UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2004
-------------------------------------
Commission file number 1-14201
---------------------------------------------
Sempra Energy
----------------------------------------------------------
(Exact name of registrant as specified in its charter)
California 33-0732627
- ------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
101 Ash Street, San Diego, California 92101
- -------------------------------------------------------------------
(Address of principal executive offices)
(Zip Code)
(619) 696-2034
----------------------------------------------------------
(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
----- -----
Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Exchange Act).
Yes X No
----- -----
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 October 31, 2004: 233,389,125
---------------------
2
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, and the Federal Energy Regulatory
Commission and other regulatory bodies in the United States and other
countries; capital market conditions, inflation rates, interest rates
and exchange rates; energy and trading markets, including the timing
and extent of changes in commodity prices; the availability of natural
gas; weather conditions and conservation efforts; war and terrorist
attacks; business, regulatory, environmental and legal decisions and
requirements; 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.
3
PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS.
<table>
SEMPRA ENERGY
STATEMENTS OF CONSOLIDATED INCOME
(Dollars in millions, except per share amounts)
<caption>
Three months ended
September 30,
------------------
2004 2003
------- -------
<s> <c> <c>
OPERATING REVENUES
California utilities:
Natural gas $ 909 $ 870
Electric 445 576
Other 811 612
------- -------
Total operating revenues 2,165 2,058
------- -------
OPERATING EXPENSES
California utilities:
Cost of natural gas 438 372
Cost of electric fuel and purchased power 143 128
Other cost of sales 484 371
Other operating expenses 530 668
Depreciation and amortization 171 158
Franchise fees and other taxes 54 54
------- -------
Total operating expenses 1,820 1,751
------- -------
Operating income 345 307
Other income - net 40 34
Interest income 25 8
Interest expense (74) (78)
Preferred dividends of subsidiaries (2) (2)
------- -------
Income before income taxes 334 269
Income tax expense 103 58
------- -------
Net income $ 231 $ 211
======= =======
Basic earnings per share:
Net income $ 1.01 $ 1.01
======= =======
Weighted-average number of shares outstanding (thousands) 229,376 208,816
======= =======
Diluted earnings per share:
Net income $ 0.98 $ 1.00
======= =======
Weighted-average number of shares outstanding (thousands) 235,936 212,273
======= =======
Dividends declared per share of common stock $ 0.25 $ 0.25
======= =======
See notes to Consolidated Financial Statements.
</table>
4
<table>
SEMPRA ENERGY
STATEMENTS OF CONSOLIDATED INCOME
(Dollars in millions, except per share amounts)
<caption>
Nine months ended
September 30,
------------------
2004 2003
------- -------
<s> <c> <c>
OPERATING REVENUES
California utilities:
Natural gas $ 3,189 $ 2,961
Electric 1,246 1,368
Other 2,086 1,492
------- -------
Total operating revenues 6,521 5,821
------- -------
OPERATING EXPENSES
California utilities:
Cost of natural gas 1,744 1,529
Cost of electric fuel and purchased power 425 428
Other cost of sales 1,186 886
Other operating expenses 1,597 1,631
Depreciation and amortization 501 455
Franchise fees and other taxes 171 167
------- -------
Total operating expenses 5,624 5,096
------- -------
Operating income 897 725
Other income - net 58 38
Interest income 58 30
Interest expense (234) (223)
Preferred dividends of subsidiaries (7) (8)
Trust preferred distributions by subsidiary -- (9)
------- -------
Income from continuing operations before income taxes 772 553
Income tax expense 191 109
------- -------
Income from continuing operations 581 444
Loss from discontinued operations, net of tax (Note 4) (30) --
Loss on disposal of discontinued operations, net of tax (Note 4) (2) --
------- -------
Income before cumulative effect of change in accounting principle 549 444
Cumulative effect of change in accounting
principle, net of tax (Note 2) -- (29)
------- -------
Net income $ 549 $ 415
======= =======
Basic earnings per share:
Income from continuing operations $ 2.55 $ 2.14
Discontinued operations, net of tax (0.14) --
Cumulative effect of change in accounting principle, net of tax -- (0.14)
------- -------
Net income $ 2.41 $ 2.00
======= =======
Weighted-average number of shares outstanding (thousands) 227,412 207,620
======= =======
Diluted earnings per share:
Income from continuing operations $ 2.50 $ 2.12
Discontinued operations, net of tax (0.14) --
Cumulative effect of change in accounting principle, net of tax -- (0.14)
------- -------
Net income $ 2.36 $ 1.98
======= =======
Weighted-average number of shares outstanding (thousands) 232,366 210,160
======= =======
Dividends declared per share of common stock $ 0.75 $ 0.75
======= =======
See notes to Consolidated Financial Statements.
</table>
5
<table>
SEMPRA ENERGY
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
<caption>
September 30, December 31,
2004 2003
------------- ------------
<s> <c> <c>
ASSETS
Current assets:
Cash and cash equivalents $ 267 $ 432
Short-term investments -- 363
Accounts receivable - trade 685 875
Accounts and notes receivable - other 85 127
Due from affiliate 7 --
Income taxes receivable -- 1
Deferred income taxes 58 2
Interest receivable 82 62
Trading assets 6,156 5,250
Regulatory assets arising from fixed-price
contracts and other derivatives 155 144
Other regulatory assets 109 89
Inventories 225 147
Other 198 157
-------- --------
Current assets of continuing operations 8,027 7,649
Current assets of discontinued operations 82 220
-------- --------
Total current assets 8,109 7,869
-------- --------
Investments and other assets:
Due from affiliates 45 55
Regulatory assets arising from fixed-price
contracts and other derivatives 530 650
Other regulatory assets 476 552
Nuclear decommissioning trusts 575 570
Investments 1,132 1,114
Sundry 750 706
-------- --------
Total investments and other assets 3,508 3,647
-------- --------
Property, plant and equipment:
Property, plant and equipment 15,927 15,317
Less accumulated depreciation and amortization (5,080) (4,843)
-------- --------
Property, plant and equipment - net 10,847 10,474
-------- --------
Total assets $ 22,464 $ 21,990
======== ========
See notes to Consolidated Financial Statements.
</table>
6
<table>
SEMPRA ENERGY
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
<caption>
September 30, December 31,
2004 2003
------------- -------------
<s> <c> <c>
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Short-term debt $ 435 $ 28
Accounts payable - trade 745 779
Accounts payable - other 89 62
Income taxes payable 302 156
Deferred income taxes -- 26
Trading liabilities 4,860 4,457
Dividends and interest payable 134 136
Regulatory balancing accounts - net 347 424
Fixed-price contracts and other derivatives 164 148
Current portion of long-term debt 99 1,433
Other 690 681
-------- --------
Current liabilities of continuing operations 7,865 8,330
Current liabilities of discontinued operations 19 52
-------- --------
Total current liabilities 7,884 8,382
-------- --------
Long-term debt 4,414 3,841
-------- --------
Deferred credits and other liabilities:
Due to affiliates 362 362
Customer advances for construction 85 89
Postretirement benefits other than pensions 121 131
Deferred income taxes 170 208
Deferred investment tax credits 80 84
Regulatory liabilities arising from cost
of removal obligations 2,331 2,238
Regulatory liabilities arising from asset
retirement obligations 300 303
Other regulatory liabilities 112 108
Fixed-price contracts and other derivatives 530 680
Asset retirement obligations 321 313
Deferred credits and other 1,194 1,182
-------- --------
Total deferred credits and other liabilities 5,606 5,698
-------- --------
Preferred stock of subsidiaries 179 179
-------- --------
Contingencies and commitments (Note 7)
SHAREHOLDERS' EQUITY
Preferred stock (50 million shares authorized;
none issued) -- --
Common stock (750 million shares authorized;
233 million and 227 million shares outstanding at
September 30, 2004 and December 31, 2003, respectively) 2,166 2,028
Retained earnings 2,674 2,298
Deferred compensation relating to ESOP (33) (35)
Accumulated other comprehensive income (loss) (426) (401)
-------- --------
Total shareholders' equity 4,381 3,890
-------- --------
Total liabilities and shareholders' equity $ 22,464 $ 21,990
======== ========
See notes to Consolidated Financial Statements.
