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 1-14201
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Sempra Energy
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(Exact name of registrant as specified in its charter)
California 33-0732627
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
101 Ash Street, San Diego, California 92101
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(Address of principal executive offices)
(Zip Code)
(619) 696-2034
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(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period
that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days.
Yes X No
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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 X No
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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 on July 31, 2004: 231,795,224
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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, national and
international 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, environmental and other regulatory
bodies in countries other than the United States, 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 Sempra Energy (the company), a California-based Fortune 500 holding company. Sempra Energy's subsidiaries include San Diego Gas & Electric Company (SDG&E), Southern California Gas Company (SoCalGas) (collectively referred to herein as the California Utilities); Sempra Energy Global Enterprises (Global), which is the holding company for Sempra Energy Trading (SET), Sempra Energy Resources (SER), Sempra Energy International (SEI), Sempra Energy Solutions (SES) and other, smaller businesses; Sempra Energy Financial (SEF); and additional smaller businesses. The financial statements herein are the Consolidated Financial Statements of Sempra Energy and its consolidated subsidiaries. The accompanying Consolidated Financial Statements have been prepared in accordance with the interim-period-reporting requirements of Form 10-Q. Results of operations for interim periods are not necessarily indicative of results for the entire year. In the opinion of management, the accompanying statements reflect all adjustments necessary for a fair presentation. These adjustments are only of a normal recurring nature. Certain changes in classification have been made to prior presentations to conform to the current financial statement presentation. 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. The company follows the guidance of Statement of Financial Accounting Standards (SFAS) 142, "Goodwill and Other Intangible Assets." The carrying amount of goodwill (included in Noncurrent Sundry Assets on the Consolidated Balance Sheets) was $188 million as of December 31, 2003 and June 30, 2004. The California Utilities account for the economic effects of regulation on utility operations in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation."
9 NOTE 2. NEW ACCOUNTING STANDARDS 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 8 of the notes to Consolidated Financial Statements in the Annual Report discusses the company's expected contribution to its pension plans and other postretirement benefit plans in 2004. For the six months ended June 30, 2004, $9 million and $30 million of contributions have been made to its pension plans and other postretirement benefit plans, respectively, including $8 million and $16 million, respectively, for the three 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 utilities' 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 $1.4 billion at both dates for SoCalGas, and $868 million and $846 million, respectively, for SDG&E. 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 $ 337 Accretion expense (interest) 11 Payments (6) ------ Balance as of June 30, 2004 $ 342* ====== * The current portion of the obligation is included in Other Current Liabilities on the Consolidated Balance Sheets. SFAS 148, "Accounting for Stock-Based Compensation -- Transition and Disclosure": SFAS 148 requires quarterly disclosure of the effects that would have been recorded if the financial statements applied the fair value recognition principle of SFAS 123, "Accounting for Stock-Based Compensation." The company accounts for stock-based employee compensation plans under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations. For certain grants, no stock-based employee compensation cost is reflected in net income, since each option granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. The following table provides the pro forma effects of recognizing compensation expense in accordance with SFAS 148 had the company adopted the modified prospective method in January 2003:
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12 SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity": The company adopted SFAS 150 beginning July 1, 2003 by reclassifying $200 million of mandatorily redeemable trust preferred securities to Deferred Credits and Other Liabilities and $24 million of mandatorily redeemable preferred stock of subsidiaries to Deferred Credits and Other Liabilities and to Other Current Liabilities on the Consolidated Balance Sheets. On December 31, 2003, the $200 million of mandatorily redeemable trust preferred securities were reclassified to Due to Affiliates due to the adoption of FASB Interpretation No. (FIN) 46 as discussed below. Emerging Issues Task Force (EITF) 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities": In accordance with the EITF's rescission of Issue 98-10 by the release of Issue 02-3, the company no longer marks to market energy-related contracts unless the contracts meet the requirements stated under SFAS 133 and SFAS 149. A substantial majority of the company's contracts do meet these requirements. On January 1, 2003, the company recorded the initial effect of Issue 98-10's rescission as a cumulative effect of a change in accounting principle, which reduced after-tax earnings by $29 million. Neither the cumulative nor the ongoing effect impacts the company's cash flow or liquidity. Additional information on derivative instruments is provided in Note 5. FIN 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees": As of June 30, 2004, substantially all of the company's guarantees were intercompany, whereby the parent issues the guarantees on behalf of its consolidated subsidiaries. The only significant guarantees for which disclosure is required are the mandatorily redeemable trust preferred securities and $25 million related to debt issued by Chilquinta Energia Finance, LLC, an unconsolidated affiliate. The mandatorily redeemable trust preferred securities were also affected by FIN 46, as described below. 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. Variable interest entities (VIEs) are enterprises that have certain characteristics defined in FIN 46. Sempra Energy adopted FIN 46 on December 31, 2003, resulting in the consolidation of two VIEs for which it is the primary beneficiary. One of the VIEs (Mesquite Trust) was the owner of the Mesquite Power plant for which the company had a synthetic lease agreement, as described in Note 2 in the Annual Report. The Mesquite Power plant is a 1,250- megawatt (MW) plant that provides electricity to wholesale energy markets in the Southwest and that became fully operational in December 2003. The company recorded an after-tax credit of $9 million in 2003 for the cumulative effect of the change in accounting principle. The company bought out the lease in January 2004. The other VIE is Atlantic Electric & Gas (AEG), which marketed power and natural gas commodities to commercial and residential customers in the United Kingdom. Consolidation of AEG resulted in Sempra Energy's recording of 100 percent of AEG's balance sheet and results of operations, whereas it previously recorded only its share of AEG's net operating results. Due to AEG's consolidation, the company recorded an
13 after-tax charge of $26 million in 2003 for the cumulative effect of the change in accounting principle. During the first quarter of 2004, Sempra Energy's Board of Directors approved management's plan to dispose of AEG. Note 4 provides further discussion concerning this matter and the disposal of AEG's discontinued operations, which occurred in April 2004. In accordance with this interpretation, the company deconsolidated a wholly owned subsidiary trust from its financial statements at December 31, 2003. The trust has no assets except for its receivable from the company. Due to the deconsolidation of this entity, Sempra Energy reclassified $200 million of mandatorily redeemable trust preferred securities to Due to Affiliates on its Consolidated Balance Sheets. In addition, 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.
14 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 $ 121 $ 116 $ 318 $ 204 Minimum pension liability adjustments -- -- -- (6) Foreign currency adjustments (14) 30 (10) 44 Financial instruments (8) -- (13) -- --------------------------------- Comprehensive income $ 99 $ 146 $ 295 $ 242 - ----------------------------------------------------------------- NOTE 4. DISCONTINUED OPERATIONS During the first quarter of 2004, Sempra Energy's Board of Directors approved management's plan to dispose of its interest in AEG, which markets power and natural gas commodities to commercial and residential customers in the United Kingdom. This disposal met the criteria established for recognition as discontinued operations under SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." On April 27, 2004, AEG went into administrative receivership and substantially all of the assets were sold. This transaction resulted in a loss of $2 million after taxes, which has been reported separately on the Statements of Consolidated Income. The net losses from discontinued operations were $32 million ($0.14 per basic and diluted share) for the six months ended June 30, 2004 and $8 million ($0.04 per basic and diluted share) for the quarter ended June 30, 2004 (including the $2 million loss on disposal). During 2003, the company accounted for its investment in AEG under the equity method of accounting. As such, for the six-month and three-month periods ended June 30, 2003, the company recorded its share of AEG's net losses ($6 million and $3 million, respectively) in Other Income - Net on the Statements of Consolidated Income. Additionally, the company recorded offsetting interest income of $1 million for both periods. Effective December 31, 2003, AEG was consolidated as a result of the adoption of FIN 46. This is discussed further in the Annual Report.
