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 March 31, 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 March 31, 2004: 229,757,604
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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.
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS.
SEMPRA ENERGY
STATEMENTS OF CONSOLIDATED INCOME
(Dollars in millions, except per share amounts)
Quarters ended
March 31,
------------------
2004 2003
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OPERATING REVENUES
California utilities:
Natural gas $ 1,333 $ 1,162
Electric 381 395
Other 646 366
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Total operating revenues 2,360 1,923
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OPERATING EXPENSES
California utilities:
Cost of natural gas 824 677
Cost of electric fuel and purchased power 127 163
Other cost of sales 327 219
Other operating expenses 521 445
Depreciation and amortization 165 148
Franchise fees and other taxes 64 56
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Total operating expenses 2,028 1,708
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Operating income 332 215
Other income (loss) - net 5 (2)
Interest income 23 12
Interest expense (80) (74)
Preferred dividends of subsidiaries (2) (3)
Trust preferred distributions by subsidiary -- (4)
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Income from continuing operations before income taxes 278 144
Income tax expense 57 24
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Income from continuing operations 221 120
Loss from discontinued operations, net of tax (Note 4) (24) (3)
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Income before cumulative effect of change in accounting principle 197 117
Cumulative effect of change in accounting principle,
net of tax (Note 2) -- (29)
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Net income $ 197 $ 88
======= =======
Weighted-average number of shares outstanding (thousands):
Basic 228,055 206,393
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Diluted 231,136 207,823
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Income from continuing operations per share of common stock
Basic $ 0.97 $ 0.58
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Diluted $ 0.96 $ 0.58
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Income before cumulative effect of change in accounting
principle per share of common stock
Basic $ 0.86 $ 0.57
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Diluted $ 0.85 $ 0.56
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Net income per share of common stock
Basic $ 0.86 $ 0.43
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Diluted $ 0.85 $ 0.42
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Common dividends declared per share $ 0.25 $ 0.25
======= =======
See notes to Consolidated Financial Statements.
SEMPRA ENERGY
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
--------------------------
March 31, December 31,
2004 2003
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ASSETS
Current assets:
Cash and cash equivalents $ 653 $ 432
Short-term investments -- 363
Accounts receivable - trade 715 875
Accounts and notes receivable - other 137 127
Interest receivable 65 62
Trading assets 4,997 5,250
Regulatory assets arising from fixed-price
contracts and other derivatives 145 144
Other regulatory assets 93 89
Inventories 67 147
Other 155 157
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Current assets of continuing operations 7,027 7,646
Assets of discontinued operations 245 220
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Total current assets 7,272 7,866
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Investments and other assets:
Due from affiliates 51 55
Regulatory assets arising from fixed-price
contracts and other derivatives 612 650
Other regulatory assets 531 554
Nuclear decommissioning trusts 584 570
Investments 1,109 1,114
Sundry 699 706
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Total investments and other assets 3,586 3,649
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Property, plant and equipment:
Property, plant and equipment 15,491 15,317
Less accumulated depreciation and amortization (4,941) (4,843)
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Property, plant and equipment - net 10,550 10,474
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Total assets $21,408 $21,989
======= =======
See notes to Consolidated Financial Statements.
SEMPRA ENERGY
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
--------------------------
March 31, December 31,
2004 2003
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LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Short-term debt $ 139 $ 28
Accounts payable - trade 647 779
Accounts payable - other 59 64
Income taxes payable 142 47
Deferred income taxes 78 88
Trading liabilities 4,401 4,457
Dividends and interest payable 128 136
Regulatory balancing accounts - net 527 424
Fixed-price contracts and other derivatives 153 148
Current portion of long-term debt 610 1,433
Other 771 704
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Current liabilities of continuing operations 7,655 8,308
Liabilities of discontinued operations 45 52
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Total current liabilities 7,700 8,360
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Long-term debt 3,822 3,841
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Deferred credits and other liabilities:
Due to affiliates 362 362
Customer advances for construction 81 89
Postretirement benefits other than pensions 123 131
Deferred income taxes 193 257
Deferred investment tax credits 82 84
Regulatory liabilities arising from cost
of removal obligations 2,268 2,238
Regulatory liabilities arising from asset
retirement obligations 299 281
Other regulatory liabilities 108 108
Fixed-price contracts and other derivatives 612 680
Asset retirement obligations 315 313
Deferred credits and other 1,176 1,176
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Total deferred credits and other liabilities 5,619 5,719
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Preferred stock of subsidiaries 179 179
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Commitments and contingent liabilities (Note 7)
SHAREHOLDERS' EQUITY
Preferred stock (50 million shares authorized,
none issued) -- --
Common stock (750 million shares authorized;
230 million and 227 million shares outstanding at
March 31, 2004 and December 31, 2003, respectively) 2,087 2,028
Retained earnings 2,438 2,298
Deferred compensation relating to ESOP (35) (35)
Accumulated other comprehensive income (loss) (402) (401)
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Total shareholders' equity 4,088 3,890
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Total liabilities and shareholders' equity $21,408 $21,989
======= =======
See notes to Consolidated Financial Statements.
SEMPRA ENERGY
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in millions)
Quarters ended
March 31,
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2004 2003
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CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 197 $ 88
Adjustments to reconcile net income to net cash
provided by operating activities:
Loss from discontinued operations 24 3
Cumulative effect of change in accounting principle -- 29
Depreciation and amortization 165 148
Deferred income taxes and investment tax credits (22) (32)
Other - net 16 23
Net changes in other working capital components 427 431
Changes in other assets (12) (5)
Changes in other liabilities (13) 6
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Net cash provided by operating activities 782 691
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CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment (219) (193)
Net proceeds from sale of short-term investments 363 --
Investments and acquisitions of subsidiaries,
net of cash acquired (7) (80)
Dividends received from affiliates 10 --
Loans to affiliate -- (46)
Other - net 2 --
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Net cash provided by (used in) investing activities 149 (319)
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CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid (57) (52)
Issuances of common stock 55 19
Repurchases of common stock (2) (3)
Issuances of long-term debt 21 400
Payments on long-term debt (857) (224)
Increase (decrease) in short-term debt - net 134 (158)
Other - net (2) (6)
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Net cash used in financing activities (708) (24)
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Increase in cash from continuing operations 223 348
Cash used in discontinued operations (2) --
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Increase in cash and cash equivalents 221 348
Cash and cash equivalents, January 1 432 455
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Cash and cash equivalents, March 31 $ 653 $ 803
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SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized $ 85 $ 74
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Income tax payments, net of refunds $ 29 $ 20
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See notes to Consolidated Financial Statements.
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).
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 March 31, 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."
NOTE 2. NEW ACCOUNTING STANDARDS
Stock-Based Compensation: On March 31, 2004, the Financial Accounting
Standards Board (FASB) issued a proposed Exposure Draft to amend SFAS
123, "Accounting for Stock-Based Compensation" and SFAS 95, "Statement
of Cash Flows" which provide the current guidance on accounting for
stock options and related items. It proposes that the new rules would
be effective for 2005. The proposed statement would eliminate the
choice of accounting for share-based compensation transactions using
Accounting Principles Board Opinion No. 25, "Accounting for Stock
Issued to Employees," and instead generally would require that such
transactions be accounted for using a fair-value-based method. The
Draft would prohibit retroactive application and require that expense
be recognized only for those options that actually vest.
The following table provides the pro forma effects that would have
resulted if stock options were expensed.
