of Appeal upheld the CPUC's assertion of limited enforcement jurisdiction, but concluded that the CPUC's interpretation of the "first priority" condition (that the holding companies could be required to infuse cash into the utilities as necessary to meet the utilities' obligation to serve) was not ripe for review at this time. On June 30, 2004, the company requested review of the Court of Appeal's decision on the jurisdictional issue by the California Supreme Court. To date, the Supreme Court, which has discretionary authority to grant or deny review, has not acted upon this request. RECOVERY OF CERTAIN DISALLOWED TRANSMISSION COSTS In August 2002, the FERC issued Opinion No. 458, which effectively disallowed SDG&E's recovery of the differentials between certain payments to SDG&E by its co-owners of the Southwest Powerlink (SWPL) under the Participation Agreements and charges assessed to SDG&E under the California Independent System Operator (ISO) FERC tariff for transmission line losses and grid management charges related to energy schedules of Arizona Public Service Co. (APS) and the Imperial Irrigation District (IID), its SWPL co-owners. As a result, SDG&E is incurring unreimbursed costs of $4 million to $8 million per year. After SDG&E petitioned the United States Court of Appeals for review of this order, the court remanded the case back to the FERC for further consideration. FERC issued its Order on Remand on May 6, 2004. Although it corrected several misstatements in its earlier opinions, FERC essentially reaffirmed its original conclusions. After the Court of Appeals rejected FERC's argument that SDG&E and other petitioners were required to file for rehearing of the Order on Remand, the parties jointly asked the court to set a schedule for completion of briefing. The Court of Appeals has not yet ruled on this joint motion. On July 6, 2001, in a separate matter related to ISO charges giving rise to most of the cost differentials described above, SDG&E filed an
20 arbitration claim against the ISO, claiming the ISO should not charge SDG&E for the transmission losses attributable to energy schedules on the APS and the IID portions of the SWPL. The independent arbitrator found in SDG&E's favor, awarding to SDG&E all amounts claimed, which totaled $22 million, including interest, as of the time of the award. The ISO appealed this result to the FERC and a FERC decision is expected in 2004. SDG&E has also commenced a private arbitration to reform the Participation Agreements to remove prospectively SDG&E's obligation to provide the services that result in unreimbursed ISO tariff charges. On April 6, 2004, the ISO filed its reply brief to SDG&E's brief and the matter was submitted to the FERC. In addition, APS, IID and Edison filed briefs in support of SDG&E's arbitration award. FERC ACTIONS Refund Proceedings The FERC is investigating prices charged to buyers in the California Power Exchange (PX) and ISO markets by various electric suppliers. The FERC is seeking to determine the extent to which individual sellers have yet to be paid for power supplied during the period of October 2, 2000 through June 20, 2001 and to estimate the amounts by which individual buyers and sellers paid and were paid in excess of competitive market prices. Based on these estimates, the FERC could find that individual net buyers, such as SDG&E, are entitled to refunds and individual net sellers are required to provide refunds. To the extent any such refunds are actually realized by SDG&E, they would reduce SDG&E's rate-ceiling balancing account. In December 2002, a FERC ALJ issued preliminary findings indicating that the California PX and ISO owe power suppliers $1.2 billion (the $3.0 billion that the California PX and ISO still owe energy companies less $1.8 billion that the energy companies charged California customers in excess of the preliminarily determined competitive market clearing prices). On March 26, 2003, the FERC adopted its ALJ's findings, but changed the calculation of the refund by basing it on a different estimate of natural gas prices. The March 26 order estimates that the replacement formula for estimating natural gas prices will increase the refund obligations from $1.8 billion to more than $3 billion. The FERC recently released additional instructions and ordered the ISO and PX to recalculate the precise number through their settlement models. California is seeking $8.9 billion in refunds from its electricity suppliers and has appealed the FERC's preliminary findings and requested rehearing of the March 26 order. In March 2004, the Attorney General of California requested the Ninth Circuit Court of Appeals to compel the FERC to comply with the Court's earlier orders, contending that the FERC had violated an August 2002 court order that should have resulted in larger refunds to California and that the FERC had failed to properly weigh evidence of market manipulation by power companies when deciding the refunds due California ratepayers.