15 Included within the net loss from discontinued operations are AEG's operating results, summarized below:
16 corresponding hedged transaction is settled. The ineffective portion is reported in earnings immediately. The company utilizes derivative instruments to reduce its exposure to unfavorable changes in energy and other commodity prices, which are subject to significant and often volatile fluctuation. The company also uses derivative physical and financial instruments to reduce its exposure to fluctuations in interest rates and foreign currency exchange rates. Derivative instruments include futures, forwards, swaps, options and long-term delivery contracts. These contracts allow the company to predict with greater certainty the effective prices to be received by the company and, in the case of the California Utilities, their 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. 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 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. Fixed-priced Contracts and Other Derivatives Fixed-priced Contracts and Other Derivatives on the Consolidated Balance Sheets primarily reflect the California Utilities' 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 at the California Utilities are not recoverable or payable through future rates, the California Utilities will apply 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 the settlement of the contingent purchase price obligation arising from the company's acquisition of the proposed Cameron liquefied natural gas (LNG) project and the physical deliveries under long-term purchased-power and natural gas transportation contracts. For the six months ended June 30, 2004, pre-tax income from transactions associated with fixed-price contracts and other derivatives included $13 million for the settlement of the Cameron contingency, which occurred during the first quarter. 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, 2003.
17 Trading Assets and Trading Liabilities Trading Assets and Trading Liabilities primarily arise from the activities of SET. SET derives revenue from market making and trading activities, as a principal, in natural gas, electricity, petroleum, petroleum products, metals and other commodities, for which it quotes bid and ask prices to other market makers and end users. It also earns trading profits as a dealer by structuring and executing transactions that permit its counterparties to manage their risk profiles. SET utilizes derivative instruments to reduce its exposure to unfavorable changes in market prices, which are subject to significant and often volatile fluctuation. These instruments include futures, forwards, swaps and options, and represent contracts with counterparties under which payments are linked to or derived from energy market indices or on terms predetermined by the contract, which may or may not be financially settled by SET. Sempra Energy guarantees many of SET's transactions. Trading instruments are recorded by SET on a trade-date basis and the majority of such derivative instruments are adjusted daily to current market value with gains and losses recognized in Other Operating Revenues on the Statements of Consolidated Income. Trading Assets or Trading Liabilities include amounts due from commodity clearing organizations, amounts due to or from trading counterparties, unrealized gains and losses from exchange-traded futures and options, derivative over-the-counter (OTC) swaps, forwards and options. Unrealized gains and losses on OTC transactions reflect amounts that would be received from or paid to a third party upon settlement of the contracts. Unrealized gains and losses on OTC transactions are reported separately as assets and liabilities unless a legal right of setoff exists under an enforceable netting arrangement. Other derivatives which qualify as hedges are accordingly recorded under hedge accounting. Futures and exchange-traded option transactions are recorded as contractual commitments on a trade-date basis and are carried at fair value based on closing market quotations. Commodity swaps and forward transactions are accounted for as contractual commitments on a trade- date basis and are carried at fair value derived from dealer quotations and underlying commodity exchange quotations. OTC options purchased and written are recorded on a trade-date basis. OTC options are carried at fair value based on the use of valuation models that utilize, among other things, current interest, commodity and volatility rates, as applicable. Energy commodity inventory is being recorded at the lower of cost or market; however metals inventories continue to be recorded at fair value in accordance with ARB 43, "Restatement and Revision of Accounting Research Bulletins."
18 The carrying values of SET's trading assets and trading liabilities are as follows: June 30, December 31, (Dollars in millions) 2004 2003 - ----------------------------------------------------------------------- Trading Assets Unrealized gains on swaps and forwards $ 1,577 $ 1,043 OTC commodity options purchased 594 459 Due from trading counterparties 1,594 2,183 Due from commodity clearing organizations and clearing brokers 160 134 Commodities owned 1,107 1,420 Other 5 1 ------- ------- Total $ 5,037 $ 5,240 ======= ======= - ----------------------------------------------------------------------- Trading Liabilities Unrealized losses on swaps and forwards $ 1,444 $ 1,095 OTC commodity options written 312 226 Due to trading counterparties 1,991 2,195 Repurchase obligations 375 866 Commodities not yet purchased -- 56 ------- ------- Total $ 4,122 $ 4,438 ======= ======= - ----------------------------------------------------------------------- At SET, market risk arises from the potential for changes in the value of physical and financial instruments resulting from fluctuations in prices and basis for natural gas, electricity, petroleum, petroleum products, metals and other commodities. Market risk is also affected by changes in volatility and liquidity in markets in which these instruments are traded. SET's credit risk from physical and financial instruments as of June 30, 2004 is represented by their positive fair value after consideration of collateral. Options written do not expose SET to credit risk. Exchange traded futures and options are not deemed to have significant credit exposure since the exchanges guarantee that every contract will be properly settled on a daily basis.
19 The following table summarizes the counterparty credit quality and exposure for SET at June 30, 2004 and December 31, 2003, expressed in terms of net replacement value. These exposures are net of collateral in the form of customer margin and/or letters of credit of $983 million and $569 million at June 30, 2004 and December 31, 2003, respectively. June 30, December 31, (Dollars in millions) 2004 2003 - ------------------------------------------------------------------------ Counterparty credit quality* Commodity exchanges $ 160 $ 134 AAA 9 5 AA 277 310 A 581 463 BBB 542 345 Below investment grade 427 357 ------- ------- Total $ 1,996 $ 1,614 ======= ======= * As determined by rating agencies or internal models intended to approximate rating-agency determinations. NOTE 6. 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 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
20 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 MW of electric capacity in 2005 increasing to 291 MW 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 SER 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. 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
21 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. The stayed decision, if implemented, would unbundle the costs of SoCalGas' backbone transmission system from rates and result in revising noncore balancing account treatment to exclude the balancing of SoCalGas' backbone transmission costs and place SoCalGas at risk for recovery of $80 million for transmission and $81 million for storage (current dollars). The decision would create firm tradable rights for the transmission system. Other noncore costs/revenues would continue to be fully balanced until the decision in the next Biennial Cost Allocation Proceeding (BCAP) discussed below. 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
22 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. The California Utilities are requesting revenue increases of $101 million. On December 19, 2003, settlements were filed with the CPUC for SoCalGas and SDG&E that, if approved, would resolve most of the Cost of Service issues. A CPUC decision is expected later this year. The SoCalGas settlement would reduce rate revenues by $33 million from 2003 rate revenues. 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, the California Utilities generally are recognizing revenue consistent with the proposed settlements, 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. The California Utilities 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
23 limited to a return on new capital additions. Edison has applied for permission to replace SONGS' steam generator, which would increase the 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, demand-side management (DSM) and Gas Cost Incentive Mechanism (GCIM) rewards are not included in the company's earnings before CPUC approval is received. The only incentive reward approved during the first six months of 2004 was $6.3 million related to SoCalGas' Year 9 GCIM, which was approved on February 26, 2004. This reward is subject to refunds based on the outcome of the Border Price Investigation. The cumulative amount of rewards subject to refund based on the outcome of the Border Price Investigation described below is $65.1 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 SoCalGas SDG&E Total - ----------------------------------------------------------- DSM/Energy Efficiency* $ 10.9 $ 37.7 $ 48.6 2003 Distribution PBR -- 8.2 8.2 GCIM/natural gas PBR 2.4 1.5 3.9 2003 safety .5 -- .5 - ----------------------------------------------------------- Total $ 13.8 $ 47.4 $ 61.2 - ----------------------------------------------------------- * 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
24 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. 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, SoCalGas' authorized ROE is 10.82 percent and its return on ratebase (ROR) is 8.68 percent. Effective January 1, 2003, SDG&E's authorized ROE is 10.9 percent and its ROR 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. In SDG&E's case, 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. SoCalGas' automatic adjustment occurs when the 12-month trailing average of 30-year Treasury bond rates and the Global Insight forecast of the 30-year Treasury bond rate 12 months ahead vary by greater than 150 basis points from the benchmark, which is currently 5.38 percent. The 12-month trailing average was 5.11 percent at June 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 California Utilities and adjusts rates to reflect variances in customer demand as compared to the forecasts previously used in establishing transportation rates. SoCalGas and SDG&E filed with the CPUC their 2005 BCAP applications 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. As a result of the deferrals
25 and the forecasted significant decline in noncore gas throughput on SoCalGas' system, in December 2002 the CPUC issued a decision approving 100 percent balancing account protection for SoCalGas' risk on local transmission and distribution revenues from January 1, 2003 until the CPUC issues its next BCAP decision. SoCalGas is seeking to continue this balancing account protection in the Natural Gas OIR proceeding. 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 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. The ORA filed testimony supporting the GCIM and the actions of SoCalGas during this period. The actions of other Sempra Energy companies are to be considered in a separate phase of the investigation, for which the schedule has been suspended. 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.