</table>
7
<table>
SEMPRA ENERGY
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in millions)
<caption>
Nine months ended
September 30,
-------------------
2004 2003
------- -------
<s> <c> <c>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 549 $ 415
Adjustments to reconcile net income to net cash
provided by operating activities:
Loss from discontinued operations, net of tax 30 --
Loss on disposal of discontinued operations, net of tax 2 --
Cumulative effect of change in accounting principle -- 29
Depreciation and amortization 501 455
Impairment losses 8 79
Deferred income taxes and investment tax credits (7) (160)
Other - net 8 38
Net changes in other working capital components (523) 75
Changes in other assets (66) (36)
Changes in other liabilities 21 28
------- -------
Net cash provided by continuing operations 523 923
Net cash used in discontinued operations (30) --
------- -------
Net cash provided by operating activities 493 923
------- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment (782) (664)
Proceeds from sale of assets 371 --
Proceeds from disposal of discontinued operations 137 --
Investments and acquisitions of subsidiaries,
net of cash acquired (70) (182)
Dividends received from affiliates 50 21
Affiliate loan -- (54)
Other - net -- (8)
------- -------
Net cash used in investing activities (294) (887)
------- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid (162) (155)
Issuances of common stock 120 81
Repurchases of common stock (1) (6)
Issuances of long-term debt 897 400
Payments on long-term debt (1,648) (481)
Increase in short-term debt - net 434 89
Other - net (4) (8)
------- -------
Net cash used in financing activities (364) (80)
------- -------
Decrease in cash and cash equivalents (165) (44)
Cash and cash equivalents, January 1 432 455
------- -------
Cash and cash equivalents, September 30 $ 267 $ 411
======= =======
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized $ 229 $ 216
======= =======
Income tax payments, net of refunds $ 120 $ 97
======= =======
See notes to Consolidated Financial Statements.
</table>
8
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. GENERAL
This Quarterly Report on Form 10-Q is that of Sempra Energy (the
company), a California-based Fortune 500 holding company. Sempra
Energy's subsidiaries include San Diego Gas & Electric Company (SDG&E),
Southern California Gas Company (SoCalGas) (collectively referred to
herein as the California Utilities); Sempra Energy Global Enterprises
(Global), which is the holding company for Sempra Energy Trading (SET),
Sempra Energy Resources (SER), Sempra Energy International (SEI),
Sempra Energy LNG (SELNG) and other, smaller businesses; Sempra Energy
Financial (SEF); and additional smaller businesses. The financial
statements herein are the Consolidated Financial Statements of Sempra
Energy and its consolidated subsidiaries.
The accompanying Consolidated Financial Statements have been prepared
in accordance with the interim-period-reporting requirements of Form
10-Q. Results of operations for interim periods are not necessarily
indicative of results for the entire year. In the opinion of
management, the accompanying statements reflect all adjustments
necessary for a fair presentation. These adjustments are only of a
normal recurring nature. Certain changes in classification have been
made to prior presentations to conform to the current financial
statement presentation. Specifically, certain December 31, 2003 income
tax liabilities have been reclassified from Deferred Income Taxes to
current Income Taxes Payable and to Deferred Credits and Other
Liabilities to conform to the current presentation of these items.
Information in this Quarterly Report is unaudited and should be read in
conjunction with the Annual Report on Form 10-K for the year ended
December 31, 2003 (Annual Report) and the Quarterly Reports on Form 10-Q
for the first and second quarters of 2004.
The company's significant accounting policies are described in Note 1
of the notes to Consolidated Financial Statements in the Annual Report.
The same accounting policies are followed for interim reporting
purposes.
The company follows the guidance of Statement of Financial Accounting
Standards (SFAS) 142, Goodwill and Other Intangible Assets. The
carrying amount of goodwill (included in Noncurrent Sundry Assets on
the Consolidated Balance Sheets) was $188 million as of December 31,
2003 and September 30, 2004.
The California Utilities account for the economic effects of regulation
on utility operations in accordance with SFAS No. 71, Accounting for
the Effects of Certain Types of Regulation.
9
The following tables provide the per share computations for income from
continuing operations.
<table>
<caption>
Three months ended September 30, 2004 Three months ended September 30, 2003
-------------------------------------- -------------------------------------
Income Shares Per Income Shares Per
(millions) (thousands) Share (millions) (thousands) Share
(numerator) (denominator) Amounts (numerator) (denominator) Amounts
----------- ------------- ------- ----------- ------------- --------
<s> <c> <c> <c> <c> <c> <c>
Basic EPS:
Income from continuing
operations $ 231 229,376 $ 1.01 $ 211 208,816 $ 1.01
Effect of dilutive
securities:
Stock options and
restricted stock
awards 3,663 (0.02) 3,457 (0.01)
Equity Units 2,897 (0.01) -- --
--------- ---------- ------ -------- --------- -------
Diluted EPS:
Income from continuing
operations $ 231 235,936 $ 0.98 $ 211 212,273 $ 1.00
========= ======== ======= ======== ======== =======
Nine months ended September 30, 2004 Nine months ended September 30, 2003
-------------------------------------- -------------------------------------
Income Shares Per Income Shares Per
(millions) (thousands) Share (millions) (thousands) Share
(numerator) (denominator) Amounts (numerator) (denominator) Amounts
----------- ------------- ------- ----------- ------------- --------
Basic EPS:
Income from continuing
operations $ 581 227,412 $ 2.55 $ 444 207,620 $ 2.14
Effect of dilutive
securities:
Stock options and
restricted stock
awards 3,344 (0.03) 2,540 (0.02)
Equity Units 1,610 (0.02) -- --
--------- ---------- ------ -------- --------- ------
Diluted EPS:
Income from continuing
operations $ 581 232,366 $ 2.50 $ 444 210,160 $ 2.12
========= ======== ======= ======== ======== =======
</table>
Additional information regarding the Equity Units is provided in Note
12 of the Annual Report.
10
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. The proposed statement
would eliminate the choice of accounting for share-based compensation
transactions using Accounting Principles Board (APB) Opinion No. 25,
Accounting for Stock Issued to Employees, whereby no expense is
recorded for most stock options, and instead would require that such
transactions be accounted for using a fair-value-based method, whereby
expense is recorded for stock options. It would also prohibit
application by restating prior periods and would require that expense
ultimately be recognized only for those options that actually vest. A
final statement is expected to be issued in the fourth quarter of 2004
and be effective July 1, 2005.
The following table provides the pro forma effects that would have
resulted if stock options had been expensed.
<table>
<caption>
Three months ended Nine months ended
September 30, September 30,
(Dollars in millions, ------------------ ------------------
except for per share amounts) 2004 2003 2004 2003
- --------------------------------------------------------------- ------------------
<s> <c> <c> <c> <c>
Net income as reported $ 231 $ 211 $ 549 $ 415
Stock-based employee compensation expense
as recorded, net of tax 6 3 15 17
Total stock-based employee compensation
under fair-value method for all awards,
net of tax (9) (5) (21) (23)
------------------ ------------------
Pro forma net income $ 228 $ 209 $ 543 $ 409
================== ==================
Earnings per share:
Basic--as reported $ 1.01 $ 1.01 $ 2.41 $ 2.00
================== ==================
Basic--pro forma $ 0.99 $ 1.00 $ 2.39 $ 1.97
================== ==================
Diluted--as reported $ 0.98 $ 1.00 $ 2.36 $ 1.98
================== ==================
Diluted--pro forma $ 0.97 $ 0.98 $ 2.34 $ 1.95
================== ==================
</table>
SFAS 132 (revised 2003), "Employers' Disclosures about Pensions and
Other Postretirement Benefits": This statement revises required
disclosures about employers' pension plans and other postretirement
benefit plans, effective in 2004. It requires disclosures beyond those
in the original SFAS 132 related to the assets, obligations, cash flows
and net periodic benefit cost of defined benefit pension plans and
other defined postretirement benefit plans. In addition, it requires
interim-period disclosures regarding the amount of net periodic benefit
cost recognized and the total amount of the employers' contributions
paid and expected to be paid during the current fiscal year. It does
not change the measurement or recognition of those plans.
11
The following table provides the components of benefit costs for the
three and nine months ended September 30:
<table>
<caption>
Other
Pension Benefits Postretirement Benefits
--------------------------------------------
Three months ended Three months ended
September 30, September 30,
--------------------------------------------
(Dollars in millions) 2004 2003 2004 2003
- -------------------------------------------------------------------------------
<s> <c> <c> <c> <c>
Service cost $ 12 $ 7 $ 5 $ 5
Interest cost 38 38 10 13
Expected return on assets (38) (40) (9) (9)
Amortization of:
Transition obligation -- -- 2 3
Prior service cost 3 2 (1) (1)
Actuarial loss 3 6 1 5
Regulatory adjustment (9) (1) 7 (3)
--------------------------------------------
Total net periodic benefit cost $ 9 $ 12 $ 15 $ 13
- -------------------------------------------------------------------------------
Other
Pension Benefits Postretirement Benefits
--------------------------------------------
Nine months ended Nine months ended
September 30, September 30,
--------------------------------------------
(Dollars in millions) 2004 2003 2004 2003
- -------------------------------------------------------------------------------
Service cost $ 36 $ 39 $ 16 $ 14
Interest cost 115 113 39 41
Expected return on assets (115) (121) (27) (26)
Amortization of:
Transition obligation -- -- 7 7
Prior service cost 7 7 (1) (1)
Actuarial loss 9 9 7 8
Regulatory adjustment (25) (11) 7 (3)
--------------------------------------------
Total net periodic benefit cost $ 27 $ 36 $ 48 $ 40
- -------------------------------------------------------------------------------
</table>
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 nine
months ended September 30, 2004, $10 million and $44 million of
contributions have been made to its pension plans and other
postretirement benefit plans, respectively, including $1 million and
$14 million, respectively, for the quarter ended September 30, 2004.