21 Manipulation Investigation The FERC is also investigating whether there was manipulation of short- term energy markets in the West that would constitute violations of applicable tariffs and warrant disgorgement of associated profits. In this proceeding, the FERC's authority is not confined to the October 2, 2000 through June 20, 2001 period relevant to the refund proceeding. In May 2002, the FERC ordered all energy companies engaged in electric energy trading activities to state whether they had engaged in various specific trading activities in violation of the PX and ISO tariffs (generally described as manipulating or "gaming" the California energy markets). On June 25, 2003, the FERC issued several orders requiring various entities to show cause why they should not be found to have violated California ISO and PX tariffs. FERC directed 43 entities, including SDG&E, to show cause why they should not disgorge profits from certain transactions between January 1, 2000 and June 20, 2001 that are asserted to have constituted gaming and/or anomalous market behavior under the California ISO and/or PX tariffs. SDG&E and the FERC resolved the matter through a settlement which documents the ISO's finding that SDG&E did not engage in market activities in violation of the ISO or PX tariffs, and in which SDG&E agreed to pay $27,792 into a FERC- established fund to conclude the matter. SDG&E has also worked with the California PX to address questions raised in connection with certain ancillary service capacity transactions that the PX carried out on behalf of SDG&E. SDG&E believes that its data show that all of these transactions were legitimate and that SDG&E always had capacity available to support its sales in the ISO's ancillary service capacity markets. The PX has petitioned the FERC, asking that the PX be dismissed from the show-cause proceeding. The FERC has not yet acted on the PX's request. On June 25, 2003, the FERC determined that it was appropriate to initiate an investigation into possible physical and economic withholding in the California ISO and PX markets. On August 1, 2003, the FERC staff issued an initial report that determined there was no need to further investigate particular entities for physical withholding of generation. For the purpose of investigating economic withholding, the FERC used an initial screen of all bids exceeding $250 per megawatt between May 1, 2000 and October 2, 2000. SDG&E received data requests from the FERC staff and provided responses. In May 2004, based on the results of its investigation, the FERC's Office of Market Oversight and Investigation informed SDG&E that its bidding procedures are no longer being investigated by the FERC. Settlement of Claims Associated with FERC's Investigations During June and July, 2004, three settlements of claims associated with FERC's investigations were announced. One settlement, in which SDG&E will receive a net payment of $11.5 million, resolves all but a few claims against The Williams Companies and Williams Power Company for the period May 1, 2000 through June 20, 2001 and was approved by the FERC on July 2, 2004. Another settlement, in which SDG&E will receive a net payment of $13.8 million, resolves all claims against Dynegy, NRG Energy and West Coast Power LLC for the period January 1, 2000 through
22 June 20, 2001 and has been submitted to the FERC for approval. A third settlement, in which SDG&E will receive a net payment of $14.7 million, resolves specified claims against Duke Energy for the period January 1, 2000 though June 20, 2001 and will be submitted to the FERC for approval in the next few months. In all cases, the majority of the funds would be received within 20 days of receiving FERC approval with the remainder contingent on certain actions by the FERC, the ISO and the PX. Receipt of the remaining amount by SDG&E would take place at the conclusion of the FERC refund proceeding, now expected to be in early 2006. These funds would be received for the benefit of SDG&E's bundled customers and will reimburse SDG&E for the costs of litigating this matter. NOTE 6. CONTINGENCIES NUCLEAR INSURANCE SDG&E and the other owners of SONGS have insurance to respond to nuclear liability claims related to SONGS. Detail to the coverage is provided in the Annual Report. As of June 30, 2004, the secondary financial protection provided by the Price-Anderson Act is $10.5 billion if the liability loss exceeds the insurance limit of $300 million. In addition, the maximum SDG&E could be assessed is $8.8 million should there be a retrospective premium call under the risk sharing arrangements of the nuclear property, decontamination and debris removal insurance policy. Both the nuclear liability and property insurance programs subscribed to by members of the nuclear power generating industry include industry aggregate