Quarters ended
March 31,
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(Dollars in millions,
except for per share amounts) 2004 2003
- --------------------------------------------------------------------
Net income as reported $ 197 $ 88
Stock-based employee compensation expense
reported in net income, net of tax 5 7
Total stock-based employee compensation
under fair value method for all awards,
net of tax (6) (9)
---------------------
Pro forma net income $ 196 $ 86
=====================
Earnings per share:
Basic--as reported $ 0.86 $ 0.43
=====================
Basic--pro forma $ 0.86 $ 0.42
=====================
Diluted--as reported $ 0.85 $ 0.42
=====================
Diluted--pro forma $ 0.85 $ 0.41
=====================
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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.
It requires disclosures beyond those in the original SFAS 132 about the
assets, obligations, cash flows and net periodic benefit cost of
defined benefit pension plans and other defined postretirement plans.
In addition, the revised statement 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
quarters ended March 31:
Other
Pension Benefits Postretirement Benefits
--------------------------------------------
(Dollars in millions) 2004 2003 2004 2003
- -------------------------------------------------------------------------------
Service cost $ 13 $ 16 $ 6 $ 4
Interest cost 38 37 14 13
Expected return on assets (38) (40) (9) (9)
Amortization of:
Transition obligation -- -- 2 2
Prior service cost 2 2 -- --
Actuarial loss 3 2 3 2
Regulatory adjustment (8) (5) (1) 1
--------------------------------------------
Total net periodic benefit cost $ 10 $ 12 $ 15 $ 13
- -------------------------------------------------------------------------------
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 quarter
ended March 31, 2004, $1 million and $14 million of contributions have
been made to its pension plans and other postretirement benefit plans,
respectively.
SFAS 143, "Accounting for Asset Retirement Obligations": SFAS 143
requires entities to record the fair value of liabilities for legal
obligations related to asset retirements in the period in which they
are incurred. It also requires the reclassification of estimated
removal costs, which have historically been recorded in accumulated
depreciation, to a regulatory liability. At March 31, 2004 and December
31, 2003, the estimated removal costs recorded as a regulatory
liability were $1.4 billion at both dates for SoCalGas and $857 million
and $846 million, respectively, for SDG&E.
The change in the asset retirement obligations for the quarter ended
March 31, 2004 is as follows (dollars in millions):
Balance as of January 1, 2004 $ 337
Accretion expense 6
Payments (3)
------
Balance as of March 31, 2004 $ 340*
======
* The current portion of the obligation is included in Other Current
Liabilities on the Consolidated Balance Sheets.
SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities": Effective July 1, 2003, SFAS 149 amended and
clarified accounting for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging
activities under SFAS 133. Under SFAS 149 natural gas forward contracts
that are subject to unplanned netting generally do not qualify for the
normal purchases and normal sales exception. ("Netting" refers to
contract settlement by paying or receiving the monetary difference
between the contract price and the market price at the date on which
physical delivery would have occurred.) In addition, effective January
1, 2004, power contracts that are subject to unplanned netting and that
do not meet the normal purchases and normal sales exception under SFAS
149 will continue to be marked to market. Implementation of SFAS 149
did not have a material impact on reported net income. Additional
information on derivative instruments is provided in Note 5.
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 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 recognizes energy-related contracts
under mark-to-market accounting unless the contracts meet the
requirements stated under SFAS 133 and SFAS 149, which is the case for
a substantial majority of the company's contracts. 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.
EITF 03-11, "Reporting Realized Gains and Losses on Derivative
Instruments that are Subject to FASB Statement No. 133, Accounting for
Derivative Instruments and Hedging Activities and Not 'Held for Trading
Purposes' as Defined in EITF Issue No. 02-3, Issues Involved in
Accounting for Derivative Contracts Held for Trading Purposes and
Contracts Involved in Energy Trading and Risk Management Activities":
During 2003, the EITF reached a consensus that determining whether
realized gains and losses on physically settled derivative contracts
not held for trading purposes should be reported in the income
statement on a gross or net basis is a matter of judgment that depends
on the relevant facts and circumstances. Adoption of EITF 03-11 in 2003
did not have and is not expected to have a significant impact on the
company's financial statements.
FASB Interpretation No. (FIN) 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees": As of March 31, 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. During December 2003, the FASB issued FIN 46
revised (FIN 46R) to defer the implementation date for pre-existing
variable interest entities (VIEs) that are special purpose entities
(SPEs) until the end of the first interim or annual period ending after
December 15, 2003. For VIEs that are not SPEs, companies must apply FIN
46R no later than the end of the first reporting period ending after
March 15, 2004.
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), which is an SPE, was the owner of the
Mesquite Power plant for which the company had a synthetic lease
agreement, as described in Notes 2 and 5 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 became
fully operational in December 2003. The company recorded an after-tax
credit of $9 million in 2003 for the cumulative effect from the change
in accounting principle. The company bought out the lease in January
2004.
The other variable interest entity is Atlantic Electric & Gas (AEG),
which markets 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 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 sale of AEG.
In accordance with FIN 46R, the company also 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. SDG&E is in
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, "Accounting and Disclosure
Requirements Related to the Medicare Prescription Drug, Improvement and
Modernization Act of 2003": Issued January 12, 2004, FSP 106-1 permits
a sponsor of a postretirement health care plan that provides a
prescription drug benefit to make a one-time election to defer
accounting for the effects of the Medicare Prescription Drug,
Improvement and Modernization Act of 2003 (the Act). The company has
elected to defer the effects of the Act as provided by FSP 106-1 until
authoritative guidance on the accounting for the federal subsidy is
issued. Any measure of the accumulated postretirement benefit
obligation or net periodic postretirement benefit cost in the financial
statements or the accompanying notes does not reflect the impact of the
Act on the plans. At this time, specific authoritative guidance on the
accounting for the federal subsidy provided by the Act is pending and
that guidance could require the company to change previously reported
information.
NOTE 3. COMPREHENSIVE INCOME
The following is a reconciliation of net income to comprehensive
income.
Quarters
ended
March 31,
---------------
(Dollars in millions) 2004 2003
- -----------------------------------------------
Net income $ 197 $ 88
Foreign currency adjustments 4 14
Financial instruments (Note 5) (5) --
Minimum pension liability
adjustments -- (6)
---------------
Comprehensive income $ 196 $ 96
- -----------------------------------------------
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 meets 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, the company entered into an agreement to sell AEG for a
sales price of $162 million.
The net losses from discontinued operations were $24 million for the
first quarter of 2004 ($0.10 per basic and diluted share) and $3
million for the first quarter of 2003 ($0.01 per basic and diluted
share). Included within the net loss from discontinued operations are
AEG's operating results, summarized below:
Quarters ended
March 31,
---------------------------
(Dollars in millions) 2004 2003
- ---------------------------------------------------------------------
Operating revenues $ 168 $ 108 *
Loss from discontinued operations
before income taxes $ (23) $ (3)*
- ---------------------------------------------------------------------
* During 2003, the company accounted for its investment in AEG
under the equity method of accounting. As such, the company
recorded its share of AEG's net loss as a $3 million loss in
Other Income - Net on the Statements of Consolidated Income.
Effective December 31, 2003, AEG was consolidated as a result of
the adoption of FIN 46. This is discussed further in the Annual
Report.
AEG's balance sheet data, excluding intercompany balances (which are
significant) eliminated in consolidation, are summarized below:
March 31, December 31,
(Dollars in millions) 2004 2003
- ---------------------------------------------------------------------
Assets:
Accounts receivable, net $ 160 $ 137
Other current assets 85 83
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Total assets $ 245 $ 220
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Liabilities:
Accounts payable $ 29 $ 36
Other current liabilities 16 16
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Total liabilities $ 45 $ 52
- ---------------------------------------------------------------------
NOTE 5. FINANCIAL INSTRUMENTS
As described in Note 10 of the notes to Consolidated Financial
Statements in the Annual Report, the company follows the guidance of
SFAS 133 as amended by SFAS 138 and 149 (collectively SFAS 133) to
account for its derivative instruments and hedging activities.