FASB Staff Position (FSP) 106-2, "Accounting and Disclosure
Requirements Related to the Medicare Prescription Drug, Improvement and
Modernization Act of 2003": In December 2003, the Medicare Prescription
Drug, Improvement and Modernization Act of 2003 (the "Act") was
enacted. The Act establishes a prescription drug benefit under
Medicare, known as "Medicare Part D," and a tax-exempt federal subsidy
12
to sponsors of retiree health care benefit plans that provide a benefit
that actuarially is at least equivalent to Medicare Part D.
In May 2004, the FASB issued FSP 106-2 which requires that the effects
of the federal subsidy be considered an actuarial gain and be
recognized in the same manner as other actuarial gains and losses. In
addition, FSP 106-2 requires certain disclosures for employers that
sponsor postretirement health care plans that provide prescription drug
benefits. During the third quarter of 2004, the company adopted FSP
106-2 retroactive to the beginning of the year. The company and its
actuarial advisors determined that benefits provided to certain
participants will actuarially be at least equivalent to Medicare Part
D, and, accordingly, the company will be entitled to an expected tax-
exempt subsidy that reduces the company's accumulated postretirement
benefit obligation under the plan at January 1, 2004 by $102 million
and net periodic benefit cost for 2004 by $13 million.
The net periodic postretirement benefit costs for the three and nine
months ended September 30, 2004 were reduced by $10 million, before
regulatory adjustments, to reflect the expected subsidy as a result of
the Act.
The following tables provide the impact of the Act on components of net
periodic postretirement benefit costs. The three-month period includes
the entire nine-month subsidy since none of the subsidy was recorded
until the third quarter.
<table>
<caption>
Three months ended
September 30, 2004
--------------------------------------------
Before After
Federal Effect Federal
(Dollars in millions) Subsidy of Subsidy Subsidy
- ------------------------------------------------------------------------------
<s> <c> <c> <c>
Service cost $ 6 $ (1) $ 5
Interest cost 15 (5) 10
Expected return on assets (9) -- (9)
Amortization of:
Transition obligation 2 -- 2
Prior service cost (1) -- (1)
Actuarial (gain) loss 5 (4) 1
Regulatory adjustment (2) 9 7
----------------------------------------------
Total net periodic benefit cost $ 16 $ (1) $ 15
- ------------------------------------------------------------------------------
13
Nine months ended
September 30, 2004
--------------------------------------------
Before After
Federal Effect Federal
(Dollars in millions) Subsidy of Subsidy Subsidy
- ------------------------------------------------------------------------------
Service cost $ 17 $ (1) $ 16
Interest cost 44 (5) 39
Expected return on assets (27) -- (27)
Amortization of:
Transition obligation 7 -- 7
Prior service cost (1) -- (1)
Actuarial (gain) loss 11 (4) 7
Regulatory adjustment (2) 9 7
----------------------------------------------
Total net periodic benefit cost $ 49 $ (1) $ 48
- ------------------------------------------------------------------------------
</table>
SFAS 143, "Accounting for Asset Retirement Obligations": Beginning in
2003, SFAS 143 requires entities to record liabilities for future costs
expected to be incurred when assets are retired from service, if the
retirement process is legally required. It also requires the
reclassification of utilities' estimated removal costs, which have
historically been recorded in accumulated depreciation, to a regulatory
liability. At September 30, 2004 and December 31, 2003, the estimated
removal costs recorded as a regulatory liability were $1.4 billion at
both dates for SoCalGas, and $882 million and $846 million,
respectively, for SDG&E.
The change in the asset retirement obligations for the nine months
ended September 30, 2004 is as follows (dollars in millions):
Balance as of January 1, 2004 $ 337
Accretion expense (interest) 17
Payments (9)
------
Balance as of September 30, 2004 $ 345*
======
* The current portion of the obligation is included in Other Current
Liabilities on the Consolidated Balance Sheets.
In June 2004, the FASB issued a proposed interpretation, Accounting for
Conditional Asset Retirement Obligations, an interpretation of FASB
Statement No. 143. The interpretation would clarify that a legal
obligation to perform an asset retirement activity that is conditional
on a future event is within the scope of SFAS 143. Accordingly, the
interpretation would require an entity to recognize a liability for a
conditional asset retirement obligation if the liability's fair value
can be reasonably estimated. The proposed interpretation would be
effective for the company on December 31, 2005.
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 and for hedging
activities under SFAS 133. Under SFAS 149, natural gas forward
contracts that are subject to unplanned netting generally do not
qualify for the normal purchases and normal sales exception, whereby
14
derivatives are not required to be marked to market when the contract
is usually settled by the physical delivery of natural gas. ("Netting"
refers to contract settlement by paying or receiving the monetary
difference between the contract price and the market price at the date
on which physical delivery would have occurred.) The company has
determined that all natural gas contracts are subject to unplanned
netting and as such, these contracts are 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 are 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 was further reclassified to Due to Affiliates upon the
adoption of FASB Interpretation No. (FIN) 46 as discussed below.
Emerging Issues Task Force (EITF) 98-10, "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities": In
accordance with the EITF's rescission of Issue 98-10 by the release of
Issue 02-3, the company no longer marks to market energy-related
contracts unless the contracts meet the requirements stated under SFAS
133 and SFAS 149. A substantial majority of the company's contracts do
meet these requirements. On January 1, 2003, the company recorded the
initial effect of Issue 98-10's rescission as a cumulative effect of a
change in accounting principle, which reduced after-tax earnings by $29
million. Neither the cumulative nor the ongoing effect impacts the
company's cash flow or liquidity. However, net income for the third
quarter of 2004 was $38 million lower than the true economic value of
SET's activities due to the EITF's rescission of Issue 98-10.
Additional information on derivative instruments is provided in Note 5.
FIN 45, "Guarantor's Accounting and Disclosure Requirements for
Guarantees": As of September 30, 2004, substantially all of the
company's guarantees were intercompany, whereby the parent issues the
guarantees on behalf of its consolidated subsidiaries. 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. In addition, the company
provided American Electric Power (AEP) a guarantee of up to $75 million
for specified liabilities described in the agreement for the company's
acquisition of certain AEP power plants. The company does not expect
material losses to result from this guarantee because performance is
not expected to be required and, therefore, has determined that the
fair value of the guarantee is immaterial. SDG&E and SoCalGas have a
residual value guarantee under a fleet lease arrangement. As of
September 30, 2004, the company had no liabilities recorded for the
15
fleet lease guarantees due to the immaterial amount of the estimated
fair value of such guarantees.
FIN 46, "Consolidation of Variable Interest Entities (an interpretation
of Accounting Research Bulletin (ARB) No. 51)": FIN 46 requires the
primary beneficiary of a variable interest entity's activities to
consolidate the entity. Variable interest entities (VIEs) are
enterprises that have certain characteristics defined in FIN 46.
Sempra Energy adopted FIN 46 on December 31, 2003, resulting in the
consolidation of two VIEs for which it is the primary beneficiary. One
of the VIEs (Mesquite Trust) was the owner of the Mesquite Power plant
for which the company had a synthetic lease agreement. The company
recorded an after-tax credit of $9 million in the fourth quarter of
2003 for the cumulative effect of the change in accounting principle.
The company bought out the lease in January 2004 and now owns the
plant.
The other VIE is Atlantic Electric & Gas (AEG). 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 the fourth
quarter of 2003 for the cumulative effect of the change in accounting
principle. During the first quarter of 2004, Sempra Energy's Board of
Directors approved management's plan to dispose of AEG. Note 4 provides
further discussion concerning this matter and the disposal of AEG,
which occurred in April 2004.
In accordance with this interpretation, the company deconsolidated a
wholly owned subsidiary trust from its financial statements at December
31, 2003. The trust has no assets except for its receivable from the
company. Due to the deconsolidation of this entity, Sempra Energy
reclassified $200 million of mandatorily redeemable trust preferred
securities to Due to Affiliates on its Consolidated Balance Sheets.
In addition, contracts under which SDG&E acquires power from generation
facilities otherwise unrelated to SDG&E could result in a requirement
for SDG&E to consolidate the entity that owns the facility. As
permitted by the interpretation, SDG&E is continuing the process of
determining whether it has any such situations and, if so, gathering
the information that would be needed to perform the consolidation. The
effects of this, if any, are not expected to significantly affect the
financial position of SDG&E and there would be no effect on results of
operations or liquidity.
16
NOTE 3. COMPREHENSIVE INCOME
The following is a reconciliation of net income to comprehensive
income.