limits for non-certified acts, as defined by the Terrorism Risk Insurance Act, of terrorism-related SONGS losses, including replacement power costs. An industry aggregate limit of $300 million exists for liability claims, regardless of the number of non-certified acts affecting SONGS or any other nuclear energy liability policy or the number of policies in place. An industry aggregate limit of $3.24 billion exists for property claims, including replacement power costs, for non-certified acts of terrorism affecting SONGS or any other nuclear energy facility property policy within twelve months from the date of the first act. These limits are the maximum amount to be paid to members who sustain losses or damages from these non-certified terrorist acts. For certified acts of terrorism, the individual policy limits stated above apply. SPENT NUCLEAR FUEL SONGS owners have responsibility for the interim storage of spent nuclear fuel generated at San Onofre, until it is accepted by the DOE for final disposal. Spent nuclear fuel is stored in the San Onofre Units 1, 2 and 3 Spent Fuel Pools (SFP) and the San Onofre Independent Spent Fuel Storage Installation (ISFSI). Movement of Unit 1 spent fuel from the Unit 3 SFP to the ISFSI was completed in late 2003. Movement of Unit 1 spent fuel from the Unit 1 SFP to the ISFSI is scheduled to be completed by late 2004 and from the Unit 2 SFP to the ISFSI by late 2005. With these moves, there will be sufficient space in the Unit 2 and 3 SFPs to meet plant requirements through mid-2007 and mid-2008, respectively.
23 LITIGATION Except for the matters referred to below, neither the company nor its subsidiary are party to, nor is their property the subject of, any material pending legal proceedings other than routine litigation incidental to their businesses. Management believes that none of these matters will have further material adverse effect on the company's financial condition or results of operations. Antitrust Litigation Class-action and individual lawsuits filed in 2000 and currently consolidated in San Diego Superior Court seek damages, alleging that Sempra Energy, SoCalGas and SDG&E, along with El Paso Energy Corp. (El Paso) and several of its affiliates, unlawfully sought to control natural gas and electricity markets. In March 2003, plaintiffs in these cases and the applicable El Paso entities (whose cases involved unrelated claims not applicable to Sempra Energy, SoCalGas or SDG&E) announced that they had reached a $1.7 billion settlement, of which $125 million is allocated to customers of the California Utilities. The Court approved that settlement in December 2003. The proceeding against Sempra Energy and the California Utilities has not been settled and continues to be litigated. On July 22, 2004, the court heard oral argument on a motion for summary judgment brought by Sempra Energy and the California Utilities and is expected to issue a decision in August 2004. Trial is set for September 7, 2004. Natural Gas Cases: Lawsuits have been filed by the Attorneys General of Arizona and Nevada, alleging that El Paso and certain Sempra Energy subsidiaries unlawfully sought to control the natural gas market in their respective states. In October 2003, the Nevada state court denied defendants' motion to dismiss the complaint. On April 12, 2004, the Sempra Energy defendants filed a motion for reconsideration. In April 2003, Sierra Pacific Resources and its utility subsidiary Nevada Power filed a lawsuit in U.S. District Court in Las Vegas against major natural gas suppliers, including Sempra Energy, the California Utilities and other company subsidiaries, seeking damages resulting from an alleged conspiracy to drive up or control natural gas prices, eliminate competition and increase market volatility, breach of contract and wire fraud. On January 27, 2004, the U.S. District Court dismissed the Sierra Pacific Resources case against all of the defendants, determining that this is a matter for the FERC to resolve. The court granted plaintiffs' request to amend their complaint, which they did. On July 15, 2004, Sempra Energy filed another motion to dismiss, which is scheduled to be heard on September 23, 2004. Electricity Cases: Various lawsuits, which seek class-action certification, allege that Sempra Energy and certain subsidiaries, including SDG&E, unlawfully manipulated the electric-energy market. In January 2003, the federal court granted a motion to dismiss a similar lawsuit on the grounds that the claims contained in the complaint were subject to the Filed Rate Doctrine and were preempted by the Federal Power Act. That ruling was appealed to the Ninth Circuit Court of Appeals and oral argument was heard on June 14, 2004. In May and June 2004, two new cases were filed in federal court against Sempra Energy and certain subsidiaries, including SDG&E.