26 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 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, such as SET, are required to provide refunds. To the extent any such refunds are actually realized by SDG&E, they would reduce SDG&E's rate-ceiling balancing account. To the extent that SET is required to provide refunds, they could result in payments by SET after adjusting for any amounts still owed to SET for power supplied during the relevant period (or receipts if refunds are less than amounts owed to SET).
27 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. SET and other power suppliers have joined in appeal of the FERC's preliminary findings and requested rehearing. The company previously had established reserves for its likely share of the original $1.8 billion. During the quarter ended June 30, 2004, the company recorded additional reserves to reflect the estimated effect of the FERC's revising the benchmark prices to be used by the FERC in assessing the affect of the alleged actions. Manipulation Investigation The FERC is also investigating whether there was manipulation of short- term energy markets in the West that would constitute violations of applicable tariffs and warrant disgorgement of associated profits. In this proceeding, the FERC's authority is not confined to the October 2, 2000 through June 20, 2001 period relevant to the refund proceeding. In May 2002, the FERC ordered all energy companies engaged in electric energy trading activities to state whether they had engaged in various specific trading activities in violation of the PX and ISO tariffs (generally described as manipulating or "gaming" the California energy markets). On June 25, 2003, the FERC issued several orders requiring various entities to show cause why they should not be found to have violated California ISO and PX tariffs. First, FERC directed 43 entities, including SET and SDG&E, to show cause why they should not disgorge profits from certain transactions between January 1, 2000 and June 20, 2001 that are asserted to have constituted gaming and/or anomalous market behavior under the California ISO and/or PX tariffs. Second, the FERC directed more than 20 entities, including SET, to show cause why their activities during the period January 1, 2000 to June 20, 2001 did not constitute gaming and/or anomalous market behavior in violation of the tariffs. Remedies for confirmed violations could include
28 disgorgement of profits and revocation of market-based rate authority. The FERC has encouraged the entities to settle the issues and on October 31, 2003, SET agreed to pay $7.2 million in full resolution of these investigations. That liability was recorded as of December 31, 2003. The entire proceeding, including the settlement, received final FERC approval on July 28, 2004. 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 as to SDG&E. 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, including SET, 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. Both SDG&E and SET 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 and SET that their 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 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. Claims alleged against SET are still pending.
29 NOTE 7. 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. ARGENTINE INVESTMENTS As a result of the devaluation of the Argentine peso at the end of 2001 and subsequent declines in the value of the peso, SEI reduced the carrying value of its investment downward by a cumulative total of $197 million as of June 30, 2004 and December 31, 2003. These non-cash adjustments continue to occur based on fluctuations in the Argentine peso. They do not affect net income, but increase or decrease other comprehensive income (loss) and accumulated other comprehensive income (loss). A decision is expected in 2005 on SEI's arbitration proceedings under the 1994 Bilateral Investment Treaty between the United States and
30 Argentina for recovery of the diminution of the value of SEI's investments that has resulted from Argentine governmental actions. Sempra Energy also has a $48.5 million political-risk insurance policy under which it filed a claim to recover a portion of the investments' diminution in value. LITIGATION Except for the matters referred to below, neither the company nor its subsidiaries are party to, nor is their property the subject of, any material pending legal proceedings other than routine litigation incidental to their businesses. Management believes that none of these matters will have further material adverse effect on the company's financial condition or results of operations. DWR Contract In 2003, SER was awarded judgment in its favor in the state civil action between SER and the DWR, in which the DWR sought to void its 10- year contract under which the company sells energy to the DWR. The DWR filed an appeal of this ruling in January 2004. A decision by the appellate court is expected during 2005. The DWR continues to accept all scheduled power from SER and, although it has disputed billings in an immaterial amount and the manner of certain deliveries, it has paid all amounts that have been billed under the contract. However, in 2004, the DWR has commenced an arbitration proceeding, disputing SER's performance on various operational matters. Among other proposed remedies, the DWR has requested a declaration by the arbitration panel that SER's inadequate performance constitutes a material breach of the agreement permitting it to terminate the contract. SER believes these claims are without merit. 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
31 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 (SDG&E, SET and SER, depending on the lawsuit) 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 addition, in May 2003, the Port of Seattle filed a similar complaint against a number of energy companies (including Sempra Energy, SER and SET). That action was dismissed by the San Diego Federal District Court in May 2004. Plaintiff has appealed the decision. In May and June 2004, two new cases were filed in federal court alleging substantially identical claims to those in Port of Seattle against Sempra Energy and certain subsidiaries (SDG&E, SER and SET depending on the lawsuit). SER, SET and SDG&E, 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 In May 2003 and February 2004, actions against various trade publications and other energy companies, alleging that energy prices were unlawfully manipulated by defendants' reporting artificially inflated natural gas prices to trade publications and by entering into wash trades, were filed in San Diego Superior Court against Sempra Energy and SET. Both actions have been removed to Federal District Court. Another lawsuit containing identical allegations was filed against Sempra Energy and SET in Federal District Court in November of 2003. 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 similar actions in San Diego Superior Court against Sempra Energy, SET, SoCalGas and SDG&E. In addition, in August 2003, a lawsuit was filed in the Southern District of New York against Sempra Energy and SES, alleging that the prices of natural gas options traded on the NYMEX were unlawfully increased under the Federal Commodity Exchange Act by defendants' manipulation of transaction data provided to natural gas trade publications. In November of 2003, another suit containing
32 identical allegations was filed and consolidated with the New York action. Subsequently, plaintiffs dismissed Sempra Energy and SES from these cases. On January 20, 2004, plaintiffs filed an amended consolidated complaint that named SET as a defendant in this lawsuit. In March 2004, defendants filed a motion to dismiss the action. No hearing date has been set by the Court. 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. In May 2003, a federal judge issued an order finding that the Department of Energy's (DOE) abbreviated assessment of two Mexicali power plants, including SER's Termoelectrica de Mexicali (TDM) plant, failed to evaluate the plants' environmental impact adequately and called into question the U.S. permits they received to build their cross-border transmission lines. In July 2003, the judge ordered the DOE to conduct additional environmental studies and denied the plaintiffs' request for an injunction blocking operation of the transmission lines, thus allowing the continued operation of the TDM plant. The DOE undertook to perform an Environmental Impact Study, which is expected to be completed in December 2004. The Peruvian appellate court has affirmed the dismissal of the charges against officers of Luz del Sur S.A.A. (Luz del Sur), a company affiliate, and others concerning the price of utility assets acquired by Luz del Sur from the Peruvian government. At June 30, 2004, SET remains due approximately $100 million from energy sales made in 2000 and 2001 through the ISO and the PX markets. The collection of these receivables depends on several factors, including the FERC refund case. The company believes adequate reserves have been recorded. 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 $40.7 million to SoCalGas' core gas customers, $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 $42 million was received in June 2004, which will be followed by 19 annual payments.