Three months Nine months
ended ended
September 30, September 30,
---------------------------------
(Dollars in millions) 2004 2003 2004 2003
- -----------------------------------------------------------------
Net income $ 231 $ 211 $ 549 $ 415
Minimum pension liability
adjustments -- -- -- (6)
Foreign currency adjustments 13 (13) 3 31
Financial instruments (15) -- (28) --
---------------------------------
Comprehensive income $ 229 $ 198 $ 524 $ 440
- -----------------------------------------------------------------
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
resulted in a loss of $2 million after taxes in the second quarter,
which has been reported separately on the Statements of Consolidated
Income.
The net losses from discontinued operations were $32 million for the
nine months ended September 30, 2004 (including the $2 million loss on
disposal). There was no operating activity for the quarter ended
September 30, 2004. During 2003, the company accounted for its
investment in AEG under the equity method of accounting. As such, for
the nine-month and three-month periods ended September 30, 2003, the
company recorded its share of AEG's net income, $1 million and $7
million, respectively, in Other Income - Net on the Statements of
Consolidated Income. Additionally, for those nine-month and three-month
periods the company recorded $2 million and $1 million, respectively,
of interest income, and for both periods the company recorded
offsetting income tax expense of $1 million. Effective December 31,
2003, AEG has been consolidated as a result of the adoption of FIN 46.
This is discussed further in the Annual Report.
17
Included within the net loss from discontinued operations are AEG's
operating results, summarized below:
Nine months ended
(Dollars in millions) September 30, 2004
- ---------------------------------------------------------------------
Operating revenues $ 201
Loss from discontinued operations,
before income taxes $ (30)
Loss on disposal of discontinued operations,
before income taxes $ (6)
- ---------------------------------------------------------------------
AEG's balance sheet data, excluding intercompany balances (which are
significant) eliminated in consolidation, are summarized below:
September 30, December 31,
(Dollars in millions) 2004 2003
- --------------------------------------------------------------------
Assets:
Accounts receivable $ 37 $ 137
Other current assets 45 83
------ ------
Total assets $ 82 $ 220
------ ------
Liabilities:
Accounts payable $ -- $ 36
Other current liabilities 19 16
------ ------
Total liabilities $ 19 $ 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 hedged items are recognized as
either assets or liabilities on the balance sheet, measured at fair
value. Except at the California Utilities, where such changes are
balanced in the ratemaking process, 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.
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. Any ineffective portion is
reported in earnings immediately.
18
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 financial instruments to reduce its exposure to
fluctuations in 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 or paid 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 use of derivative financial instruments by the
California Utilities is subject to certain limitations imposed by
company policy and regulatory requirements.
Contracts that meet the definition of normal purchases 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 September 30, 2003 generally do not
qualify for the normal purchases and sales exception and, accordingly,
are marked to market.
Fixed-price Contracts and Other Derivatives
Fixed-price Contracts and Other Derivatives on the Consolidated Balance
Sheets primarily reflect the California Utilities' unrealized gains and
losses related to long-term delivery contracts for purchased power and
natural gas transportation. The California Utilities have established
offsetting regulatory assets and liabilities to the extent that these
gains and losses are included in the calculation of future rates. If
gains and losses at the California Utilities are not recoverable or
payable through future rates, the California Utilities apply hedge
accounting if certain criteria are met. If a contract no longer meets
the requirements of SFAS 133, the unrealized gains and losses and the
related regulatory asset or liability will be amortized over the
remaining contract life.
The changes in Fixed-price Contracts and Other Derivatives on the
Consolidated Balance Sheets for the nine months ended September 30,
2004 were primarily due to the settlement of the contingent purchase
price obligation arising from the company's acquisition of the proposed
Cameron liquefied natural gas (LNG) project described below and the
physical deliveries under long-term purchased-power and natural gas
transportation contracts. For the nine months ended September 30, 2004,
pre-tax income from transactions associated with fixed-price contracts
and other derivatives included $13 million for the settlement of the
Cameron contingency, which occurred during the first quarter. The
transactions associated with fixed-price contracts and other
derivatives had no material impact to the Statements of Consolidated
Income for the nine months ended September 30, 2003.
19
Trading Assets and Trading Liabilities
Trading Assets and Trading Liabilities primarily arise from the
activities of SET. SET derives revenue from market making and trading
activities, as a principal, in natural gas, electricity, petroleum,
petroleum products, metals and other commodities, for which it quotes
bid and ask prices to other market makers and end users. It also earns
trading profits as a dealer by structuring and executing transactions
that permit its counterparties to manage their risk profiles. SET
utilizes derivative instruments to reduce its exposure to unfavorable
changes in market prices, which are subject to significant and often
volatile fluctuation. These instruments include futures, forwards,
swaps and options, and represent contracts with counterparties under
which payments are linked to or derived from energy market indices or
on terms predetermined by the contract, which may or may not be
financially settled by SET. Sempra Energy guarantees many of SET's
transactions.
Derivative 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 offset
exists under an enforceable netting arrangement. Other derivatives
which qualify as hedges are accordingly recorded under hedge
accounting.
Futures and exchange-traded option transactions are recorded as
contractual commitments on a trade-date basis and are carried at fair
value based on closing market quotations. Commodity swaps and forward
transactions are accounted for as contractual commitments on a trade-
date basis and are carried at fair value derived from dealer quotations
and underlying commodity exchange quotations. OTC options purchased and
written are recorded on a trade-date basis and 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 recorded at the lower of cost or market; however
metals inventories continue to be recorded at fair value in accordance
with ARB 43, Restatement and Revision of Accounting Research Bulletins.
20
The carrying values of SET's trading assets and trading liabilities are
as follows:
September 30, December 31,
(Dollars in millions) 2004 2003
- -----------------------------------------------------------------------
Trading Assets
Unrealized gains on swaps and forwards $ 2,063 $ 1,043
OTC commodity options purchased 819 459
Due from trading counterparties 1,699 2,183
Due from commodity clearing organizations
and clearing brokers 270 134
Commodities owned 1,243 1,420
Other 6 1
------- -------
Total $ 6,100 $ 5,240
======= =======
- -----------------------------------------------------------------------
Trading Liabilities
Unrealized losses on swaps and forwards $ 1,883 $ 1,095
OTC commodity options written 397 226
Due to trading counterparties 2,175 2,195
Repurchase obligations 371 866
Commodities not yet purchased -- 56
------- -------
Total $ 4,826 $ 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
September 30, 2004 is represented by their positive fair value after
consideration of collateral. Options written do not expose SET to
credit risk. Exchange traded futures and options are not deemed to have
significant credit exposure since the exchanges guarantee that every
contract will be properly settled on a daily basis.
21
The following table summarizes the counterparty credit quality (as
determined by rating agencies or internal models intended to
approximate rating-agency determinations) and exposure for SET at
September 30, 2004 and December 31, 2003, expressed in terms of net
replacement value. These exposures are net of collateral in the form of
customer margin and/or letters of credit of $1.1 billion and $569
million at September 30, 2004 and December 31, 2003, respectively.
September 30, December 31,
(Dollars in millions) 2004 2003
- -----------------------------------------------------------------------
Counterparty credit quality
Commodity exchanges $ 270 $ 134
AAA 5 5
AA 489 310
A 593 463
BBB 820 345
Below investment grade 562 357
------- -------
Total $ 2,739 $ 1,614
======= =======
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 energy crisis of 2000-2001 caused the California Public
Utilities Commission (CPUC) to adjust its plan for restructuring the
electricity industry. The background of these issues is described in
the Annual Report.
At September 30, 2004, the AB 265 Undercollection had been reduced to
$23 million and SDG&E expects that the undercollection will be
eliminated by the end of 2004.
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.
In October 2003, the CPUC initiated a proceeding to consider a
permanent methodology for allocating the DWR's revenue requirement
beginning in 2004 through the remaining life of the DWR contracts. An
interim allocation based on the current 2003 methodology was utilized
beginning January 1, 2004, and will remain in effect until a decision
is reached on a permanent methodology. In April 2004, Southern
California Edison (Edison), Pacific Gas & Electric (PG&E) and a
northern California consumer advocacy group proposed a limited joint
settlement to allocate the DWR revenue requirement among the investor-
owned utilities (IOUs). This settlement proposes to shift more than $1
billion in additional costs to SDG&E customers and would have a
22
negative impact on customers' commodity costs over the remaining eight-
year life of the DWR contracts. On July 19, 2004, the CPUC issued a
proposed decision and an alternate decision recommending permanent
allocations of DWR contract costs to the IOUs. These proposals were
revised and third and fourth alternate decisions were issued on
September 9, 2004. None of the proposed or alternate decisions would
adopt the settlement; instead, they would permanently allocate a
percentage of the fixed or above market costs of the contracts to SDG&E
for the remaining life of the contracts (2004-2013). The CPUC is
expected to address this matter at its meeting on November 19, 2004.
The judge's proposed decision and Commissioner Lynch's alternate
decision would allocate 12.5 percent of the fixed costs of the
contracts for the remaining term, resulting in a total shift of $1
billion to SDG&E customers. Commissioner Brown's alternate decision
determines SDG&E's share of the above-market costs for all contracts
for all years to be 9.9 percent, resulting in a total shift of $787
million. Commissioner Peevey's alternate decision would allocate 10.3
percent of the fixed costs of the contracts to SDG&E, resulting in a
total shift of $425 million.