24 SDG&E and two other subsidiaries of Sempra Energy, along with all other sellers in the western power market, have been named defendants in a complaint filed at the FERC by the California Attorney General's office seeking refunds for electricity purchases based on alleged violations of FERC tariffs. The FERC has dismissed the complaint. The California Attorney General filed an appeal in the Ninth Circuit of Appeals and oral argument was heard in October 2003. No decision has yet been rendered. Price Reporting Practices On July 8, 2004, the City and County of San Francisco and the County of Santa Clara and on July 18, 2004 the County of San Diego brought actions, alleging that energy prices were unlawfully manipulated by defendants' reporting artificially inflated natural gas prices to trade publications and by entering into wash trades, in San Diego Superior Court against Sempra Energy, SET, SoCalGas and SDG&E. Other The Utility Consumers' Action Network (UCAN), a consumer-advocacy group which had requested a CPUC rehearing of a CPUC decision concerning the allocation of certain power contract gains between SDG&E customers and the company, appealed the CPUC's rehearing denial to the California Court of Appeal. On July 12, 2004, the Court of Appeal affirmed the CPUC's decision. UCAN has 40 days to appeal. Customers of the California Utilities will receive benefits under a settlement with El Paso resolving a number of civil and administrative proceedings surrounding the high natural gas and electric prices experienced in several Western states during the March 2000 through May 2001 period. A total amount of settlement funds of $33.3 million to SDG&E's core gas customers and $66.6 million to SDG&E's electric customers will be received over a period of 20 years. An initial lump sum payment of $30 million was received in June 2004, which will be followed by 19 annual payments.
25 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion should be read in conjunction with the financial statements contained in this Form 10-Q and "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained in the Annual Report. RESULTS OF OPERATIONS Electric revenues increased to $810 million for the six months ended June 30, 2004 from $799 million for the same period in 2003, and the cost of electric fuel and purchased power decreased to $282 million in 2004 from $300 million in 2003. The increase in revenues was the result of higher volumes and higher operating costs that are recovered in rates via balancing accounts, offset by more power being provided by the DWR as discussed in Note 5 of the notes to Consolidated Financial Statements, while the decrease in the cost of electric fuel and purchased power was mainly due to more power being provided by the DWR. Additionally, electric revenues increased to $425 million for the quarter ended June 30, 2004 from $402 million for the same period in 2003, and the cost of electric fuel and purchased power increased to $155 million in 2004 from $137 million in 2003. These changes were mainly due to higher volumes. Under the current regulatory framework, changes in commodity costs normally do not affect net income. Natural gas revenues increased to $306 million for the six months ended June 30, 2004 from $283 million for the corresponding period in 2003, and the cost of natural gas increased to $172 million in 2004 from $152 million in 2003. These increases were primarily attributable to natural gas cost increases, which are passed on to customers. Additionally, natural gas revenues were relatively unchanged at $111 million for the quarter ended June 30, 2004 compared to $118 million for the corresponding period in 2003, and the cost of natural gas was relatively unchanged at $63 million in 2004 compared to $67 million in 2003. Under the current regulatory framework, the cost of natural gas purchased for customers and the variations in that cost are passed through to the customers on a substantially concurrent basis. However, SDG&E's natural gas procurement PBR mechanism provides an incentive mechanism by measuring SDG&E's procurement of natural gas against a benchmark price comprised of monthly natural gas indices, resulting in shareholder rewards for costs achieved below the benchmark and shareholder penalties when costs exceed the benchmark. In 2002, the California Utilities filed Cost Of Service applications with the CPUC, seeking rate increases reflecting forecasts of 2004 capital and operating costs, as further discussed in the Annual Report. In accordance with generally accepted accounting principles, SDG&E is generally recognizing 2004 revenue consistent with the proposed settlement, except for amounts related to pension costs which are pending the CPUC decision and CPUC acceptance of a related compliance
26 filing. Resolution of the pension matter consistent with the proposed settlement would result in the recording of additional income at that time. To the extent, if any, that the final CPUC decision varies from the method used to recognize revenue prior to that decision, an accounting adjustment will be recorded at that time. To date, the impacts of accounting consistent with the settlement have not had a material effect on the financial statements. The tables below summarize the electric and natural gas volumes and revenues by customer class for the six months ended June 30, 2004 and 2003.