33 INCOME TAX ISSUES Section 29 Income Tax Credits On July 1, 2004, SEF sold its investment in an enterprise that earns Section 29 income tax credits. That investment comprised one-third of Sempra Energy's Section 29 participation and was sold because the company's alternative minimum tax position defers utilization of the credits in the determination of income taxes currently payable. The sale will have a minor negative affect on the company's recorded income in the future, but will have a minor positive affect on its cash flow. The IRS recently concluded its examinations of the company's Section 29 income tax credits for certain years, reporting no change in the credits. From acquisition of the facilities in 1998 through December 31, 2003, the company has generated Section 29 income tax credits of $251 million. In addition, the company has generated Section 29 tax credits of $51 million for the six months ended June 30, 2004, of which $27 million occurred in the second quarter. The company believes disallowance of its Section 29 income tax credits is unlikely. NOTE 8. SEGMENT INFORMATION The company is a holding company, whose subsidiaries are primarily engaged in the energy business. It has four separately managed reportable segments: SoCalGas, SDG&E, SET and SER, which are described in the Annual Report. The accounting policies of the segments are described in the notes to Consolidated Financial Statements in the Annual Report, and segment performance is evaluated by management based on reported income. There were no significant changes in segment assets during the six months ended June 30, 2004.
34 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. OVERVIEW Sempra Energy is a Fortune 500 energy services holding company. Its business units provide a wide spectrum of value-added electric and natural gas products and services to a diverse range of customers. Operations are divided between delivery services, comprised of the California utility subsidiaries, and Sempra Energy Global Enterprises. RESULTS OF OPERATIONS Net income and operating income for the three months and for the six months ended June 30, 2004 were up substantially from the corresponding periods of 2003. The following table summarizes the major factors affecting the comparisons for both periods.
35 California Utility Revenues and Cost of Sales Natural gas revenues increased to $2.3 billion for the six months ended June 30, 2004 from $2.1 billion for the corresponding period in 2003, and the cost of natural gas increased to $1.3 billion in 2004 from $1.2 billion in 2003. These increases were primarily attributable to natural gas cost increases, which are passed on to customers, and increased volumes. Additionally, natural gas revenues were relatively unchanged at $947 million for the quarter ended June 30, 2004 compared to $929 million for the corresponding period in 2003, and the cost of natural gas was relatively unchanged at $482 million in 2004 compared to $480 million in 2003. Higher natural gas costs in the second quarter of 2004 were offset by lower gas sales volumes. 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, SoCalGas' GCIM allows SoCalGas to share in the savings or costs from buying natural gas for customers below or above monthly benchmarks. The mechanism permits full recovery of all costs within a tolerance band above the benchmark price and refunds all savings within a tolerance band below the benchmark price. The costs or savings outside the tolerance band are shared between customers and shareholders. In addition, SDG&E's 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. Electric revenues increased to $801 million for the six months ended June 30, 2004 from $792 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 6 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 $420 million for the quarter ended June 30, 2004 from $397 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. 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, the California Utilities are generally recognizing 2004 revenue consistent with the proposed settlements, 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.
36 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 natural gas and electric volumes and revenues by customer class for the six months ended June 30, 2004 and 2003.
37 Although commodity-related revenues from the DWR's purchasing of SDG&E's net short position or from the DWR's allocated contracts are not included in revenue, the associated volumes and distribution revenue are included herein. Beginning in 2004, off-system sales are accounted for as a reduction of the cost of purchased power. Other Operating Revenues Other operating revenues, which consist primarily of revenues at Global, increased to $1.3 billion for the six months ended June 30, 2004 from $880 million for the same period of 2003, and increased to $629 million for quarter ended June 30, 2004 from $514 million for the same period of 2003. These changes were primarily due to higher revenues at SER resulting from increased volumes of contract sales associated with energy produced by the new generating plants. The increase for the six-month period was also due to higher revenues at SET resulting from increased commodity revenue from metals and petroleum. Other Cost of Sales Other cost of sales, which consists primarily of cost of sales at Global, increased to $702 million for the six months ended June 30, 2004 from $515 million for the same period of 2003, and increased to $375 million for the quarter ended June 30, 2004, from $296 million for the same period in 2003. The increases were primarily due to costs related to the higher sales for SER as noted above. Other Operating Expenses Other operating expenses increased to $1.1 billion for the six months ended June 30, 2004 from $1.0 billion for the same period in 2003, including $716 million and $682 million in 2004 and 2003, respectively, related to the California Utilities. The increase was primarily due to higher operating costs at SET related to increased trading activity, the new generating plants coming on line and litigation expenses. Additionally, increases were due to nuclear refueling costs at SONGS and increases in other operating expenses at the California Utilities. Other operating expenses increased to $546 million for the quarter ended June 30, 2004 from $518 million for the same period in 2003, including $374 million and $364 million in 2004 and 2003, respectively, related to the California Utilities. The change was due primarily to the increased litigation costs, nuclear refueling costs at SONGS and increases in other operating expenses at the California Utilities. Other Income - Net Other income, which primarily consists of equity earnings from unconsolidated subsidiaries and interest on regulatory balancing accounts, increased to $18 million for the six months ended June 30, 2004 from $4 million for the same period of 2003, and increased to $13 million for the quarter ended June 30, 2004 from $9 million for the same period of 2003. The increase for the six-month period was primarily due to the $8 million after tax gain on the settlement of an
38 unpaid portion of the purchase price of the proposed Cameron LNG project for an amount less than the liability (which had been recorded as a derivative) and increased equity earnings at SEI, including $5 million from the partial sale of Luz del Sur. The increase for the quarter was due to lower regulatory interest expense at SoCalGas and the increased equity earnings at SEI. Interest Income Interest income increased to $33 million for the six months ended June 30, 2004 from $22 million for the same period of 2003 due primarily to interest from the Internal Revenue Service during the first quarter of 2004. Interest Expense Interest expense increased to $160 million for the six months ended June 30, 2004 from $145 million for the same period of 2003, and increased to $80 million for the quarter ended June 30, 2004 from $71 million for the same period of 2003. The increases were primarily the result of the reclassification of preferred dividends on mandatorily redeemable trust preferred securities and preferred stock of subsidiaries to interest expense as a result of the adoption on July 1, 2003 of SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity," as well as higher capitalized interest at SER in 2003. Income Taxes Income tax expense increased to $88 million for the six months ended June 30, 2004 from $51 million for the same period of 2003. The corresponding effective income tax rates were 20.1 percent and 17.9 percent, respectively. Additionally, income tax expense increased to $31 million for the second quarter of 2004 compared to $27 million for the second quarter of 2003, and the effective income tax rate increased to 19.6 percent in 2004 from 19.0 percent in 2003. The changes were due primarily to higher taxable income and the higher effective income tax rate in 2004, despite the reduction in estimated income tax liabilities for certain prior years. Discussion of Section 29 income tax credits is provided in Note 7 herein and in Note 7 of the notes to Consolidated Financial Statements of the Annual Report. Discontinued Operations During the first quarter of 2004 Sempra Energy's Board of Directors approved management's plan to dispose of the company's interest in AEG. On April 27, 2004, the company disposed of AEG at a $2 million loss net of income taxes. Including the $2 million loss on disposal, AEG's losses were $32 million ($0.14 per diluted share) and $8 million ($0.04 per diluted share), respectively, for the six months and three months ended June 30, 2004. Note 4 of the notes to Consolidated Financial Statements provides further details. During 2003, the company accounted for its investment in AEG under the equity method of accounting. As such, for the six-month and three-month periods ended June 30, 2003, the company recorded its share of AEG's net loss as a $6 million and $3 million loss, respectively, in Other