Derivative instruments and related hedges are recognized as either
assets or liabilities on the balance sheet, measured at fair value.
Changes in the fair value of derivatives are recognized in earnings in
the period of change unless the derivative qualifies as an effective
hedge that offsets certain exposure, except at the California
Utilities, where such changes are balanced in the ratemaking process.
SFAS 133 provides for hedge accounting treatment when certain criteria
are met. For derivative instruments designated as fair value hedges,
the gain or loss is recognized in earnings in the period of change
together with the offsetting gain or loss on the hedged item
attributable to the risk being hedged. For derivative instruments
designated as cash flow hedges, the effective portion of the derivative
gain or loss is included in other comprehensive income, but not
reflected in the Statements of Consolidated Income until the
corresponding hedged transaction is settled. The ineffective portion is
reported in earnings immediately.
The company utilizes 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. The company
classifies its forward contracts as follows:
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 recoverable through 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. When 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 quarter ended March 31, 2004 were
primarily due to the settlement of the contingent purchase price
obligation arising from the company's acquisition of the proposed
Cameron LNG project and the physical deliveries under long-term
purchased-power and natural gas transportation contracts.
For the quarter ended March 31, 2004, pre-tax income from transactions
associated with fixed-price contracts and other derivatives included
$13 million for the settlement of the Cameron contingency. The
transactions associated with fixed-price contracts and other
derivatives had no material impact to the Statements of Consolidated
Income for the quarter ended March 31, 2003.
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
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 exchange quotations. Commodity swaps and forward
transactions are accounted for as contractual commitments on a trade-
date basis and are carried at fair value derived from dealer quotations
and underlying commodity exchange quotations. OTC options 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 Accounting Research Bulletin 43,
"Restatement and Revision of Accounting Research Bulletins."
The carrying values of SET's trading assets and trading liabilities
approximate the following:
March 31, December 31,
(Dollars in millions) 2004 2003
- --------------------------------------------------------------------------
Trading Assets
Unrealized gains on swaps and forwards $ 1,193 $ 1,043
OTC commodity options purchased 573 459
Due from trading counterparties 1,817 2,183
Due from commodity clearing organizations
and clearing brokers 106 134
Resale agreements 7 1
Commodities owned 1,348 1,420
------- -------
Total $ 5,044 $ 5,240
======= =======
- --------------------------------------------------------------------------
Trading Liabilities
Unrealized losses on swaps and forwards $ 1,136 $ 1,095
OTC commodity options written 303 226
Due to trading counterparties 2,090 2,195
Repurchase obligations 854 866
Commodities not yet purchased -- 56
------- -------
Total $ 4,383 $ 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 March
31, 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.
The following table summarizes the counterparty credit quality and
exposure for SET at March 31, 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 $572 million
and $569 million at March 31, 2004 and December 31, 2003, respectively.
March 31, December 31,
(Dollars in millions) 2004 2003
- ----------------------------------------------------------------------------
Counterparty credit quality*
Commodity exchanges $ 106 $ 134
AAA 3 5
AA 240 310
A 416 463
BBB 464 345
Below investment grade 553 357
------- -------
Total $ 1,782 $ 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 backgrounds of these issues are 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.
SDG&E's 20-year resource plan identifies the near-term need for
capacity resources within its service territory to support transmission
grid reliability. An updated long-term resource plan will be filed
during the summer of 2004 in a CPUC proceeding which will consider
utility resource planning, such as energy efficiency, contracted power,
demand response, qualifying facilities, renewable generation and
distributed generation. However, in order to satisfy SDG&E's recognized
near-term need for grid reliability capacity, in May 2003 SDG&E issued
a Request for Proposals (RFP) for the years 2005-2007 for 69 megawatts
(MW) in 2005 increasing to 291 MWs in 2007.
As a result of its RFP, in October 2003, SDG&E filed a motion
requesting CPUC authorization to enter into five new electric resource
contracts (including two under which SDG&E would take ownership of new
generating assets, one of which is being developed by SER), as more
fully described in the Annual Report. Hearings concluded on February
20, 2004. Two draft decisions were issued on April 6, 2004, one by the
Administrative Law Judge (ALJ) and an Alternate Draft by the Assigned
Commissioner. Both draft decisions would approve all five proposed
contracts. The Assigned Commissioner's Alternate Draft would also grant
SDG&E's cost recovery, ratemaking and revenue requirement proposals for
the proposed resources, including a return on equity (ROE) for SDG&E's
new generation investments that is 50-basis points higher than SDG&E's
ROE on distribution assets, an equity offset for the debt equivalency
of purchase power contracts, and an equity buildup for construction.
The CPUC may adopt all or part of the proposed decisions as written, or
amend or modify them. Only when the CPUC acts does a decision become
binding and final. The CPUC is expected to issue a final decision in
the late spring of 2004. Given the CPUC's prior denial of the company's
request for approval of additional transmission facilities, the company
believes that customer requirements for electricity could not be met
without the requested resources or similar additions.
NATURAL GAS INDUSTRY RESTRUCTURING
As discussed in the Annual Report, in December 2001 the CPUC issued a
decision related to natural gas industry restructuring (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)
(see below). At that time, the CPUC will reconcile the GIR market
structure with whatever structure results from the Phase I decision of
the 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 throughput. The decision would create firm tradable rights
for the transmissions system. Other noncore costs/revenues would
continue to be fully balanced until the decision in the next Biennial
Cost Allocation Proceeding (BCAP) (see below).
NATURAL GAS MARKET OIR
The 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 summer 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 2006 to 2016. Since GIR (see above)
would end in August 2006 and there is overlap between GIR and the Gas
OIR issues, a number of parties (including SoCalGas) advised the CPUC
not to implement GIR.
The California Utilities have made comprehensive filings in the Gas 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 rate base. The estimated costs of these system
enhancements to access as much as 2 billion cubic feet per day of new
supplies are $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. They expect to
receive a CPUC decision approving a methodology during the third
quarter of 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 $121
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 likely in the second quarter of
2004. 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 are recognizing revenues consistent with the proposed
settlements.
SDG&E is also awaiting the CPUC decision on the Cost of Service
application of Southern California Edison (Edison). This decision will
set rates for San Onofre Nuclear Generating Station (SONGS), 20 percent
of which is owned by SDG&E. As discussed in the Annual Report, SDG&E's
SONGS ratebase restarted at $0 on January 1, 2004 and, therefore,
SDG&E's earnings from SONGS will generally be limited to a return on
new capital additions. Edison has applied for permission to replace
SONGS' steam generator, which would increase the total cost of SONGS by
an estimated $800 million ($160 million for SDG&E). SDG&E has raised
objections at the CPUC and at the San Diego Superior Court, intended to
compel Edison to declare an operating impairment as the basis for the
expenditure. Under the terms of the ownership agreement, determination
that an operating impairment exists will allow SDG&E to not participate
in the project, which would proceed without SDG&E, and SDG&E's
ownership percentage in SONGS would be reduced. A pre-hearing
conference is scheduled for May 18, 2004.
The California Utilities have also filed for continuation through 2004
of existing performance-based regulation (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 deferred action on applying any
rewards or penalties for performance relative to these targets to a
decision to be issued later in 2004 in a second phase of these
applications. On April 2, 2004, the CPUC's Office of Ratepayers
Advocates (ORA) filed its report recommending that a Consumer Price
Index with no productivity factor or customer growth factor be used to
change the California Utilities' base margin, as opposed to the
proposed Margin per Customer proposal of the California Utilities, and
that the pending decision be in effect for five years. The ORA also
proposed the possibility of performance penalties, without the
possibility of performance awards. Hearings are scheduled for June 2004
with a final decision expected by November 2004.