Although these proposed decisions would have no effect on SDG&E's net
income, they could adversely affect its customer rates and SDG&E's cash
flows. In the near term the effect on SDG&E's cash flows would be
minor, but could become significant in the later years unless rate
ceilings, imposed by Assembly Bill 1X, which freeze total rates for
most residential customers at the February 2001 level, were increased
to provide more-contemporaneous recovery. Until January 1, 2006, state
law provides SDG&E with a recovery triggering mechanism when an over or
undercollection exceeds approximately $30 million. If the triggering
mechanism is not extended, the CPUC will have discretion on when to act
on over and undercollections.
SDG&E's long-term resource plan identifies the forecasted needs for
capacity resources within its service territory to support transmission
grid reliability. An updated 10-year resource plan was filed on July 9,
2004, in a CPUC proceeding to consider utility resource planning,
including energy efficiency, contracted power, demand response,
qualifying facilities, renewable generation and distributed generation.
SDG&E's updated long-term resource plan incorporates the resources
approved by the CPUC that are discussed below, and recognizes updated
goals to reach a 20-percent renewable resources target by 2010. The
updated plan recommends a 500-kV transmission line addition in 2010,
which would be processed for approval in a subsequent CPUC proceeding.
In order to satisfy SDG&E's recognized near-term need for grid
reliability and capacity, in May 2003 SDG&E issued a Request for
Proposals for the years 2005-2007 for at least 69 MW of electric
capacity in 2005 increasing to 291 MW in 2007.
On June 9, 2004, the CPUC approved SDG&E's entering into five new
electric resource contracts (including two under which SDG&E would take
ownership, on a turnkey basis, of new generating assets, including a
550-MW plant (Palomar) being developed by SER for completion in 2006),
as more fully described in the Annual Report. An additional, demand-
response contract was also approved. The decision authorized SDG&E to
recover the costs of both contracted resources and turnkey resources,
23
but did not adopt SDG&E's specific cost recovery, ratemaking and
revenue requirement proposals for the proposed turnkey resources. On
July 15, 2004, three parties filed requests for rehearing of the
decision. SDG&E filed its response on July 30, 2004, opposing the
requests. The CPUC is expected to rule on the requests in the next few
months. In September 2004, SDG&E filed its revenue requirement and
ratemaking proposals for the 45-MW combustion turbine which SDG&E will
acquire as a turnkey project (Ramco facility) and filed for the Palomar
facility in November 2004. The decision did not approve SDG&E's
proposals for a return on equity (ROE) for SDG&E's new generation
investments higher than SDG&E's ROE on distribution assets, an equity
offset for the debt equivalency of purchase power contracts or an
equity buildup for construction. These matters may be re-introduced for
consideration in future CPUC proceedings.
NATURAL GAS MARKET OIR
The CPUC's Natural Gas Market Order Instituting Rulemaking (OIR) was
instituted on January 22, 2004, and will be addressed in two phases. A
decision on Phase I was issued on September 2, 2004 and the schedule
for Phase II calls for a decision by the end of 2004. Further
discussion of Phase I and Phase II is included in the Annual Report.
The focus of the Gas OIR is the period from 2006 to 2016. Since Natural
Gas Industry Restructuring (GIR), as discussed in the Annual Report,
would end in August 2006 and there is overlap between GIR and the OIR
issues, a number of parties (including SoCalGas) have requested the
CPUC not to implement GIR.
The California Utilities have made comprehensive filings in the OIR
outlining a proposed market structure that is intended to create access
to new natural gas supply sources (such as LNG) for California. In
their Phase I and Phase II filings, 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 also proposed that the capital expenditures
necessary to access new sources of supply be included in ratebase and
that the total amount of the expenditures would be $200 million to $300
million.
The California Utilities also proposed a methodology and framework to
be used by the CPUC for granting pre-approval of new interstate
transportation agreements. The Phase I decision approves the California
Utilities' transportation capacity pre-approval procedures with some
modifications. SoCalGas' existing pipeline capacity contract with
Transwestern Pipeline Company expires in November 2005 and its primary
contracts with El Paso Natural Gas Company expire in August 2006.
Discussions are underway pursuant to the framework approved by the CPUC
to acquire replacement capacity. The Phase I decision also directs the
California Utilities to file, by December 2, 2004, an application to
implement proposals for transmission system integration, firm access
rights, and off-system delivery services. The CPUC has determined that
project developers, not the utilities, will be presumed to pay for the
costs for access-related infrastructure, subject to future applications
to be filed when more is known about the particular projects. Phase II
24
of the Gas Market OIR will review the CPUC's ratemaking policies on
throughput risk to better align these with its objectives of promoting
energy conservation and adequate infrastructure. Phase II will also
investigate the need for emergency natural gas storage reserves and the
role of the utility in backstopping the noncore market.
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 requested revenue increases of $101 million.
As previously reported, in December 2003 the California Utilities filed
with the CPUC proposed settlements of their cost of service
proceedings. The settlements, if approved by the CPUC, would reduce the
California Utilities' annual rate revenues by an aggregate net amount
of approximately $46 million from the rates in effect during 2003. The
CPUC's Office of Ratepayer Advocates (ORA) and most other major parties
to the cost of service proceedings have recommended that the CPUC
approve the settlements.
On September 28, 2004, the CPUC's Administrative Law Judge (ALJ) and
the CPUC Commissioner assigned to the cost of service proceedings
issued differing proposed decisions for consideration by the CPUC. Both
of these proposed decisions recommend that the CPUC reject the proposed
settlements. The ALJ's proposed decision would, if adopted by the CPUC,
increase annual rate revenues by $60 million from that contemplated by
the settlements but would also adopt a one-way balancing account
requiring that any reductions in operating labor costs from those
estimated in establishing rates be refunded to customers. CPUC
Commissioner Wood's alternate proposed decision, which does not include
a one-way labor balancing account, would, if adopted by the CPUC,
increase the annual rate reduction by an additional $24 million from
that contemplated by the proposed settlements.
The company believes that a factual error relating to SDG&E's nuclear
electric rate revenues was applied in the proposed decisions of both
the ALJ and Commissioner Wood. The company also believes that
Commissioner Wood's proposed decision contains a depreciation error
with respect to SDG&E. If these errors and other, minor factual errors
are corrected, they would increase the annual rate revenues that would
be provided by the ALJ's proposed decision to $93 million above that
contemplated by the settlements and would increase the annual rate
revenues that would be provided by Commissioner Wood's alternative
proposed decision to $26 million above that contemplated by the
settlements. Both proposed decisions would approve balancing accounts
for pension costs similar to those contemplated by the settlements and
various other cost balancing accounts not contemplated by the
settlements. All the proposals contemplate that the rates resulting
from the cost of service proceedings would remain effective through
2007 subject to annual attrition adjustments.
The company previously reported that it expects that another CPUC
commissioner will issue an additional proposed decision that, if
adopted by the CPUC, would essentially approve the proposed
settlements. Subsequently, on October 28, 2004, the CPUC at its
regularly scheduled meeting deferred acting on the cost of service
25
proceedings at the request of Commissioner Brown, who stated that he
would issue an additional proposed decision.
The CPUC may adopt any one of the proposed decisions or reject all of
them and adopt a different outcome. The company expects that a CPUC
decision will be issued by year end.
The CPUC previously ordered that any changes in rates resulting from
the cost of service proceedings would be effective retroactively to
January 1, 2004. Consequently, during 2004 the company and the
California Utilities have, in general, recorded revenue and resulting
net income in a manner consistent with the reduced rates contemplated
by the proposed settlements, except for the favorable effect of the
recovery of pension costs contemplated by the proposed settlements and
provided by the proposed decisions. To the extent that the revenues
provided by the CPUC's decision in the cost of service proceedings
differ from those previously recorded, a reconciling adjustment to
revenues and resulting net income would be recorded in the latest
quarter for which financial statements had not been published.
Other ratemaking issues are included in Phase II of the cost of service
proceedings. In addition to recommending changes in the performance-
based regulation (PBR) formulas, the ORA also proposed the possibility
of performance penalties for service quality, safety and electric
service reliability, without the possibility of performance awards.
Hearings took place in June 2004. On July 21, 2004, all of the active
parties in Phase II who dealt with post test year ratemaking and
performance incentives filed for adoption by the CPUC of an all-party
settlement agreement for most of the Phase II issues, including annual
inflation adjustments and revenue sharing. The agreement does not cover
performance incentives. For the interim years of 2005-2007, the
Consumer Price Index would be used to adjust the escalatable authorized
base rate revenues within identified floors and ceilings. It is not
likely that the CPUC will address this matter in its decision related
to Phase II of this proceeding before year-end 2004. Consequently, to
ensure that the results of Phase II would be applicable for a full year
in 2005, SoCalGas and SDG&E filed with the CPUC on September 29, 2004,
a petition to modify a prior decision that provided for the differences
between 2004's rates and the amounts determined in the cost of service
decision to be collected or refunded in future rates, to also apply to
similar differences occurring in 2005 prior to implementation of the
cost of service decision.