39 Income - Net on the Statements of Consolidated Income. Additionally, the company recorded offsetting interest income of $1 million for both periods. Effective December 31, 2003, AEG was consolidated as a result of the adoption of FIN 46. This is discussed further in Note 2 herein and in the Annual Report. Net Income Net income for the six months ended June 30 increased to $318 million, or $1.37 per diluted share of common stock, in 2004 from $204 million, or $0.98 per diluted share in 2003. Additionally, net income for the second quarter was $121 million, or $0.52 per diluted share for 2004, compared to $116 million or $0.55 per diluted share in 2003. Unusual items affecting these comparisons are provided in the first table in this section. Although net income increased for both periods, earnings per share were impacted by dilution from the issuance of 16.5 million additional shares in the fourth quarter of 2003. The only differences between basic and diluted earnings per share are the effects of common stock options and the Equity Units, discussed in Note 12 of the Annual Report.
40 SOUTHERN CALIFORNIA GAS COMPANY SoCalGas recorded net income of $106 million and $95 million for the six-month periods ended June 30, 2004 and 2003, respectively, and net income of $50 million and $37 million for the quarters ended June 30, 2004 and 2003, respectively. The changes were primarily due to improved operating results in 2004. SAN DIEGO GAS & ELECTRIC SDG&E recorded net income of $80 million and $86 million for the six- month periods ended June 30, 2004 and 2003, respectively, and net income of $30 million and $41 million for the quarters ended June 30, 2004 and 2003, respectively. The decreases were primarily due to the absence of the 2003 Incremental Cost Incentive Pricing for SONGS and performance-based regulation gains and higher operating costs, offset by higher revenues. SEMPRA ENERGY TRADING SET recorded net income of $99 million and $45 million for the six- month periods ended June 30, 2004 and 2003, respectively, excluding the cumulative effect of the change in accounting principle of ($28) million in 2003. Additionally, SET recorded net income of $40 million and $35 million for the quarters ended June 30, 2004 and 2003, respectively. The increases were primarily attributable to higher trading margin on metals and petroleum, offset by litigation expenses. A summary of SET's unrealized revenues for trading activities for the six months ended June 30, 2004 and 2003 follows: (Dollars in millions) 2004 2003 - ----------------------------------------------------------------- Balance at December 31 $ 269 $ 180 Cumulative effect adjustment -- (48) Additions 701 599 Realized (369) (277) ---------------------- Balance at June 30 $ 601 $ 454 - -----------------------------------------------------------------
41 The estimated fair values for SET's trading activities as of June 30, 2004, and the periods during which unrealized revenues are expected to be realized, are (dollars in millions):
42 price of the proposed Cameron LNG project for an amount less than the liability (which had been recorded as a derivative). Additionally, the changes for both periods were impacted by a gain on the sale of a portion of SEI's interests in Luz del Sur, a Peruvian electric utility, and increased earnings from the company's Gasoducto Bajanorte natural gas pipeline, offset by the impact of changes in estimates for certain income tax issues in the second quarter of 2004 and start-up costs at SELNG. SEMPRA ENERGY SOLUTIONS SES recorded a net loss of $1 million and net income of $8 million for the six-month periods ended June 30, 2004 and 2003, respectively, excluding the cumulative effect of the change in accounting principle of ($1) million in 2003. SES recorded net income of $3 million and $8 million for the quarters ended June 30, 2004 and 2003, respectively. The decreases in 2004 were primarily due to lower net commodity revenues. SEMPRA ENERGY FINANCIAL SEF recorded net income of $16 million and $19 million for the six- month periods ended June 30, 2004 and 2003, respectively, and net income of $6 million and $8 million for the quarters ended June 30, 2004 and 2003, respectively. PARENT AND OTHER Net losses for Parent and Other were $41 million and $60 million for the six-month periods ended June 30, 2004 and 2003, respectively, and $37 million and $36 million for the quarters ended June 30, 2004 and 2003, respectively. The six-month period improved primarily because of increased interest income in 2004 and the change in estimate of federal and state income tax liabilities for certain prior years. CAPITAL RESOURCES AND LIQUIDITY The company's California Utility operations are the major source of liquidity. Funding of other business units' capital expenditures is significantly dependent on the California Utilities' paying sufficient dividends to Sempra Energy and on SET's liquidity requirements, which fluctuate significantly. At June 30, 2004, the company had $1.2 billion in cash and $2.6 billion in available unused, committed lines of credit. Total available unused, committed lines of credit increased to $3.1 billion at July 31, 2004. See "Cash Flows from Financing Activities" for discussion on changes in credit facilities in 2004. Management believes these amounts and cash flows from operations and new security issuances will be adequate to finance capital expenditure requirements, shareholder dividends, any new business acquisitions or start-ups, and other commitments. If cash flows from operations were to be significantly reduced or the company were to be unable to issue new securities on acceptable terms, neither of which is considered likely, the company would be required to reduce non-utility capital expenditures
43 and investments in new businesses. Management continues to regularly monitor the company's ability to finance the needs of its operating, financing and investing activities in a manner consistent with its intention to maintain strong, investment-quality credit ratings. Rating agencies and others that evaluate a company's liquidity generally consider a company's capital expenditures and working capital requirements in comparison to cash from operations, available credit lines and other sources available to meet liquidity requirements. At the California Utilities, cash flows from operations and from new and refunding debt issuances are expected to continue to be adequate to meet utility capital expenditure requirements and provide dividends to Sempra Energy. In June 2004, SDG&E received CPUC approval of its plans to purchase from SER a $456 million, 550-MW generating facility to be constructed in Escondido, California. As a result, the level of SDG&E's dividends to Sempra Energy is expected to be significantly lower during the construction of the facility to enable SDG&E to increase its equity in preparation for the purchase of the completed facility. SET provides or requires cash as the level of its net trading assets fluctuates with prices, volumes, margin requirements (which are substantially affected by credit ratings and commodity price fluctuations) and the length of its various trading positions. Its status as a source or use of cash also varies with its level of borrowing from its own sources. SET's intercompany borrowings were $461 million at June 30, 2004, up from $359 million at December 31, 2003. SET's external debt was $72 million at June 30, 2004. In June 2004, SET obtained a $1 billion revolving line of credit. Additional information on the line of credit is provided in "Cash Flows from Financing Activities." Company management continuously monitors the level of SET's cash requirements in light of the company's overall liquidity. SELNG will require funding for its planned development of LNG receiving facilities. While funding from the company is expected to be adequate for these requirements, the company may decide to use project financing if that is believed to be advantageous. SEI is expected to require funding from the company and/or external sources to continue the expansion of its existing natural gas distribution operations in Mexico and its planned development of pipelines to serve LNG facilities expected to be developed in Baja California, Mexico; Hackberry, Louisiana; and Port Arthur, Texas, as discussed in "Cash Flows From Investing Activities," below. SER's projects are expected to be financed through a combination of project financing, SER's cash from operations and borrowings, and funds from the company. In the longer term, SEF is expected to again be a net provider of cash through reductions of consolidated income tax payments resulting from its investments in affordable housing. However, that was not true in 2003 and will not be true in the near term, while the company is in an alternative minimum tax position.