PERFORMANCE-BASED REGULATION
To promote efficient operations and improved productivity and to move
away from reasonableness reviews and disallowances, the CPUC adopted
PBR for SDG&E effective in 1994 and for SoCalGas effective in 1997. As
further described in the Annual Report, under PBR, regulators require
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 quarter of 2004 was
$6.3 million related to SoCalGas' Year 9 GCIM, which was approved on
February 26, 2004. This reward is subject to refund based on the
outcome of the Border Price Investigation described below. The
cumulative amount of rewards so subject is $61.2 million at March 31,
2004.
At March 31, 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* $ 9.8 $ 35.6 $ 45.4
2003 Distribution PBR -- 8.2 8.2
GCIM/natural gas PBR -- 1.9** 1.9
2003 safety .5 -- .5
- -----------------------------------------------------------
Total $ 10.3 $ 45.7 $ 56.0
- -----------------------------------------------------------
* Dollar amounts shown do not include interest, franchise fees or
uncollectible amounts.
**On March 15, 2004, the ORA recommended a modified reward of
$1.5 million.
COST OF CAPITAL
Effective January 1, 2003, SoCalGas' authorized rate of return on
common equity (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 discussed
below. As discussed in the Annual Report, these rates will continue to
be effective until market interest-rate changes are large enough to
trigger an automatic adjustment or until the CPUC orders a periodic
review. In SDG&E's case, the double-A utility bond yield 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 double-A utility bond yield averaged 6.30 percent
during the first three weeks of April 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 4.93 percent at March 31, 2004. It would
have to exceed 6.88 percent or fall below 3.88 percent for an automatic
adjustment to occur.
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," the ALJ in the 2005
BCAP issued a ruling suspending the BCAP schedule pending CPUC
dismissal of the applications. It is not known at this time when the
California Utilities would be required to file new BCAP applications.
As a result of the deferrals 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 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 are scheduled to begin on June
14, 2004. At a later date, the CPUC will hold a second round of
hearings to consider whether Sempra Energy or any of its non-utility
subsidiaries contributed to the price spikes. 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 recently filed testimony supporting the GCIM and
the actions of SoCalGas during this period.
CPUC INVESTIGATION OF COMPLIANCE WITH AFFILIATE RULES
In February 2003, the CPUC opened an investigation of the business
activities of SDG&E, SoCalGas and Sempra Energy to determine if they
have complied with statutes and CPUC decisions in the management,
oversight and operations of their companies. In September 2003, the
CPUC suspended the procedural schedule until it completes an
independent audit to evaluate energy-related holding company systems
and affiliate activities undertaken by Sempra Energy within the service
territories of SDG&E and SoCalGas. The audit, covering years 1997
through 2003, is expected to be completed by March 2005. The scope of
the audit will be broader than the annual affiliate audit. In
accordance with existing CPUC requirements, the California Utilities'
transactions with other Sempra Energy affiliates have been audited by
an independent auditing firm each year, with results reported to the
CPUC, and there have been no material adverse findings in those audits.
CPUC INVESTIGATION OF ENERGY-UTILITY HOLDING COMPANIES
The CPUC has initiated an investigation into the relationship between
California's investor-owned utilities (IOUs) and their parent holding
companies. The CPUC broadly determined that it would 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. The company's request for rehearing on the issues
was denied by the CPUC and the company subsequently filed appeals in
the California Court of Appeal. Oral argument was held on March 5, 2004
before the First District Court of Appeal and a written opinion from
the Court is expected by June 2004.
RECOVERY OF CERTAIN DISALLOWED TRANSMISSION COSTS
In August 2002 the Federal Energy Regulatory Commission (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. On November 17, 2003, SDG&E petitioned
the United States Court of Appeals for review of this FERC order and
argued that the disallowed costs should be allowed for recovery through
the Transmission Revenue Balancing Account Adjustment. On February 12,
2004, on the FERC's motion, the court remanded the case back to the
FERC for further consideration, "based on the FERC's representation
that it intends to act expeditiously on remand." The FERC has not yet
issued further orders in this matter.
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 shares of the SWPL. On October 23, 2003, 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 services giving rise to
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.
In addition, on January 23, 2004, the FERC denied rehearing of its
Opinion No. 463, which upheld the ISO's grid management charges billed
to SDG&E for the APS and IID SWPL energy schedules. This rehearing
order did require the ISO to refund amounts of such charges covered by
SDG&E self-supply of imbalance energy. Pursuant to this order, the ISO
issued its refund report on February 23, 2004, calculating the refunds
due SDG&E at $320,000. On March 15, 2004, SDG&E protested the ISO's
refund report, claiming refunds of $3.3 million, before interest. A
FERC decision on the refunds is expected later in 2004. In addition, on
March 22, 2004, SDG&E petitioned the United States Court of Appeals for
review of these FERC orders and will argue that the ISO lacks authority
under its tariff to assess grid management charges on the subject SWPL
schedules. The court has not yet scheduled briefing or argument in this
matter.
FERC ACTIONS
DWR Contract
On June 25, 2003, the FERC issued orders upholding the company's long-
term energy supply contract with the DWR, as well as contracts between
the DWR and other power suppliers. The order affirmed a previous FERC
conclusion that those advocating termination or alteration of the
contract would have to satisfy a "heavy" burden of proof, and cited its
long-standing policy to recognize the sanctity of contracts. In the
order, the FERC noted that FERC and court precedent clearly establish
that allegations that contracts have become uneconomic by the passage
of time do not render them contrary to the public interest under the
Federal Power Act. The FERC pointed out that the contracts were entered
into voluntarily in a market-based environment. The FERC found no
evidence of unfairness, bad faith or duress in the original contract
negotiations. It said there was no credible evidence that the contracts
placed the complainants in financial distress or that ratepayers will
bear an excessive burden. In December 2003, appeals of this matter
filed by a number of parties, including the California Energy Oversight
Board and the CPUC, were consolidated and assigned to the Ninth Circuit
Court of Appeals (the Court). The company expects that the Court will
affirm the FERC decision. Information regarding court proceedings and
arbitration involving this contract is included under "Litigation"
below.
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).
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 largely adopted the ALJ's
findings, but expanded the basis for refunds by adopting a staff
recommendation from a separate investigation to change the natural gas
proxy component of the mitigated market clearing price that is used to
calculate refunds. 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.
SET had established reserves of $29 million for its likely share of the
original $1.8 billion. SET is unable to determine its possible share of
the additional refund amount. Accordingly, it has not recorded any
additional reserves but the company does not believe that any
additional amounts that SET may be required to pay would be material to
the company's financial position or liquidity.
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
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. The entire amount has been recorded as of
December 31, 2003. The entire proceeding, including the settlement, is
subject to final approval by the FERC, which is expected later in 2004.
SDG&E and the FERC resolved the matter by SDG&E's paying $28 thousand
into a FERC-established fund.
On June 25, 2003, the FERC also determined that it was appropriate to
initiate an investigation into possible physical and economic
withholding in the California ISO and PX markets. 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,
2001. Both SDG&E and SET have received data requests from the FERC
staff and have provided responses. The FERC staff will prepare a report
to the FERC, which will be the basis to decide whether additional
proceedings are warranted. SET and SDG&E believe that their bids and
bidding procedures were consistent with ISO and PX tariffs and
protocols and applicable FERC price caps. 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.