27
28 expenditures and working capital requirements in comparison to cash from operations, available credit lines and other sources available to meet liquidity requirements. CASH FLOWS FROM OPERATING ACTIVITIES Net cash provided by operating activities totaled $159 million and $217 million for the six months ended June 30, 2004 and 2003, respectively. The decrease was mainly due to a lower increase in overcollected regulatory balancing accounts in 2004 and a decrease in accounts payable in 2004 compared to an increase in 2003. For the six months ended June 30, 2004, the company contributed $2 million to other postretirement benefit plans but made no contribution to the pension plan. CASH FLOWS FROM INVESTING ACTIVITIES Net cash used in investing activities totaled $62 million and $148 million for the six months ended June 30, 2004 and 2003, respectively. The change was primarily due to the $122 million repayment of an intercompany loan by Sempra Energy in 2004. Significant capital expenditures in 2004 are expected to be for additions to the company's natural gas and electric distribution systems. These expenditures are expected to be financed by cash flows from operations and security issuances. In connection with the importation of additional sources of natural gas into Southern California, for which the California Utilities have made filings with the CPUC, the California Utilities could install capital facilities estimated at up to $200 million over three years, starting in 2005, in order to connect with new delivery locations. The expenditures would be included in utility ratebases or would be reimbursed by LNG project developers dependent on CPUC review of the projects and on the outcome of the Gas Market Order Instituting Investigation Phase II proceeding. CASH FLOWS FROM FINANCING ACTIVITIES Net cash provided by (used in) financing activities totaled $49 million and $(136) million for the six months ended June 30, 2004 and 2003, respectively. The change was due to $251 million of long-term debt issuances in 2004, partially offset by higher dividends paid to Sempra Energy in 2004. In June 2004, SDG&E issued $251 million of first mortgage bonds and applied the proceeds in July to refund an identical amount of first mortgage bonds and related tax-exempt industrial development bonds of a shorter maturity. The bonds, which mature in 2034 ($176 million) and in 2039 ($75 million), bear interest at rates that are periodically reset through auction procedures. They secure the repayment of tax-exempt industrial development bonds of an identical amount, maturity and interest rate issued by City of Chula Vista, the proceeds of which were loaned to SDG&E and repaid with payments on the first mortgage bonds.