44 CASH FLOWS FROM OPERATING ACTIVITIES Net cash provided by operating activities totaled $652 million and $758 million for the six months ended June 30, 2004 and 2003, respectively. The change was attributable to an increase in net trading assets in 2004 compared to a decrease in 2003, partially offset by higher net income and a higher decrease in accounts receivable in 2004. For the six months ended June 30, 2004, the company made pension plan contributions of $9 million and payments for other postretirement benefit plans of $30 million. CASH FLOWS FROM INVESTING ACTIVITIES Net cash provided by (used in) investing activities totaled $12 million and $(641) million for the six months ended June 30, 2004 and 2003, respectively. The change was primarily attributable to proceeds from the sale of U.S. Treasury obligations which previously securitized the Mesquite synthetic lease. The collateral was no longer necessary as SER bought out the lease in January 2004. The decrease in cash used in investing activities was also due to lower investments primarily as a result of completion of the Elk Hills and Mesquite power plants. In addition, the company had proceeds of $112 million from the disposal of AEG's discontinued operations. On April 1, 2004, SEI and PSEG Global, an unaffiliated company, sold a portion of their interests in Luz del Sur for a total of $62 million. Each party had a 44-percent interest in Luz del Sur prior to the sale compared to a 38-percent interest after the sale was completed. SEI recognized an after-tax gain of $5 million as a result of the sale. Starting in 2003 and through the end of the second quarter of 2004, SET spent $77 million related to the development of Bluewater Gas Storage, LLC. SET owns the rights to develop the facility and to utilize its capacity to store natural gas for customers who buy, sell or transport natural gas to Michigan. The FERC-regulated, market-based-pricing facility started injecting natural gas during the second quarter of 2004. On April 16, 2004, the company announced the acquisition of land and associated rights for the development of a salt-cavern natural gas storage facility in Evangeline Parish, Louisiana. This facility, operating as the Pine Prairie Energy Center, will consist of three salt caverns with a total capacity of 24 billion cubic feet (bcf) of natural gas and is expected to begin operations by the fourth quarter of 2005 and to cost approximately $175 million. The company is currently negotiating contracts to sell the capacity of this facility. FERC approval for the construction and operation of the facility is pending. On July 20, 2004, the company announced that it had acquired the rights to develop a salt-cavern natural gas storage facility located in Calcasieu Parish, Louisiana, called "Liberty," that is expected to have capacity of 17 bcf. On April 21, 2004, SELNG announced plans to develop and construct a new $600 million LNG receiving terminal near Port Arthur, Texas. The terminal would be capable of processing 1.5 bcf of natural gas per day and could be expanded to 3 bcf per day. The company is currently in the
45 process of obtaining FERC approval for the construction of the terminal. The project is expected to begin construction in 2006 with start-up slated for 2009. On July 1, 2004, Sempra Energy Partners and Carlyle/Riverstone, an energy and power-focused equity fund, completed their acquisition of ten power plants from American Electric Power (AEP), including the Coleto Creek Power Station, a 632-MW coal-fired power plant in Goliad County, Texas, for $430 million and advanced additional working capital. $355 million of the purchase price was provided by project financing which is non-recourse to the joint venture partners. Excluding the Coleto Creek Power Station, the transaction included the acquisition of five operating power plants with generating capacity of 1,318 MW and four inactive power plants (capable of generating 1,863 MW) in Texas. The joint venture partners have sold one of the inactive power plants. Coleto Creek Power Station and the eight other power plants retained by the partners will comprise the newly formed Topaz Power Partners, a 50/50 joint venture. In addition, the joint venture partners have entered into several power sales agreements for 572 MW of Coleto Creek Power Station's capacity. The weighted-average life of the contracts is 4.3 years. The company expects to make capital expenditures and investments of $1.2 billion in 2004, of which $511 million had been expended as of June 30, 2004. Significant capital expenditures and investments are expected to include $750 million for California utility plant improvements and $100 million for the development of LNG regasification terminals. These expenditures and investments 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 $54 million and $(247) million for the six months ended June 30, 2004 and 2003, respectively. The change was due to higher long-term debt issuances and a net increase in short-term debt, partially offset by higher long-term debt payments in 2004. In May 2004, the company issued $600 million of senior unsecured notes, consisting of $300 million of 4.75-percent fixed-rate, five-year notes and $300 million of four-year, floating-rate notes. The proceeds of the issuance were used to repay $500 million of debt maturing July 1, 2004, and for general corporate purposes. 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
46 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. In January 2004, SER purchased the assets of Mesquite Trust, the owner of the Mesquite Power plant, thereby extinguishing $630 million of debt outstanding. Also in 2004, SoCalGas repaid $175 million of first mortgage bonds. 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. In May 2004, the company entered into an interest-rate swap agreement that effectively changed the interest rate on $300 million of 7.95% notes (issued in February 2000) from fixed to floating. The swap is set to expire in 2010, the same year the related debt matures. In June 2004, SET obtained a two-year syndicated revolving line of credit providing for extensions of credit (consisting of borrowings, letters of credit and other credit support accommodations) to SET and certain of its affiliates of up to $1 billion. The amount of credit extended on a non-guaranteed basis is limited by the amount of a borrowing base consisting of receivables, inventories and other assets of SET that secure the credit facility and are valued for purposes of the borrowing base at varying percentages of current market value. Credit utilization above the borrowing base (up to a maximum of $500 million) is guaranteed by Sempra Energy subject to the overall $l billion credit limit. Non-guaranteed extensions of credit bear interest and fees that vary with SET's tangible net worth and guaranteed extensions bear interest and fees varying with Sempra Energy's credit ratings. Extensions of credit are subject to the absence of any development or event that has had or would reasonably be expected to have a material adverse effect on SET. The facility also requires SET to meet certain financial tests at the end of each quarter (including a current ratio, leverage ratio and minimum consolidated net worth tests) and (while guaranteed borrowings are outstanding) also requires Sempra Energy to meet, at the end of each quarter and as defined in the credit facility, a leverage ratio of consolidated indebtedness to consolidated total capitalization of not more than .65 to 1. It also imposes certain other limitations on SET including limitations on other indebtedness, capital expenditures, liens, transfers of assets, investments, loans, advances, dividends, other distributions, modifications of risk-management policies and transactions with affiliates. The facility replaced $490 million of SET's $764 million uncommitted credit lines. At June 30, 2004