NOTE 7. CONTINGENCIES
NUCLEAR INSURANCE
SDG&E and the other owners of SONGS have insurance to respond to
nuclear liability claims related to SONGS. The insurance policy
provides $300 million in coverage, which is the maximum amount
available. In addition to this primary financial protection, the Price-
Anderson Act provides for up to $10.5 billion of secondary financial
protection if the liability loss exceeds the insurance limit. Should
any of the licensed/commercial reactors in the United States experience
a nuclear liability loss which exceeds the $300 million insurance
limit, all utilities owning nuclear reactors could be assessed under
the Price-Anderson Act to provide the secondary financial protection.
SDG&E and the other co-owners of SONGS could be assessed up to $201
million under the Price-Anderson Act. SDG&E's share would be $40
million unless a default was to occur by any other SONGS owner. In the
event the secondary financial protection limit were insufficient to
cover the liability loss, the Price-Anderson Act provides for Congress
to enact further revenue-raising measures to pay claims. These measures
could include an additional assessment on all licensed reactor
operators.
SDG&E and the other owners of SONGS have $2.75 billion of nuclear
property, decontamination and debris removal insurance. The coverage
also provides the SONGS owners up to $490 million for outage
expenses/replacement power incurred because of accidental property
damage. This coverage is limited to $3.5 million per week for the first
52 weeks, and $2.8 million per week for up to 110 additional weeks.
There is a deductible waiting period of 12 weeks prior to receiving
indemnity payments. The insurance is provided through a mutual
insurance company owned by utilities with nuclear facilities. Under the
policy's risk sharing arrangements, insured members are subject to
retrospective premium assessments if losses at any covered facility
exceed the insurance company's surplus and reinsurance funds. Should
there be a retrospective premium call, SDG&E could be assessed up to
$8.5 million.
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.
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 had reduced the
carrying value of its investment downward by a cumulative total $194
million as of March 31, 2004, ($197 million as of 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 early 2005 on SEI's arbitration proceedings
under the 1994 Bilateral Investment Treaty between the United States
and Argentina for recovery of the diminution of the value of its
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 sometime 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. In
February 2004, the DWR commenced an arbitration proceeding, disputing
SER's performance on four operational matters. On April 20, 2004, SER
filed a motion for a preliminary injunction to stay arbitration of
three of the matters. Among other proposed remedies, the DWR has
requested a declaration by the arbitration panel that SER's
performance on certain of these issues 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
additional issues not applicable to Sempra Energy, SoCalGas or SDG&E)
announced that they had reached a $1.5 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, is currently in discovery and continues to be litigated.
Natural Gas Cases: Similar lawsuits have been filed by the Attorneys
General of Arizona and Nevada, alleging that El Paso and certain Sempra
Energy subsidiaries unlawfully sought to control the natural gas market
in their respective states. In October 2003, the Nevada state court
denied defendants' motion to dismiss the complaint. On April 12, 2004,
the Sempra Energy defendants filed a motion for reconsideration. In
April 2003, Sierra Pacific Resources and its utility subsidiary Nevada
Power filed a lawsuit in U.S. District Court in Las Vegas against major
natural gas suppliers, including Sempra Energy, the California
Utilities and other company subsidiaries, seeking damages resulting
from an alleged conspiracy to drive up or control natural gas prices,
eliminate competition and increase market volatility, breach of
contract and wire fraud. On January 27, 2004, the U.S. District Court
dismissed the Sierra Pacific Resources case against all of the
defendants, determining that this is a matter for the FERC. Plaintiffs
have asked the court to reconsider its decision.
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 applicable 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 has
been appealed in the Ninth Circuit Court of Appeals. Oral argument has
not yet been scheduled by the Court. In addition, in May 2003, the Port
of Seattle filed an action alleging that a number of energy companies,
including Sempra Energy, SER and SET, unlawfully manipulated the
electric energy market and committed wire fraud. That action has been
transferred to San Diego Federal District Court and is currently
pending a Court-decision on defendants' motion to dismiss 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.
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 has
filed an appeal in the Ninth Circuit of Appeals. The matter was argued
before the Ninth Circuit Court in October 2003. No decision has yet
been rendered.
Price Reporting Practices
In the fourth quarter of 2002, Sempra Energy and SoCalGas were named as
defendants in a lawsuit filed in Los Angeles Superior Court 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. On July
8, 2003, the Superior Court granted the defendants' demurrer 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.
Plaintiffs filed an amended complaint, and in September 2003 defendants
filed a demurrer to the amended complaint, which was granted in part.
In December 2003, the plaintiffs dismissed both Sempra Energy and
SoCalGas from the lawsuit. In May 2003 and again in February 2004,
similar actions 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. 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 to natural gas trade publications. In
November of 2003, another suit containing identical allegations was
filed and consolidated with the New York action. In December 2003,
plaintiffs dismissed Sempra Energy from these cases and in January
2004, SES was also dismissed. 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
On August 21, 2003, the CPUC denied a rehearing requested by opponents
of its December 2002 decision that had approved a settlement with SDG&E
allocating between SDG&E customers and shareholders the profits from
intermediate-term purchase power contracts that SDG&E had entered into
during the early stages of California's electric utility industry
restructuring. As previously reported, the settlement provided $199
million of these profits to customers, by reductions to balancing
account undercollections in prior years. The settlement provided the
remaining $173 million of profits to SDG&E shareholders, of which $57
million had been recognized for financial reporting purposes in prior
years. As a result of the decision, SDG&E recognized additional after-
tax income of $65 million in the third quarter of 2003. The Utility
Consumers' Action Network, a consumer-advocacy group which had requested
the CPUC rehearing, appealed the decision to the California Court of
Appeals and the court agreed to hear the case. Oral argument has not yet
been scheduled by the Court. The company expects that the Court of
Appeals will affirm the CPUC's decision.
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 has until May 15, 2004, to demonstrate why the court
should not set aside the permits.
In 1999, Sempra Energy and PSEG each acquired a 44-percent interest in
Luz Del Sur, a Peruvian electric distribution company. Local law
required that assets built with government funds be purchased by the
local utility and added to rate base. A dispute arose between the
government and Luz Del Sur over the amount of compensation due for the
194 projects transferred to Luz Del Sur by the government. The
government claims the amount owed was $36 million. Luz Del Sur argued
that the amount was less and the matter was settled with the government
for approximately $10 million. Following a change in the Peruvian
government, a criminal charge was filed against certain government
officials, and utility officials as accomplices, including the chief
executive officer and chief financial officer of Luz Del Sur, alleging
that the settlements were inadequate. In September 2003 a Peruvian
court ordered the prosecutor's case to be dismissed. Although the
prosecutor has indicated no evidence of wrongdoing in the case, the
prosecutor has appealed this decision and the case rests in a higher
Peruvian court. A decision is expected during the first half of 2004.
At March 31, 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 the resolution of the
financial difficulties experienced by Pacific Gas & Electric and the PX
as a result of the California electric industry crisis. SET has
submitted relevant claims in the PG&E and PX bankruptcy proceedings.
The company believes adequate reserves have been recorded.
INCOME TAX ISSUES
Section 29 Income Tax Credits
In 2003 the Internal Revenue Service (IRS) issued Announcement 2003-46,
stating it has reason to question the scientific validity of testing
procedures and results related to Section 29 income tax credits. The
notice also announced that it would suspend the issuance of new rulings
until its review is complete and that rulings could be revoked if the
IRS did not determine that the test procedures demonstrate a
significant chemical change between the feedstock coal and the
synthetic fuel. The IRS completed its review and on October 29, 2003,
announced that it would again be issuing private letter rulings based
on the previous requirements. Many such rulings have been issued since
that date, including one involving operations owned by the company. The
Permanent Subcommittee on Investigations of the U.S. Senate's Committee
on Governmental Affairs has initiated an investigation on the subject
of these income tax credits. In January 2004, the company received a
letter from the Committee requesting certain information about its
synthetic fuel operations and it is in the process of responding to
this inquiry.