The California Utilities had filed for continuation of existing PBR
mechanisms for service quality and safety that would otherwise expire
at the end of 2003. In January 2004, the CPUC issued a decision that
extended 2003 service and safety targets through 2004, but did not
determine the applicability of rewards or penalties. As part of the
proposed Phase II Settlement Agreement, Revenue Sharing, under which
IOUs return to customers a percentage of earnings above specified
levels, would be suspended for 2004 and resume for 2005 through 2007.
The proposed revenue sharing mechanism also provides either utility the
option to file for suspension of the earnings sharing mechanism if
earnings for two consecutive years fall 175 basis points or more below
its authorized rate of return; however, if earnings are 300 or more
basis points above the utility's authorized rate of return, the revenue
sharing mechanism would be automatically suspended and trigger a formal
26
regulatory review by the CPUC to determine whether modification of the
ratemaking mechanism is required.
Edison's CPUC decision on its cost of service application sets rates
for San Onofre Nuclear Generating Station (SONGS), 20 percent of which
is owned by SDG&E. As discussed in the Annual Report, SDG&E's SONGS
ratebase restarted at $0 on January 1, 2004 and, therefore, SDG&E's
earnings from SONGS are now generally limited to a return on new
capital additions. Edison has applied for permission to replace SONGS'
steam generators, which would increase the total cost of SONGS by an
estimated $800 million ($160 million for SDG&E). SDG&E has the option
of not participating in the project and has informed Edison of its
intention to exercise this option. Doing so would reduce SDG&E's
ownership percentage in SONGS by an amount to be determined in
arbitration and will be subject to CPUC review and approval. Such
approval is expected to occur during late 2005. If the proposed
reduction of SDG&E's ownership percentage resulting from the
arbitration is unacceptable, SDG&E may elect to participate in the
replacement project.
During the current SONGS Unit 3 refueling outage, Edison reported that it had
performed inspections of two pressurizer sleeves and found evidence of
degradation. Degradation of the pressurizer sleeves has been a concern in the
nuclear industry for some time. Edison had been planning to replace all of
the sleeves in Units 2 and 3 during the next refueling for each unit in 2005
and 2006, but has reported its intention to move the planned replacement of
Unit 3's pressurizer sleeves forward from 2006 to the current outage. This
extra work will lengthen the current outage from 55 days to a range of 95 to
110 days, but allows Edison to move the 2006 refueling outage out of the peak
summer period to the fall or winter of 2006. Edison has reported that it will
incur about $9 million of capital expenditures during 2005 that otherwise
would have occurred in 2006. SDG&E's share would be approximately $2 million.
Edison plans to replace the pressurizer sleeves in Unit 2 during its next
scheduled outage in 2005.
Also during the current outage, Edison reported that it had conducted a
planned inspection of the Unit 3 reactor vessel head and found indications of
degradation. Although the degradation is far below the level at which leakage
would occur, Edison plans to make repairs during the current outage. While
Edison reports that this is the first experience at SONGS of this kind of
degradation to the reactor vessel heads, the detection and repair of similar
degradation at other plants are now common in the industry. Edison reports
that it plans to replace the Unit 2 and Unit 3 reactor vessel heads during
refueling outages in 2009-2010.
PERFORMANCE-BASED REGULATION
As further described in the Annual Report, under PBR, the CPUC requires
future income potential to be tied to achieving or exceeding specific
performance and productivity goals, rather than relying solely on
expanding utility plant to increase earnings. PBR, demand-side
management (DSM) and Gas Cost Incentive Mechanism (GCIM) rewards are
not included in the company's earnings before CPUC approval is
received.
The only incentive rewards approved during the nine months ended
September 30, 2004 consisted of $6.3 million related to SoCalGas' Year
27
9 GCIM, which was approved on February 26, 2004 and $1.5 million
related to SDG&E's Year 10 natural gas PBR, which was approved on
August 22, 2004. These rewards were awarded by the CPUC subject to
refund based on the outcome of the Border Price Investigation, as
discussed below. The cumulative amount of rewards subject to refund
based on the outcome of the Border Price Investigation is $65.1
million, substantially all of which has been included in net income.
At September 30, 2004, the following performance incentives were
pending CPUC approval and, therefore, were not included in the
company's earnings (dollars in millions):
Program SoCalGas SDG&E Total
- -----------------------------------------------------------
DSM/Energy Efficiency* $ 10.9 $ 37.7 $ 48.6
2003 Distribution PBR -- 8.2 8.2
GCIM/natural gas PBR 2.4 -- 2.4
2003 safety .5 -- .5
- -----------------------------------------------------------
Total $ 13.8 $ 45.9 $ 59.7
- -----------------------------------------------------------
* Dollar amounts shown do not include interest, franchise fees or
uncollectible amounts.
SOUTHERN CALIFORNIA FIRES
Several major wildfires that began on October 26, 2003 severely damaged
SDG&E's infrastructure, causing a significant number of customers to be
without utility services. On October 27, 2003, then governor Gray Davis
declared a State of Emergency for the State of California. The
declaration authorized the establishment of catastrophic event
memorandum accounts (CEMA) to record all incremental costs (costs not
already included in rates) associated with the repair of facilities and
the restoration of service. Incremental electric distribution and
natural gas related costs are recovered through the CEMA. Electric
transmission related costs are recovered through the annual FERC true-
up proceeding. Incremental costs incurred related to the wildfires and
recoverable through the CEMA were $38 million.
On June 28, 2004, SDG&E filed its CEMA application with the CPUC to
recover incremental operating and maintenance and capital costs of its
natural gas and electric distribution systems associated with the
fires. In that application, SDG&E is requesting a 2005 revenue
requirement of $20 million, representing the operating and maintenance
costs of $12 million plus the 2004 and 2005 ongoing annual amounts of
$4 million to recover the $26 million of capital costs and the
authorized return thereon. The company expects no significant effect on
earnings from the fires. The ALJ indicated that he expects to issue a
proposed decision by the end of the first quarter of 2005.
SoCalGas did not file a CEMA application as damages incurred as a
result of the wildfires were minimal.
COST OF CAPITAL
Effective January 1, 2005, SDG&E's authorized return on rate base (ROR)
and return on equity (ROE) will be 8.18 percent and 10.37 percent,
28
respectively, for its electric distribution and natural gas businesses,
down from 8.77 percent and 10.9 percent, respectively. The decrease is
a result of the CPUC's automatic triggering mechanism, which resets
these rates whenever Moody's Aa utility bond yield as published by
Mergent Bond Record changes by more than a specified amount. The new
benchmark will be 6.19 percent and another automatic adjustment would
be triggered if the Mergent Aa utility bond yield were to average less
than 5.19 percent or greater than 7.19 percent during the April -
September timeframe of any given year. If the cost of service
proceeding described above is decided by the CPUC along the lines of
the settlement, the effect of the changes in ROR and ROE would be to
decrease net income in 2005 by $10 million from what it would have been
if the rates had not changed. The electric-transmission cost of capital
is determined under a FERC proceeding.
Effective January 1, 2003, SoCalGas' authorized ROE is 10.82 percent
and its ROR is 8.68 percent. These rates are subject to automatic
adjustment if 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 a benchmark,
which is currently 5.38 percent. The 12-month trailing average was 5.10
percent and the Global Insight forecast was 5.84 percent at September
30, 2004.
BIENNIAL COST ALLOCATION PROCEEDING (BCAP)
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 sales
volumes 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 in the Annual Report, on May 27, 2004 the ALJ in
the 2005 BCAP issued a decision dismissing the BCAP applications. The
California Utilities are required to file new BCAP applications after
the stay of the GIR implementation decision is lifted. As a result of
the deferrals and the significant decline forecasted in noncore gas
throughput on SoCalGas' system, in December 2002 the CPUC issued a
decision approving 100 percent balancing account protection for
SoCalGas' risk on local transmission and distribution revenues from
January 1, 2003 until the CPUC issues its next BCAP decision. SoCalGas
is seeking to continue this balancing account protection in the Natural
Gas OIR proceeding.
BORDER PRICE INVESTIGATION
In November 2002, the CPUC instituted an investigation into the
Southern California natural gas market and the price of natural gas
delivered to the California - Arizona border between March 2000 and May
2001. The California Utilities are the parties to the first phase of
the investigation. If the investigation were to determine that the
conduct of either of the California Utilities contributed to the
natural gas price spikes that occurred during the investigation period,
29
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. At
September 30, 2004, the cumulative amount of shareholder awards,
substantially all of which has been included in net income, was $65.1
million. The ORA has filed testimony supporting the GCIM and the
actions of SoCalGas during this period. The first phase of this
investigation was reopened for one day on October 25, 2004, for
additional testimony and supplemental opening and reply briefs. While
the ALJ stated that a proposed decision is not imminent, the company
expects that a proposed decision will be issued before year end for
consideration by the CPUC. Although the proposed decision may be
adverse to it, the company believes it is unlikely that the full CPUC
would adopt any such adverse decision and would instead conclude that
the California Utilities were not responsible for any natural gas price
spikes. A final CPUC decision in the first phase of the investigation
is not expected until 2005. The CPUC may hold additional rounds of
hearings to consider whether other companies, including other
California utilities as well as the company and its non-utility
subsidiaries, contributed to the natural gas price spikes.