47 outstanding extensions of credit under the facility totaled $371 million. In July 2004, Global obtained a $1.5 billion three-year syndicated revolving credit facility to replace its expiring $500 million revolving credit facility and the expiring $400 million revolving credit facility of SER. Global continues to have a substantially identical $500 million three-year revolving credit facility that expires in 2006. Borrowings under each facility would be guaranteed by Sempra Energy and bear interest at rates varying with market rates and Sempra Energy's credit rating. Each facility requires Sempra Energy to maintain, at the end of each quarter, a ratio of total indebtedness to total capitalization (as identically defined in each facility) of no more than 65 percent. FACTORS INFLUENCING FUTURE PERFORMANCE Base results of the company in the near future will depend primarily on the results of the California Utilities, while earnings growth and variability will result primarily from activities at SET, SER, SELNG and SEI. Notes 6 and 7 of the notes to Consolidated Financial Statements herein and Notes 13 through 15 of the Annual Report describe events in the deregulation of California's electric and natural gas industries and various FERC, SET and income tax issues. California Utilities Note 6 of the notes to Consolidated Financial Statements contains discussions of electric and natural gas restructuring and rates, the pending cost of service filings and the CPUC's investigation of compliance with affiliate rules. Sempra Energy Global Enterprises Electric-Generation Assets As discussed in more detail in "Cash Flows From Investing Activities," the company is involved in the expansion of its electric-generation capabilities, including the AEP-related acquisition noted above, which will significantly impact the company's future performance. Investments As discussed in "Cash Flows From Investing Activities," the company's investments will significantly impact the company's future performance. SELNG is in the process of developing Energia Costa Azul, an LNG receiving terminal in Baja California, Mexico; the Cameron LNG receiving terminal in Hackberry, Louisiana; and the Port Arthur LNG receiving terminal near Port Arthur, Texas. The viability and future profitability of this business unit is dependent upon numerous factors, including the relative prices of natural gas in North America and from LNG suppliers located elsewhere, negotiating sale and supply contracts at adequate margins, and completing cost-effective construction of the required facilities.
48 Beginning in 2003, SET started expanding its natural gas storage capacity by developing Bluewater Gas Storage, LLC. In April 2004, SET announced the acquisition of land and associated rights for the development of a salt-cavern natural gas storage facility in Evangeline Parish, Louisiana. In July 2004, the company announced that it had acquired the rights to develop a salt-cavern gas storage facility located in Calcasieu Parish, Louisiana. Additional information regarding these activities is provided above in "Cash Flows From Investing Activities." The Argentine economic decline and government responses (including Argentina's unilateral, retroactive abrogation of utility agreements early in 2002) are continuing to adversely affect the company's investment in two Argentine utilities. Information regarding this situation is provided in Note 7 of the notes to Consolidated Financial Statements. 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, FIN 45 and 46, and EITF 98-10, 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. EITF Issue 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities": In accordance with the EITF's rescission of Issue 98-10 by the release of Issue 02-3, the company no longer marks to market energy-related contracts unless the contracts meet the requirements stated under SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," and SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." A substantial majority of the company's contracts do meet these requirements. Upon adoption of this consensus on January 1, 2003, the company recorded the initial effect of rescinding Issue 98-10 as a cumulative effect of a change in accounting principle, which reduced after-tax earnings by $29 million. 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 most energy utilities, including the California Utilities, 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
49 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. FIN 46, "Consolidation of Variable Interest Entities an interpretation of ARB No. 51": In January 2003, the FASB issued FIN 46 to strengthen existing accounting guidance that addresses when a company should consolidate a VIE in its financial statements. Adoption of FIN 46 on December 31, 2003 resulted in the consolidation of two VIEs for which Sempra Energy is the primary beneficiary. One of the VIEs (Mesquite Trust) was the owner of the Mesquite Power plant for which the company had a synthetic lease agreement. (The company bought out the lease in January 2004.) The other VIE relates to the investment in AEG. Sempra Energy consolidated these entities in its financial statements at December 31, 2003. During the first quarter of 2004 Sempra Energy's Board of Directors approved management's plan to dispose of AEG. Note 4 of the notes to Consolidated Financial Statements provides further discussion on this matter and the disposal of AEG's discontinued operations, which occurred in April 2004. In accordance with FIN 46, the company has deconsolidated a wholly owned subsidiary trust from its financial statements at December 31, 2003. Further discussion regarding FIN 46 is provided in Note 2 of the notes to Consolidated Financial Statements. 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. The VaR for SET at June 30, 2004, and the average VaR for the six months ended June 30, 2004, at the 95-percent and 99-percent confidence intervals (one-day holding period) were as follows (in millions of dollars): 95% 99% - ------------------------------------------------------ At June 30, 2004 $ 5.6 $ 7.9 Average for the six months ended June 30, 2004 $ 6.1 $ 8.5 - ------------------------------------------------------ As of June 30, 2004, the total VaR of the California Utilities' and SES' positions was not material.
50 ITEM 4. CONTROLS AND PROCEDURES The company has designed and maintains disclosure controls and procedures to ensure that information required to be disclosed in the company's reports under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and is accumulated and communicated to the company's management, including its Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating these controls and procedures, management recognizes that any system of controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired objectives and necessarily applies judgment in evaluating the cost-benefit relationship of other possible controls and procedures. In addition, the company has investments in unconsolidated entities that it does not control or manage and, consequently, its disclosure controls and procedures with respect to these entities are necessarily substantially more limited than those it maintains with respect to its consolidated subsidiaries. Under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer, the company 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 company's 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 On June 9, 2004, Donald E. Felsinger was named Sempra Energy's president and chief operating officer and was also elected to its board of directors. The company's succession plan contemplates that Mr. Felsinger will become chief executive officer upon Stephen L. Baum's retirement at the end of January 2006. As part of the management succession plan, executive vice president and chief financial officer, Neal Schmale, was also elected to the board of directors. The succession plan contemplates that Mr. Schmale will become chief operating officer when Mr. Felsinger becomes chief executive officer. Also on June 9, 2004, Denise K. Fletcher became a member of the board of directors. Ms. Fletcher is a director of Orbitz and Unisys Corporation. She has served as a senior vice president and chief financial officer of MasterCard International and a senior vice president and chief financial officer of Bowne & Company.