As part of its audit program for the company for the period 1998-2001,
the IRS is nearing completion of examinations of SET's and SEF's credits
and the company believes the credits will be sustained. 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 $24 million for the
quarter ended March 31, 2004. The company believes disallowance of
Section 29 income tax credits generated during tax years not currently
under audit 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.
California utility transactions are based on rates set by the CPUC and
FERC. There were no significant changes in segment assets during the
quarter ended March 31, 2004.
- -------------------------------------------------------------
Quarters ended
March 31,
----------------------
(Dollars in millions) 2004 2003
- -------------------------------------------------------------
Operating Revenues:
Southern California Gas Company $ 1,148 $ 1,008
San Diego Gas & Electric 580 562
Sempra Energy Trading 301 223
Sempra Energy Resources 277 90
All other 68 50
Intersegment revenues (14) (10)
----------------------
Total $ 2,360 $ 1,923
- -------------------------------------------------------------
Net Income (Loss):
Southern California Gas Company $ 56 $ 58
San Diego Gas & Electric* 50 45
Sempra Energy Trading 59 (18)
Sempra Energy Resources 37 10
All other (5) (7)
----------------------
Total $ 197 $ 88
- -------------------------------------------------------------
* after preferred dividends
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
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
(Global).
RESULTS OF OPERATIONS
Net income and operating income for the quarter were up substantially
over the first quarter of 2003. The following table summarizes the
major factors affecting the comparisons for the two quarters.
Net Operating
(Dollars in millions) Income Income
- -------------------------------------------------------------------
2003 Quarter $ 88 $ 215
Change in accounting principle in 2003 29 --
Loss from discontinued operations in 2003 3 --
SONGS incentive pricing (ended 12/31/03) (12) (20)
-----------------------
108 195
Gain on settlement of Cameron
liability in 2004 8 13
Loss from discontinued operations in 2004 (24) --
Operations (2004 compared to 2003) 105 124
-----------------------
2004 Quarter $ 197 $ 332
- -------------------------------------------------------------------
California Utility Revenues and Cost of Sales.
Natural gas revenues increased to $1.3 billion in 2004 from $1.2
billion in 2003, and the cost of natural gas distributed increased to
$824 million in 2004 from $677 million in 2003. These changes were
primarily attributable to natural gas cost increases, which are passed
on to customers, and increased 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' Gas Cost Incentive Mechanism (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 Performance-
Based Regulation (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 decreased to $381 million in 2004 from $395 million
in 2003, and the cost of electric fuel and purchased power decreased to
$127 million in 2004 from $163 million in 2003. These changes were
mainly due to decreases in electric commodity costs partially offset by
higher volumes. Under the current regulatory framework, changes in
commodity costs normally do not affect net income. During 2004 and
2003, revenues and costs associated with long-term contracts allocated
to SDG&E from the DWR were not included in the income statement, since
the DWR retains legal and financial responsibility for these contracts.
The tables below summarize the natural gas and electric volumes and
revenues by customer class for the quarters ended March 31, 2004 and
2003.
Gas Sales, Transportation and Exchange
(Volumes in billion cubic feet, dollars in millions)
Transportation
Gas Sales & Exchange Total
----------------------------------------------------------------------
Volumes Revenue Volumes Revenue Volumes Revenue
----------------------------------------------------------------------
2004:
Residential 103 $ 979 1 $ 2 104 $ 981
Commercial and industrial 37 292 69 40 106 332
Electric generation plants -- -- 44 15 44 15
Wholesale -- -- 44 1 44 1
--------------------------------------------------------------
140 $ 1,271 158 $ 58 298 1,329
Balancing accounts and other 4
--------
Total $ 1,333
- -----------------------------------------------------------------------------------------
2003:
Residential 87 $ 779 1 $ 2 88 $ 781
Commercial and industrial 38 260 70 39 108 299
Electric generation plants -- -- 56 18 56 18
Wholesale -- -- 7 1 7 1
--------------------------------------------------------------
125 $ 1,039 134 $ 60 259 1,099
Balancing accounts and other 63
---------
Total $ 1,162
- -----------------------------------------------------------------------
Electric Distribution and Transmission
(Volumes in millions of kWhs, dollars in millions)
2004 2003
-----------------------------------------
Volumes Revenue Volumes Revenue
-----------------------------------------
Residential 1,813 $ 183 1,672 $ 184
Commercial 1,512 138 1,454 150
Industrial 464 30 437 35
Direct access 729 21 806 18
Street and highway lighting 23 3 23 2
Off-system sales -- - 23 1
-----------------------------------------
4,541 375 4,415 390
Balancing accounts and other 6 5
-----------------------------------------
Total $ 381 $ 395
-----------------------------------------
Although commodity-related revenues from the DWR's allocated contracts
are not included in revenue, the associated volumes and distribution
revenue are included herein.
Other Operating Revenues
Other operating revenues, which consist primarily of revenues from
Global, increased to $646 million in 2004 from $366 million in 2003.
This change was primarily due to higher revenues at SER resulting from
increased volumes associated with contract sales of electricity to the
DWR and higher revenues at SET resulting from higher commodity revenue
from metals and European power.
Other Cost of Sales
Other cost of sales, which consists primarily of cost of sales at
Global, increased to $327 million in 2004 from $219 million in 2003,
primarily due to the higher sales noted above for SER.
Other Operating Expenses
Other operating expenses increased to $521 million in 2004 from $445
million in 2003, including $343 million and $318 million in 2004 and
2003, respectively, related to the California Utilities. The change was
primarily due to increased operating costs at SET related to increased
trading activity, as well as higher labor and employee benefit costs at
the California Utilities and nuclear refueling costs at SONGS.
Other Income (Loss) - Net
Other income, which primarily consists of equity earnings from
unconsolidated subsidiaries and interest on regulatory balancing
accounts, increased to $5 million in 2004 from a net expense of $2
million in 2003. The change was primarily due to the $8 million after-
tax settlement of an 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), partially offset by higher
regulatory interest expense at SoCalGas.
Interest Income
Interest income increased to $23 million in 2004 from $12 million in
2003 due primarily to interest income earned from the Internal Revenue
Service during the 2004 quarter.
Income Taxes
Income tax expense was $57 million in 2004 and $24 million in 2003. The
effective income tax rate was 20.5 percent and 16.7 percent,
respectively. The increase in income tax expense was due primarily to
higher taxable income and a higher effective income tax rate in 2004
offset by the reduction of certain prior year state income tax
liabilities. Further discussion of Section 29 credits is provided in
Note 7 of the notes to Consolidated Financial Statements in the Annual
Report.
Discontinued Operations
During the first quarter of 2004 Sempra Energy's Board of Directors
approved management's plan to dispose of its interest in Atlantic
Electric & Gas Limited (AEG). This disposal meets the criteria
established for recognition as discontinued operations under SFAS 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets." The
financial results of AEG are reported separately as discontinued
operations for both quarters presented. AEG's losses were $24 million
or $0.10 per diluted share in 2004 compared to $3 million or $0.01 per
diluted share in 2003. Sempra Energy consolidated AEG in its financial
statements at December 31, 2003 as a result of the adoption of FIN 46.
On April 27, 2004, the company entered into a sales agreement which is
expected to result in no significant gain or loss. Note 4 of the notes
to Consolidated Financial Statements provides further details.
Net Income
Net income increased to $197 million, or $0.85 per diluted share of
common stock, in 2004 from $88 million, or $0.42 per diluted share in
2003. Excluding the effects of the cumulative effect of the change in
accounting principle ($0.14 per diluted share), which is discussed in
Note 2 of the notes to Consolidated Financial Statements, income from
continuing operations was $221 million, or $0.96 per diluted share in
2004 compared to $120 million, or $0.58 per diluted share in 2003. The
change was primarily due to higher net income from SET and SER as
discussed below.