CPUC INVESTIGATION OF ENERGY-UTILITY HOLDING COMPANIES
The CPUC has initiated an investigation into the relationship between
California's IOUs and their parent holding companies. The CPUC broadly
determined that it could, in appropriate circumstances, require the
holding company to provide cash to a utility subsidiary to cover its
operating expenses and working capital to the extent they are not
adequately funded through retail rates. This would be in addition to
the requirement of holding companies to provide for their utility
subsidiaries' capital requirements, as the IOUs previously acknowledged
in connection with the holding companies' formations. In January 2002,
the CPUC ruled that it had jurisdiction to create the holding company
system and, therefore, retains jurisdiction to enforce conditions to
which the holding companies had agreed.
In an opinion issued May 21, 2004, the California Court of Appeal
upheld the CPUC's assertion of limited enforcement jurisdiction, but
concluded that the CPUC's interpretation of the "first priority"
condition (that the holding companies could be required to infuse cash
into the utilities as necessary to meet the utilities' obligation to
serve) was not ripe for review. In September 2004, the California
Supreme Court declined to review the California Court of Appeal's
decision.
RECOVERY OF CERTAIN DISALLOWED TRANSMISSION COSTS
The Federal Court of Appeals scheduled completion of briefing by
February 9, 2005, and set oral argument for April 14, 2005, concerning
SDG&E's recovery of the differentials between certain payments to SDG&E
by its co-owners of the Southwest Powerlink (SWPL) and charges assessed
to SDG&E under the California Independent System Operator (ISO) FERC
tariff for transmission line losses, and grid management and other
charges related to energy schedules of its SWPL co-owners. The parties
in the related private arbitration have agreed to hold the arbitration
in abeyance pending resolution of the FERC tariff proceeding.
30
FERC ACTIONS
Refund Proceedings
The FERC is investigating prices charged to buyers in the California
Power Exchange (PX) and ISO markets by various electric suppliers. The
FERC is seeking to determine the extent to which individual sellers
have yet to be paid for power supplied during the period of October 2,
2000 through June 20, 2001 and to estimate the amounts by which
individual buyers and sellers paid and were paid in excess of
competitive market prices. Based on these estimates, the FERC could
find that individual net buyers, such as SDG&E, are entitled to refunds
and individual net sellers, such as SET, are required to provide
refunds. To the extent any such refunds are actually realized by SDG&E,
they would be refunded to ratepayers. 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 reduced 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 for the
October 2, 2000 through June 20, 2001 period (the $3.0 billion that the
California PX and ISO still owe energy companies less $1.8 billion that
the energy companies charged California customers in excess of the
preliminarily determined competitive market clearing prices). On March
26, 2003, the FERC adopted its ALJ's findings, but changed the
calculation of the refund by basing it on a different estimate of
natural gas prices. The March 26 order estimates that the replacement
formula for estimating natural gas prices will increase the refund
obligations from $1.8 billion to more than $3 billion for the same time
period. Pending in the Ninth Circuit are various parties' appeals on
aspects of the FERC's order.
In a series of orders in 2004, the FERC has provided further direction
and clarifications regarding the methodology to be used by the ISO and
PX to recalculate the precise refund obligations and entitlements
through their settlement models.
SET previously established reserves for its likely share of the
original $1.8 billion discussed above. During the nine months ended
September 30, 2004, SET recorded additional reserves to reflect the
estimated effect of the FERC's revision of the benchmark prices to be
used by the FERC to calculate refunds.
In a separate complaint filed with the FERC in 2002, the California
Attorney General challenged the FERC's authority to establish a market-
based rate regime, and further contended that, even if such a regime
were valid, electricity sellers had failed to comply with the FERC's
quarterly reporting requirements. The Attorney General requested that
the FERC order refunds from suppliers to the California PX and ISO for
the period prior to October 2, 2000, and for short-term bilateral
transactions entered into with the California Energy Resources
Scheduler. In May 2003, and upon rehearing in September 2003, the FERC
dismissed the complaint, determining that its market-based rate system
was lawful, and that refunds for non-compliance with its reporting
requirements were unnecessary, and instead ordered sellers to restate
31
their reports. After an appeal by the California Attorney General, in
September 2004, the Ninth Circuit Court of Appeals upheld the FERC's
authority to establish a market-based rate regime, but ordered remand
of the case to the FERC for further proceedings, stating that failure
to file transaction-specific quarterly reports gave the FERC authority
to order refunds with respect to jurisdictional sellers. In October
2004, the FERC announced that it will not appeal the court's decision.
Although a group of sellers has requested the Ninth Circuit to rehear
this matter, the timing and substance of the FERC's response to the
remand is not yet known. However, it is possible that the FERC could
order "refunds" or disgorgement of profits for periods in addition to
those covered by its prior refund orders and substantially increase the
refunds that ultimately may be required to be paid by SET and other
power suppliers.
Manipulation Investigation
The FERC is separately investigating whether there was manipulation of
short-term energy markets in the western United States 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 periods 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 (generally described as manipulating or
"gaming" the California energy markets) in violation of the PX and ISO
tariffs.
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, the 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, in partnership or alliance with others, 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
various entities to settle these issues. On October 31, 2003, SET
agreed to pay $7.2 million in full resolution of these investigations.
That liability was recorded as of December 31, 2003. The SET settlement
was approved by the FERC on August 2, 2004. SDG&E and the FERC resolved
the matter through a settlement, which documents the ISO's finding that
SDG&E did not engage in market activities in violation of the ISO or PX
tariffs, and in which SDG&E agreed to pay $27,792 into a FERC-
established fund.
NOTE 7. CONTINGENCIES
NUCLEAR INSURANCE
SDG&E and the other owners of SONGS have insurance to respond to
nuclear liability claims related to SONGS. Detail of the coverage is
provided in the Annual Report. As of September 30, 2004, the secondary
32
financial protection provided by the Price-Anderson Act is $10.5
billion if the liability loss exceeds the insurance limit of $300
million. In addition, the maximum SDG&E could be assessed is $8.8
million should there be a retrospective premium call under the risk
sharing arrangements of the nuclear property, decontamination and
debris removal insurance policy.
Both the nuclear liability and property insurance programs subscribed
to by members of the nuclear power generating industry include industry
aggregate limits for non-certified acts, as defined by the Terrorism
Risk Insurance Act, of terrorism-related SONGS losses, including
replacement power costs. An industry aggregate limit of $300 million
exists for liability claims, regardless of the number of non-certified
acts affecting SONGS or any other nuclear energy liability policy or
the number of policies in place. An industry aggregate limit of $3.24
billion exists for property claims, including replacement power costs,
for non-certified acts of terrorism affecting SONGS or any other
nuclear energy facility property policy within twelve months from the
date of the first act. These limits are the maximum amount to be paid
to members who sustain losses or damages from these non-certified
terrorist acts. For certified acts of terrorism, the individual policy
limits stated above apply.
SPENT NUCLEAR FUEL
SONGS owners have responsibility for the interim storage of spent
nuclear fuel generated at SONGS until it is accepted by the DOE for
final disposal. Spent nuclear fuel is stored in the SONGS Units 1, 2
and 3 Spent Fuel Pools (SFP) and the SONGS Independent Spent Fuel
Storage Installation (ISFSI). Movement of Unit 1 spent fuel from the
Unit 3 SFP to the ISFSI was completed in late 2003. Movement of Unit 1
spent fuel from the Unit 1 SFP to the ISFSI is scheduled to be
completed by the end of 2004 and from the Unit 2 SFP to the ISFSI by
late 2005. With these moves, there will be sufficient space in the Unit
2 and 3 SFPs to meet plant requirements through mid-2007 and mid-2008,
respectively.
ARGENTINE INVESTMENTS
As a result of the devaluation of the Argentine peso at the end of 2001
and subsequent declines in the value of the peso, SEI reduced the
carrying value of its Argentine investments downward by a cumulative
total of $199 million as of September 30, 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 by the end of 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 SEI's investments that has resulted from Argentine governmental
actions. Sempra Energy also has a $48.5 million political-risk
insurance policy under which it filed a claim to recover a portion of
the investments' diminution in value.
33
LITIGATION
Except for the matters referred to below, neither the company nor its
subsidiaries are party to, nor is their property the subject of, any
material pending legal proceedings other than routine litigation
incidental to their businesses. Management believes that none of these
matters will have further material adverse effect on the company's
financial condition or results of operations.