29 In May 2004, the California Utilities obtained a combined $500 million three-year syndicated revolving credit facility to replace their expiring 364-day facility of a like amount. Under the facility, each utility may borrow up to $300 million, subject to a combined borrowing limit of $500 million. Borrowings would bear interest at rates varying with market rates and the borrowing utility's credit rating. The agreement requires each utility to maintain, at the end of each quarter, a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 60 percent. Borrowings under the agreement would be individual obligations of the borrowing utility and a default by one utility would not constitute a default or preclude borrowings by the other. FACTORS INFLUENCING FUTURE PERFORMANCE Performance of the company will depend primarily on the ratemaking and regulatory process, electric and natural gas industry restructuring, and the changing energy marketplace. These factors are discussed in the Annual Report and in Note 5 of the notes to Consolidated Financial Statements herein. NEW ACCOUNTING STANDARDS Relevant pronouncements that have recently become effective and have had a significant effect on the company are SFAS Nos. 143, 149 and 150, and FIN 46, as discussed in Note 2 of the notes to Consolidated Financial Statements. Pronouncements that have or are likely to have a material effect on future earnings are described below. SFAS 143, "Accounting for Asset Retirement Obligations": Beginning in 2003, SFAS 143 requires entities to record liabilities for future costs expected to be incurred when assets are retired from service, if the retirement process is legally required. It also requires the company to reclassify amounts recovered in rates for future removal costs not covered by a legal obligation from accumulated depreciation to a regulatory liability. Further discussion is provided in Note 2 of the notes to Consolidated Financial Statements. SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities": SFAS 149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS 133. Under SFAS 149, natural gas forward contracts that are subject to unplanned netting do not qualify for the normal purchases and normal sales exception, whereby derivatives are not required to be marked to market when the contract is usually settled by the physical delivery of natural gas. The company has determined that all natural gas contracts are subject to unplanned netting and as such, these contracts will be marked to market. In addition, effective January 1, 2004, power contracts that are subject to unplanned netting and that do not meet the normal purchases and normal sales exception under SFAS 149 will be further marked to market. Implementation of SFAS 149 on July 1, 2003 did not have a material impact on reported net income.
30 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK There have been no significant changes in the risk issues affecting the company subsequent to those discussed in the Annual Report. As of June 30, 2004, the total Value at Risk of SDG&E's positions was not material. ITEM 4. CONTROLS AND PROCEDURES The company has designed and maintains disclosure controls and procedures to ensure that information required to be disclosed in the company's reports under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and is accumulated and communicated to the company's management, including its Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating these controls and procedures, management recognizes that any system of controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired objectives and necessarily applies judgment in evaluating the cost-benefit relationship of other possible controls and procedures. Under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer, the company evaluated the effectiveness of the design and operation of the company's disclosure controls and procedures as of June 30, 2004, the end of the period covered by this report. Based on that evaluation, the company's Chief Executive Officer and Chief Financial Officer concluded that the company's disclosure controls and procedures were effective at the reasonable assurance level. There has been no change in the internal controls over financial reporting during the company's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the company's internal controls over financial reporting. ITEM 5. OTHER INFORMATION Effective May 1, 2004, Debra L. Reed, President of SoCalGas and SDG&E, also became their Chief Operating Officer. Simultaneously, Steven D. Davis, who remains Senior Vice President, External Relations, succeeded her as Chief Financial Officer.
31 PART II - OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS SDG&E and the County of San Diego are in the process of negotiating the remaining terms of a settlement relating to alleged environmental law violations by SDG&E and its contractors in connection with the abatement of asbestos-containing materials during the demolition of a natural gas storage facility that was completed in 2001. The expected settlement would involve payments by SDG&E of less than $750,000. Except as described above and in Notes 5 and 6 of the notes to Consolidated Financial Statements, neither the company nor its subsidiary is party to, nor is their property the subject of, any material pending legal proceedings other than routine litigation incidental to their businesses. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits Exhibit 12 -- Computation of ratios 12.1 Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends. Exhibit 31 -- Section 302 Certifications 31.1 Statement of Registrant's Chief Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934. 31.2 Statement of Registrant's Chief Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934. Exhibit 32 -- Section 906 Certifications 32.1 Statement of Registrant's Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350. 32.2 Statement of Registrant's Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350. (b) Reports on Form 8-K The following reports on Form 8-K were filed after March 31, 2004: Current Report on Form 8-K filed April 29, 2004, filing as an exhibit Sempra Energy's press release of April 29, 2004, giving the financial results for the quarter ended March 31, 2004. Current Report on Form 8-K filed August 5, 2004, filing as an exhibit Sempra Energy's press release of August 5, 2004, giving the financial results for the quarter ended June 30, 2004.