The only differences between basic and diluted earnings per share are
the effects of common stock options and the Equity Units, which are
discussed in Note 12 of the notes to Consolidated Financial Statements
in the Annual Report.
Net Income by Business Unit
Quarters ended
March 31,
- ---------------------------------------------------------------
(Dollars in millions) 2004 2003
- ---------------------------------------------------------------
California Utilities
Southern California Gas Company $ 56 $ 58
San Diego Gas & Electric 50 45
------ ------
Total Utilities 106 103
Global Enterprises
Sempra Energy Trading 59 10
Sempra Energy Resources 37 10
Sempra Energy International/LNG 17 7
Sempra Energy Solutions (4) --
------ ------
Total Global Enterprises 109 27
Sempra Energy Financial 10 11
Parent and Other (4) (21)
------ ------
Continuing Operations 221 120
Discontinued Operations (24) (3)
Cumulative Effect of Change in
Accounting Principle -- (29)*
------ ------
Consolidated Net Income $ 197 $ 88
====== ======
- ---------------------------------------------------------------
* The effects to SET and SES were ($28) million and ($1) million,
respectively.
SOUTHERN CALIFORNIA GAS COMPANY
Net income for SoCalGas decreased to $56 million in 2004 from $58
million in 2003, as higher 2004 revenues were offset by increased
operating costs.
SAN DIEGO GAS & ELECTRIC
Net income for SDG&E increased to $50 million in 2004 compared to $45
million in 2003, primarily due to higher transmission and distribution
revenue offset partially by higher operating costs and the absence of
the 2003 Incremental Cost Incentive Pricing for SONGS and performance-
based regulation gains.
SEMPRA ENERGY TRADING
SET recorded net income of $59 million in 2004 compared to $10 million
in 2003, excluding the cumulative effect of the change in accounting
principle of ($28) million. The change in 2004 was primarily
attributable to higher trading margin on metals and European power
commodities.
A summary of SET's unrealized revenues for trading activities for the
quarters ended March 31, 2004 and 2003 follows:
(Dollars in millions) 2004 2003
- ------------------------------------------------------------------
Balance at December 31 $ 269 $ 180
Cumulative effect adjustment -- (48)
Additions 640 299
Realized (448) 11
-------------------------------------
Balance at March 31 $ 461 $ 442
- ------------------------------------------------------------------
The estimated fair values for SET's trading activities as of March 31,
2004, and the periods during which unrealized revenues are expected to
be realized, are (dollars in millions):
Fair Market
Value at
March 31, /--Scheduled Maturity (in months)--/
Source of fair value 2004 0-12 13-24 25-36 >36
- -------------------------------------------------------------------------
Prices actively quoted $ 295 $ 223 $ 36 $ (4) $ 40
Prices provided by other
external sources 8 (6) -- -- 14
Prices based on models
and other valuation
methods 24 8 2 -- 14
------------------------------------------------
Over-the-counter (OTC)
revenue * 327 225 38 (4) 68
Exchange contracts ** 134 68 58 15 (7)
------------------------------------------------
Total $ 461 $ 293 $ 96 $ 11 $ 61
- -------------------------------------------------------------------------
* The present value of unrealized revenue to be received or (paid) from
outstanding OTC contracts.
** Cash (paid) or received associated with open Exchange contracts.
SET's Value at Risk (VaR) amounts are described in Item 3.
See also the discussion concerning the CPUC's prohibition of IOUs'
procuring electricity from their affiliates in "Electric Industry
Regulation" in Note 13 of the notes to Consolidated Financial
Statements in the Annual Report.
SEMPRA ENERGY RESOURCES
SER recorded net income of $37 million in 2004 compared to $10 million
in 2003. The change was primarily due to higher volumes associated with
contract sales of electricity to the DWR.
During March 2004 the El Dorado generating plant, 50% owned by SER,
suffered significant damage to a transformer requiring the plant to
cease operations temporarily. Temporary/permanent equipment is
currently expected to be installed. The plant is anticipated to
recommence operations near the end of the second quarter of 2004, but
repairs could extend until near the end of the third quarter of 2004.
The impact on operating margins will not be significant if the plant
returns to service near the end of the second quarter of 2004. SER is
expected to be able to meet its contractual obligations for the sale of
power. Damage and/or insurance claims will be filed for the cost of
repairs, replacement and related project losses during this period.
SEMPRA ENERGY INTERNATIONAL/LNG
SEI/SELNG recorded net income of $17 million in 2004 compared to $7
million in 2003. The increase was due primarily to the settlement of an
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).
SEMPRA ENERGY SOLUTIONS
SES recorded a net loss of $4 million in 2004 compared to break even
results in 2003, excluding the ($1) million cumulative effect of the
change in accounting principle. The increase was primarily due to lower
net commodity revenues in 2004.
SEMPRA ENERGY FINANCIAL
SEF recorded net income of $10 million and $11 million for the quarters
ended March 31, 2004 and 2003, respectively.
PARENT AND OTHER
Net losses for Parent and Other were $4 million in 2004 compared to $21
million in 2003. The change was due primarily to increased interest
income in 2004 and the reduction of certain prior year state income
tax liabilities.
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 March 31, 2004, the company had $653 million in cash and $2.1 billion
in available unused, committed lines of credit.
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 was to be unable to issue new
securities under acceptable terms, neither of which is considered
likely, the company would be required to reduce non-utility capital
expenditures 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.
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. However, if SDG&E receives CPUC approval of its plans to
purchase from SER a 550-megawatt (MW) generating facility to be
constructed in Escondido, California, 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. In April 2004, a
proposed CPUC decision approved SDG&E's plan to buy the generating
facility. A final CPUC decision is scheduled for May 2004.
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
$279 million at March 31, 2004, down from $359 million at December 31,
2003. SET's external debt was $149 million at March 31, 2004. 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 liquefied
natural gas (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 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 and synthetic fuel. 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.
CASH FLOWS FROM OPERATING ACTIVITIES
Net cash provided by operating activities totaled $782 million and $691
million for the quarters ended March 31, 2004 and 2003, respectively.
The change was attributable to higher net income, the increase in
overcollected balancing accounts and lower accounts receivable in 2004.
For the quarter ended March 31, 2004, the company made pension plan
contributions of $1 million for the 2004 plan year.
CASH FLOWS FROM INVESTING ACTIVITIES
Net cash provided by (used in) investing activities totaled $149 million
and $(319) million for the quarters ended March 31, 2004 and 2003,
respectively. The change was 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.
Starting in 2003 and through the end of the first quarter of 2004, SET
spent $50 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 Federal Energy Regulatory Commission
(FERC)-regulated, market-based pricing facility is expected to inject
cushion gas starting in early May 2004.
On April 1, 2004, SEI and PSEG Global, an unaffiliated company, sold a
portion of their interests in Luz del Sur S.A.A. (Luz del Sur), a
Peruvian electric utility, for a total of $62 million. Prior to the
sale, each party had a 44-percent interest in Luz del Sur. SEI expects
to recognize an after-tax gain of $5 million as a result of the sale.
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 per day and is expected to begin operations by the fourth quarter of
2005 and to cost approximately $160 million. The company is currently
negotiating contracts to sell the output of this facility.
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
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.
The company expects to make capital expenditures and investments of $1.1
billion in 2004. Significant capital expenditures and investments are
expected to include $750 million for California utility plant
improvements and $110 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 incur capital
expenditures estimated at $200 million in order to connect with new
delivery locations. The expenditures would be included in utility rate
bases.