51 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 6 and 7 of the notes to Consolidated Financial Statements, neither the company nor its subsidiaries are party to, nor is their property the subject of, any material pending legal proceedings other than routine litigation incidental to their businesses. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Sempra Energy's board of directors is divided into three classes whose terms are staggered so that the term of one class expires at each Annual Meeting of Shareholders. At the annual meeting on May 4, 2004, the shareholders of Sempra Energy elected three directors for a three-year term expiring in 2007. The name of each nominee and the number of shares voted for and withheld from the election of each director were as follows: Nominees Votes For Votes Withheld Stephen L. Baum 185,453,797 12,446,837 Wilford D. Godbold, Jr. 184,841,895 13,058,739 Richard G. Newman 187,100,591 10,800,043 The results of the voting on the other proposals considered at the annual meeting were as follows: (a) management proposal for the reapproval of long-term incentive plan performance goals. In favor 166,145,134 Opposed 27,931,314 (b) management proposal for the ratification of independent auditors. In favor 187,193,487 Opposed 7,149,577 (c) shareholder proposal recommending that each director be elected annually. In favor 102,810,350 Opposed 58,380,870 (d) shareholder proposal regarding shareholder rights plan. In favor 106,527,100 Opposed 54,176,636
52 (e) shareholder proposal limiting auditor services. In favor 27,809,978 Opposed 132,792,660 (f) shareholder proposal regarding independent chairman of the board. In favor 68,124,252 Opposed 92,860,896 The two approved shareholder proposals constitute recommendations to the board of directors and will be considered by the board prior to the next annual meeting of shareholders. 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.
53 SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. SEMPRA ENERGY ------------------- (Registrant) Date: August 5, 2004 By: /s/ F. H. Ault ---------------------------- F. H. Ault Sr. Vice President and Controller
|
EXHIBIT 12.1 |
|||||||||||
|
SEMPRA ENERGY |
|||||||||||
|
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES |
|||||||||||
|
AND PREFERRED STOCK DIVIDENDS |
|||||||||||
|
(Dollars in millions) |
|||||||||||
|
Six months ended |
|||||||||||
|
1999 |
2000 |
2001 |
2002 |
2003 |
June 30, 2004 |
||||||
|
Fixed Charges and Preferred Stock Dividends: |
|||||||||||
|
Interest |
$ 233 |
$ 308 |
$ 358 |
$ 350 |
$ 351 |
$ 167 |
|||||
|
Interest portion of annual rentals |
10 |
8 |
6 |
6 |
5 |
2 |
|||||
|
Preferred dividends of subsidiaries (1) |
16 |
18 |
16 |
15 |
11 |
7 |
|||||
|
Combined fixed charges and preferred stock |
|||||||||||
|
dividends for purpose of ratio |
$ 259 |
$ 334 |
$ 380 |
$ 371 |
$ 367 |
$ 176 |
|||||
|
Earnings: |
|||||||||||
|
Pretax income from continuing operations |
$ 573 |
$ 699 |
$ 731 |
$ 721 |
$ 742 |
$ 438 |
|||||
|
Total fixed charges (from above) |
259 |
334 |
380 |
371 |
367 |
176 |
|||||
|
Less: |
|||||||||||
|
Interest capitalized |
1 |
3 |
11 |
29 |
26 |
4 |
|||||
|
Equity in income (loss) of unconsolidated |
|
||||||||||
|
subsidiaries and joint ventures |
- |
62 |
12 |
(55) |
8 |
- |
|||||
|
Total earnings for purpose of ratio |
$ 831 |
$ 968 |
$ 1,088 |
$ 1,118 |
$ 1,075 |
$ 610 |
|||||
|
Ratio of earnings to combined fixed charges |
|||||||||||
|
and preferred stock dividends |
3.21 |
2.90 |
2.86 |
3.01 |
2.93 |
3.47 |
|||||
|
(1) In computing this ratio, "Preferred dividends of subsidiaries" represents the before-tax earnings necessary to pay such dividends, |
|||||||||||
|
computed at the effective tax rates for the applicable periods. |
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EXHIBIT 31.1
CERTIFICATION
I, Stephen L. Baum, certify that:
1. I have reviewed this Quarterly Report on Form 10-Q of Sempra Energy;
2. Based on my knowledge, this Quarterly Report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect
to the period covered by this Quarterly Report;
3. Based on my knowledge, the financial statements and other financial
information included in this Quarterly Report fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented
in this Quarterly Report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the
registrant and we have:
a) Designed such disclosure controls and procedures, or caused
such disclosure controls and procedures to be designed under
our supervision, to ensure that material information relating
to the registrant, including its consolidated subsidiaries, is
made known to us by others within those entities, particularly
during the period in which this Quarterly Report is being
prepared;
b) Evaluated the effectiveness of the registrant's disclosure
controls and procedures and presented in this Quarterly Report
our conclusions about the effectiveness of the disclosure
controls and procedures, as of the end of the period covered
by this Quarterly Report, based on such evaluation; and
c) Disclosed in this report any change in the registrant's
internal control over financial reporting that occurred during
the registrant's most recent fiscal quarter that has
materially affected, or is reasonably likely to materially
affect, the registrant's internal control over financial
reporting;
5. The registrant's other certifying officer and I have disclosed,
based on our most recent evaluation of internal control over
financial reporting, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing
the equivalent function):
a) All significant deficiencies and material weaknesses in the
design or operation of internal controls over financial
reporting which are reasonably likely to adversely affect the
registrant's ability to record, process, summarize and report
financial information; and
b) Any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls over financial reporting.
August 5, 2004
/S/ STEPHEN L. BAUM
Stephen L. Baum
Chief Executive Officer
EXHIBIT 31.2
CERTIFICATION
I, Neal E. Schmale, certify that:
1. I have reviewed this Quarterly Report on Form 10-Q of Sempra Energy;
2. Based on my knowledge, this Quarterly Report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect
to the period covered by this Quarterly Report;
3. Based on my knowledge, the financial statements and other financial
information included in this Quarterly Report fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented
in this Quarterly Report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the
registrant and we have:
a) Designed such disclosure controls and procedures, or caused
such disclosure controls and procedures to be designed under
our supervision, to ensure that material information relating
to the registrant, including its consolidated subsidiaries, is
made known to us by others within those entities, particularly
during the period in which this Quarterly Report is being
prepared;
b) Evaluated the effectiveness of the registrant's disclosure
controls and procedures and presented in this Quarterly Report
our conclusions about the effectiveness of the disclosure
controls and procedures, as of the end of the period covered
by this Quarterly Report, based on such evaluation; and
c) Disclosed in this report any change in the registrant's
internal control over financial reporting that occurred during
the registrant's most recent fiscal quarter that has
materially affected, or is reasonably likely to materially
affect, the registrant's internal control over financial
reporting;
5. The registrant's other certifying officer and I have disclosed,
based on our most recent evaluation of internal control over
financial reporting, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing
the equivalent function):
a) All significant deficiencies and material weaknesses in the
design or operation of internal controls over financial
reporting which are reasonably likely to adversely affect the
registrant's ability to record, process, summarize and report
financial information; and
b) Any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls over financial reporting.
August 5, 2004
/S/ NEAL E. SCHMALE
Neal E. Schmale
Chief Financial Officer
Exhibit 32.1
Statement of Chief Executive Officer
Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the
Sarbanes-Oxley Act of 2002, the undersigned Chief Executive Officer of
Sempra Energy (the "Company") certifies that:
(i) the Quarterly Report on Form 10-Q of the Company filed with
the Securities and Exchange Commission for the quarterly
period ended 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/ STEPHEN L. BAUM
______________________
Stephen L. Baum
Chief Executive Officer
Exhibit 32.2
Statement of Chief Financial Officer
Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the
Sarbanes-Oxley Act of 2002, the undersigned Chief Financial Officer of
Sempra Energy (the "Company") certifies that:
(i) the Quarterly Report on Form 10-Q of the Company filed with
the Securities and Exchange Commission for the quarterly
period ended 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/ NEAL E. SCHMALE
______________________
Neal E. Schmale
Chief Financial Officer