32 SIGNATURE Pursuant to the requirement of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. SAN DIEGO GAS & ELECTRIC COMPANY ------------------------------- (Registrant) Date: August 5, 2004 By: /s/ S. D. Davis ------------------------------ S. D. Davis Sr. Vice President-External Relations and Chief Financial Officer
|
EXHIBIT 12.1 |
||||||||||||||
|
SAN DIEGO GAS & ELECTRIC COMPANY |
||||||||||||||
|
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES |
||||||||||||||
|
AND PREFERRED STOCK DIVIDENDS |
||||||||||||||
|
(Dollars in millions) |
||||||||||||||
|
Six months ended |
||||||||||||||
|
1999 |
2000 |
2001 |
2002 |
2003 |
June 30, 2004 |
|||||||||
|
Fixed Charges and Preferred |
||||||||||||||
|
Stock Dividends: |
||||||||||||||
|
Interest |
$ 131 |
$ 119 |
$ 96 |
$ 83 |
$ 78 |
$ 37 |
||||||||
|
Interest portion of annual rentals |
5 |
3 |
3 |
4 |
3 |
1 |
||||||||
|
Total fixed charges |
136 |
122 |
99 |
87 |
81 |
38 |
||||||||
|
Preferred stock dividends (1) |
10 |
13 |
11 |
9 |
9 |
4 |
||||||||
|
Combined fixed charges and preferred stock |
||||||||||||||
|
dividends for purpose of ratio |
$ 146 |
$ 135 |
$ 110 |
$ 96 |
$ 90 |
$ 42 |
||||||||
|
Earnings: |
||||||||||||||
|
Pretax income from continuing operations |
$ 325 |
$ 295 |
$ 324 |
$ 300 |
$ 488 |
$ 155 |
||||||||
|
Total fixed charges (from above) |
136 |
122 |
99 |
87 |
81 |
38 |
||||||||
|
Less: interest capitalized |
1 |
3 |
1 |
1 |
1 |
- |
||||||||
|
Total earnings for purpose of ratio |
$ 460 |
$ 414 |
$ 422 |
$ 386 |
$ 568 |
$ 193 |
||||||||
|
Ratio of earnings to combined fixed charges |
||||||||||||||
|
and preferred stock dividends |
3.15 |
3.07 |
3.84 |
4.02 |
6.31 |
4.60 |
||||||||
|
|
||||||||||||||
|
(1) In computing this ratio, "Preferred stock dividends" represents the before-tax earnings necessary to pay such dividends, |
||||||||||||||
|
computed at the effective tax rates for the applicable periods |
||||||||||||||
EXHIBIT 31.1
CERTIFICATION
I, Edwin A. Guiles, certify that:
1. I have reviewed this Quarterly Report on Form 10-Q of San Diego Gas
& Electric Company;
2. Based on my knowledge, this Quarterly Report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect
to the period covered by this Quarterly Report;
3. Based on my knowledge, the financial statements and other financial
information included in this Quarterly Report fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented
in this Quarterly Report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the
registrant and we have:
a) Designed such disclosure controls and procedures, or caused
such disclosure controls and procedures to be designed under
our supervision, to ensure that material information relating
to the registrant, including its consolidated subsidiaries, is
made known to us by others within those entities, particularly
during the period in which this Quarterly Report is being
prepared;
b) Evaluated the effectiveness of the registrant's disclosure
controls and procedures and presented in this Quarterly Report
our conclusions about the effectiveness of the disclosure
controls and procedures, as of the end of the period covered
by this Quarterly Report, based on such evaluation; and
c) Disclosed in this report any change in the registrant's
internal control over financial reporting that occurred during
the registrant's most recent fiscal quarter that has
materially affected, or is reasonably likely to materially
affect, the registrant's internal control over financial
reporting;
5. The registrant's other certifying officer and I have disclosed,
based on our most recent evaluation of internal control over
financial reporting, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing
the equivalent function):
a) All significant deficiencies and material weaknesses in the
design or operation of internal controls over financial
reporting which are reasonably likely to adversely affect the
registrant's ability to record, process, summarize and report
financial information; and
b) Any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls over financial reporting.