In addition to its normal capital expenditures related to its
distribution and transmission systems and its share of the additional
$200 million referred to above, SDG&E expects to be making significant
capital expenditures for the proposed generation resources referred to
in Note 6 of the notes to Consolidated Financial Statements.
On March 15, 2004, Sempra Energy Partners and Carlyle/Riverstone, an
energy and power-focused equity fund, announced a joint purchase and
sales agreement with American Electric Power (AEP) to acquire AEP's
Coleto Creek Power Station, a 632-MW coal-fired power plant in Goliad
County, Texas, for $430 million. The transaction also includes the
acquisition of five other operating power plants with generating
capacity of 1,318 MW and four currently inactive power plants (capable
of generating 1,863 MW) in Texas. The transaction is expected to be
substantially project financed on a non-recourse basis and to close in
July 2004.
CASH FLOWS FROM FINANCING ACTIVITIES
Net cash used in financing activities totaled $708 million and $24
million for the quarters ended March 31, 2004 and 2003, respectively. In
January 2004, SER purchased the assets of Mesquite Trust, the owner of
the Mesquite Power plant, thereby extinguishing $630 million of debt
outstanding. The increase in cash used in financing activities to repay
the Mesquite debt along with SoCalGas' repayment of $175 million of
first mortgage bonds and lower long-term debt issuances in 2004 were
partially offset by an increase in short-term debt in 2004.
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 notes to Consolidated
Financial Statements in 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 development of several electric-
generation projects that will significantly impact the company's future
performance, including the AEP-related acquisition noted above.
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.
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 noted above.
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.
CRITICAL ACCOUNTING POLICIES AND KEY NON-CASH PERFORMANCE INDICATORS
There have been no significant changes to the accounting policies
viewed by management as critical or key non-cash performance indicators
for the company's subsidiaries, as set forth in the Annual Report.
NEW ACCOUNTING STANDARDS
Relevant pronouncements that have recently become effective and have
had a significant effect on the company are Statement of Financial
Accounting Standards (SFAS) Nos. 143, 149 and 150, Financial Accounting
Standards Board Interpretation Nos. (FIN) 45 and 46, and Emerging
Issues Task Force (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, the company no longer recognizes energy-
related contracts under mark to market accounting unless the contracts
meet the requirements stated under SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities," which is the case for a
substantial majority of the company's contracts. 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": SFAS 143
requires entities to record the fair value of liabilities for legal
obligations related to asset retirements in the period in which they
are incurred. 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. 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 variable interest entity (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 (the Mesquite Trust) was the owner of the Mesquite Power plant
for which the company had a synthetic lease agreement. 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.
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 Value at Risk (VaR) for SET at March 31, 2004, and the average VaR
for the quarter ended March 31, 2004, at the 95-percent and 99-percent
confidence intervals (one-day holding period) were as follows (in
millions of dollars):
95% 99%
- ------------------------------------------------------
At March 31, 2004 $ 10.0 $ 14.2
Average for the quarter
ended March 31, 2004 $ 5.7 $ 8.1
- ------------------------------------------------------
As of March 31, 2004, the total VaR of the California Utilities' and
SES' positions was not material.
ITEM 4. CONTROLS AND PROCEDURES
The company has designed and maintains disclosure controls and
procedures to ensure that information required to be disclosed in the
company's reports under the Securities Exchange Act of 1934 is
recorded, processed, summarized and reported within the time periods
specified in the rules and forms of the Securities and Exchange
Commission and is accumulated and communicated to the company's
management, including its Chief Executive Officer and Chief Financial
Officer, as appropriate, to allow timely decisions regarding required
disclosure. In designing and evaluating these controls and procedures,
management recognizes that any system of controls and procedures, no
matter how well designed and operated, can provide only reasonable
assurance of achieving the desired objectives and necessarily applies
judgment in evaluating the cost-benefit relationship of other possible
controls and procedures. 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 as of March 31, 2004 has evaluated the effectiveness of the
design and operation of the company's disclosure controls and
procedures. Based on that evaluation, the company's Chief Executive
Officer and Chief Financial Officer have concluded that the controls
and procedures are effective.
There have been no significant changes in the company's internal
controls over financial reporting or in other factors that could
significantly affect the internal controls subsequent to the date the
company completed its evaluation.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
SDG&E has been advised by the County of San Diego that the county is
considering initiating legal proceedings against SDG&E 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. SDG&E disputes the county's allegations and believes that the
abatement of these materials was properly managed. The county has
indicated a willingness to settle this matter for less than $1 million.
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 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 December 31, 2003:
Current Report on Form 8-K filed February 24, 2004, filing as an exhibit
Sempra Energy's press release of February 24, 2004, giving the financial
results for the quarter ended December 31, 2003.
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.
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: April 29, 2004 By: /s/ F. H. Ault
----------------------------
F. H. Ault
Sr. Vice President and Controller
EXHIBIT 12 Sempra Energy Ratios
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EXHIBIT 12.1 |
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SEMPRA ENERGY |
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COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES |
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AND PREFERRED STOCK DIVIDENDS |
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(Dollars in millions) |
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Quarter ended |
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1999 |
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2000 |
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2001 |
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2002 |
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2003 |
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March 31, 2004 |
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Fixed Charges and Preferred Stock Dividends: |
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Interest |
$ 233 |
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$ 308 |
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$ 358 |
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$ 350 |
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$ 351 |
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$ 85 |
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Interest portion of annual rentals |
10 |
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8 |
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6 |
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6 |
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5 |
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1 |
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Preferred dividends of subsidiaries (1) |
16 |
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18 |
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16 |
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15 |
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11 |
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3 |
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Combined fixed charges and preferred stock |
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dividends for purpose of ratio |
$ 259 |
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$ 334 |
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$ 380 |
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$ 371 |
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$ 367 |
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$ 89 |
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Earnings: |
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Pretax income from continuing operations |
$ 573 |
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$ 699 |
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$ 731 |
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$ 721 |
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$ 742 |
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$ 278 |
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Total fixed charges (from above) |
259 |
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334 |
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380 |
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371 |
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367 |
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89 |
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Less: |
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Interest capitalized |
1 |
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3 |
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11 |
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29 |
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26 |
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4 |
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Equity in income (loss) of unconsolidated |
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subsidiaries and joint ventures |
- |
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62 |
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12 |
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(55) |
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8 |
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(6) |
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Total earnings for purpose of ratio |
$ 831 |
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$ 968 |
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$ 1,088 |
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$ 1,118 |
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$ 1,075 |
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$ 369 |
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Ratio of earnings to combined fixed charges |
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and preferred stock dividends |
3.21 |
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2.90 |
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2.86 |
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3.01 |
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2.93 |
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4.15 |
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(1) In computing this ratio, "Preferred dividends of subsidiaries" represents the before-tax earnings necessary to pay such dividends, |
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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)) and internal
control over financial reporting (as defined in Exchange Act Rules
15(f) and 15d-15(f)) 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) Designed such internal control over financial reporting, or
caused such internal control over financial reporting to be
designed under our supervision, to provide reasonable
assurance regarding the reliability of financial reporting and
the preparation of financial statements for external purposes
in accordance with generally accepted accounting principles;
c) 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
d) 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.
April 29, 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)) and internal
control over financial reporting (as defined in Exchange Act Rules
15(f) and 15d-15(f)) 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) Designed such internal control over financial reporting, or
caused such internal control over financial reporting to be
designed under our supervision, to provide reasonable
assurance regarding the reliability of financial reporting and
the preparation of financial statements for external purposes
in accordance with generally accepted accounting principles;
c) 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
d) 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.
April 29, 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 March 31, 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.
April 29, 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 March 31, 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.
April 29, 2004
/S/ NEAL E. SCHMALE
______________________
Neal E. Schmale
Chief Financial Officer