August 5, 2004
/S/ EDWIN A. GUILES
Edwin A. Guiles
Chief Executive Officer
EXHIBIT 31.4
CERTIFICATION
I, Steven D. Davis, certify that:
1. I have reviewed this Quarterly Report on Form 10-Q of Southern
California Gas Company;
2. Based on my knowledge, this Quarterly Report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect
to the period covered by this Quarterly Report;
3. Based on my knowledge, the financial statements and other financial
information included in this Quarterly Report fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented
in this Quarterly Report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the
registrant and we have:
a) Designed such disclosure controls and procedures, or caused
such disclosure controls and procedures to be designed under
our supervision, to ensure that material information relating
to the registrant, including its consolidated subsidiaries, is
made known to us by others within those entities, particularly
during the period in which this Quarterly Report is being
prepared;
b) Evaluated the effectiveness of the registrant's disclosure
controls and procedures and presented in this Quarterly Report
our conclusions about the effectiveness of the disclosure
controls and procedures, as of the end of the period covered
by this Quarterly Report, based on such evaluation; and
c) Disclosed in this report any change in the registrant's
internal control over financial reporting that occurred during
the registrant's most recent fiscal quarter that has
materially affected, or is reasonably likely to materially
affect, the registrant's internal control over financial
reporting;
5. The registrant's other certifying officer and I have disclosed,
based on our most recent evaluation of internal control over
financial reporting, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing
the equivalent function):
a) All significant deficiencies and material weaknesses in the
design or operation of internal controls over financial
reporting which are reasonably likely to adversely affect the
registrant's ability to record, process, summarize and report
financial information; and
b) Any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls over financial reporting.
August 5, 2004
/S/ STEVEN D. DAVIS
Steven D. Davis
Chief Financial Officer
Exhibit 32.1
Statement of Chief Executive Officer
Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the
Sarbanes-Oxley Act of 2002, the undersigned Chief Executive Officer of
San Diego Gas & Electric (the "Company") certifies that:
(i) the Quarterly Report on Form 10-Q of the Company filed with
the Securities and Exchange Commission for the quarterly
period ended June 30, 2004 (the "Quarterly Report") fully
complies with the requirements of Section 13(a) or Section
15(d), as applicable, of the Securities Exchange Act of
1934, as amended; and
(ii) the information contained in the Quarterly Report fairly
presents, in all material respects, the financial condition
and results of operations of the Company.
August 5, 2004
/S/ EDWIN A. GUILES
______________________
Edwin A. Guiles
Chief Executive Officer
Exhibit 32.2
Statement of Chief Financial Officer
Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the
Sarbanes-Oxley Act of 2002, the undersigned Chief Financial Officer of
San Diego Gas & Electric (the "Company") certifies that:
(i) the Quarterly Report on Form 10-Q of the Company filed with
the Securities and Exchange Commission for the quarterly
period ended June 30, 2004 (the "Quarterly Report") fully
complies with the requirements of Section 13(a) or Section
15(d), as applicable, of the Securities Exchange Act of
1934, as amended; and
(ii) the information contained in the Quarterly Report fairly
presents, in all material respects, the financial condition
and results of operations of the Company.
August 5, 2004
/S/ STEVEN D. DAVIS
______________________
Steven D. Davis
Chief Financial Officer