DWR Contract
In 2003, SER was awarded judgment in its favor in the state civil
action between SER and the DWR, in which the DWR sought to void its 10-
year contract under which the company sells energy to the DWR. The DWR
filed an appeal of this ruling in January 2004. A decision by the
appellate court is expected during 2005.
The DWR continues to accept scheduled power from SER and, although it
has disputed a small percentage of the billings and the manner of
certain deliveries, it has paid all amounts that have been billed under
the contract. However, the DWR has commenced an arbitration proceeding,
disputing SER's performance on various operational matters. Among other
proposed remedies, the DWR has requested a declaration by the
arbitration panel that SER's performance is inadequate and constitutes
a material breach of the agreement permitting it to terminate the
contract. SER believes these claims are without merit and has filed a
motion to dismiss claims in the arbitration proceeding. Arbitration on
any remaining claims will occur in mid-2005.
On June 25, 2003, the FERC issued orders upholding SER's 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 CPUC 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. Oral
argument on the appeal has been scheduled for December 2004, with a
decision by the appellate court expected during 2005.
Energy Crisis Litigation
In 2000 and 2001, California experienced a severe energy crisis
characterized by dramatic increases in the prices of electricity and
natural gas. Many, often duplicative, lawsuits have been filed against
numerous energy companies seeking overlapping damages aggregating in
the tens of billions of dollars for allegedly unlawful activities
asserted to have caused or contributed to the energy crisis. In
34
addition, the energy crisis has generated numerous governmental
investigations and regulatory proceedings. The company is cooperating
in various investigations, including an investigation being conducted
by the California Attorney General into possible anti-competitive
behavior. The material regulatory proceedings arising out of the energy
crisis that involve the company are briefly summarized, along with
other proceedings, in Note 6 and this Note 7. The lawsuits arising out
of the energy crisis to which the company is a defendant are briefly
summarized below.
Natural Gas Cases
Class-action and individual antitrust and unfair competition lawsuits
filed in 2000 and thereafter, and currently consolidated in San Diego
Superior Court seek damages, alleging that Sempra Energy, SoCalGas and
SDG&E, along with El Paso Natural Gas Company (El Paso) and several of
its affiliates, unlawfully sought to control natural gas and
electricity markets. In December 2003, the Court approved a settlement
whereby the applicable El Paso entities (including cases involving
unrelated claims not applicable to Sempra Energy, SoCalGas or SDG&E)
will pay approximately $1.7 billion to resolve these claims. The
proceeding against Sempra Energy and the California Utilities has not
been settled and continues to be litigated. During the third quarter of
2004, the court denied motions by Sempra Energy and the California
Utilities for summary judgment in their favor. Sempra Energy and the
California Utilities have requested the Court of Appeal to review these
denials; however, such an interim review pending a final decision on
the merits of the case is entirely at the discretion of the appellate
court. In October 2004, certain of the plaintiffs issued a news release
asserting that they could recover as much as $24 billion from Sempra
Energy and the California Utilities if their allegations were upheld at
trial. The trial of the case was previously set for September 2004 but
has been postponed and the newly assigned judge has yet to schedule a
new trial date. (The original judge is retiring at year end.)
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. The claims against the Sempra Energy
defendants in the Arizona lawsuit were settled in September 2004 for
$150,000 and have been dismissed with prejudice.
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 recovery
of damages alleged to aggregate in excess of $150 million (before
trebling) from an alleged conspiracy to drive up or control natural gas
prices, eliminate competition and increase market volatility, breach of
contract and wire fraud. On January 27, 2004, the U.S. District Court
dismissed the Sierra Pacific Resources case against all of the
defendants, determining that this is a matter for the FERC to resolve.
However, the court granted plaintiffs' request to amend their
complaint, which they have done and Sempra Energy has filed another
motion to dismiss, which is scheduled to be heard on November 29, 2004.
35
In May 2003 and February 2004, antitrust actions against various trade
publications and energy companies, including Sempra Energy and SET,
alleging that energy prices were unlawfully manipulated by defendants'
reporting artificially inflated natural gas prices to trade
publications and by entering into wash trades, were filed in San Diego
Superior Court. Both actions have been removed to U.S. District Court.
In November 2003, an additional suit was filed in U.S. District Court.
In September 2004, two additional lawsuits alleging substantially
identical claims were filed against Sempra Energy and SET, among
various other entities in San Diego Superior and U.S. District Courts.
In July 2004, the City and County of San Francisco, the County of Santa
Clara and the County of San Diego brought similar actions in San Diego
Superior Court against various entities, including Sempra Energy, SET,
SoCalGas and SDG&E. Three identical lawsuits were filed in October 2004
in the Alameda and San Mateo Superior Courts.
In August 2003, a lawsuit was filed in the Southern District of New
York against Sempra Energy and its subsidiary, Sempra Energy Solutions
(SES), alleging that the prices of natural gas options traded on the
New York Mercantile Exchange (NYMEX) were unlawfully increased under
the Federal Commodity Exchange Act by defendants' manipulation of
transaction data provided to natural gas trade publications. In
November of 2003, another suit containing identical allegations was
filed and consolidated with the New York action. Subsequently,
plaintiffs dismissed Sempra Energy and SES from these cases. On January
20, 2004, plaintiffs filed an amended consolidated complaint that named
SET as a defendant in this lawsuit. In March 2004, defendants filed a
motion to dismiss the action, which was denied by the court in
September 2004. In October 2004, plaintiffs amended their complaint to
allege that SET had engaged in natural gas wash trade transactions.
Electricity Cases
Various antitrust lawsuits, which seek class-action certification,
allege that numerous entities, including Sempra Energy and certain
subsidiaries (SDG&E, SET and SER, depending on the lawsuit), that
participated in the wholesale electricity markets unlawfully
manipulated those markets. Collectively, these lawsuits allege damages
against all defendants in an aggregate amount in excess of $16 billion
(before trebling). In January 2003, the federal court granted a motion
to dismiss one of these lawsuits, filed by Snohomish County, Washington
Public Utility District, on the grounds that the claims contained in
the complaint were subject to the filed rate doctrine and were
preempted by the Federal Power Act. That ruling was appealed to the
Ninth Circuit U.S. Court of Appeals. In addition, in May 2003, the Port
of Seattle filed a similar complaint against a number of energy
companies (including Sempra Energy, SER and SET). That action was
dismissed by the San Diego U.S. District Court in May 2004. Plaintiff
has appealed the decision. In May and June 2004 two lawsuits
substantially identical to the Port of Seattle case was filed in
Washington and Oregon U.S. District Courts. These cases were
transferred to the San Diego U.S. District Court and motions to dismiss
them have been filed. In October 2004 another case was filed in Santa
Clara Superior Court against SER, alleging substantively identical
claims to those in the Port of Seattle case.
36
In September 2004, the Ninth Circuit U.S. Court of Appeals dismissed
the suit against the company, SET and SER, by Snohomish County,
Washington Public Utility District. The court ruled that the FERC, not
civil courts, has exclusive jurisdiction over the matter. The company
believes that this decision provides a precedent for the dismissal on
the basis of federal preemption and the filed rate doctrine of the
other lawsuits against the Sempra Energy companies claiming
manipulation of the electricity markets.
Other Litigation
The Utility Consumers' Action Network (UCAN), a consumer-advocacy group
which had requested a CPUC rehearing of a CPUC decision concerning the
allocation of certain power contract gains between SDG&E customers and
the company, appealed the CPUC's rehearing denial to the California
Court of Appeal. On July 12, 2004, the Court of Appeal affirmed the
CPUC's decision. On August 20, 2004, UCAN filed a Petition for Review
in the California Supreme Court. The Supreme Court has not yet
determined whether it will grant review.
In May 2003, a federal judge issued an order finding that the
Department of Energy's (DOE) environmental assessment of two Mexicali
power plants, including SER's Termoelectrica de Mexicali (TDM) plant,
failed to evaluate the plants' environmental impact adequately and
called into question the U.S. permits they received to build their
cross-border transmission lines. In July 2003, the judge ordered the
DOE to conduct additional environmental studies and denied the
plaintiffs' request for an injunction blocking operation of the
transmission lines, thus allowing the continued operation of the TDM
plant. The DOE undertook to perform an Environmental Impact Study,
which is expected to be completed in December 2004.
The Peruvian appellate court has affirmed the dismissal of the charges
against officers of Luz del Sur S.A.A. (Luz del Sur), a company
affiliate, and others concerning the price of utility assets acquired
by Luz del Sur from the Peruvian government. However, the Peruvian tax
authorities continue to claim that Luz de Sur owes additional income
taxes related to the disputed valuation. Hearings are scheduled for
November 10, 2004.
At September 30, 2004, SET remains due approximately $100 million from
energy sales made in 2000 and 2001 through the ISO and the PX markets.
The collection of these receivables depends on several factors,
including the FERC refund case. The company believes adequate reserves
have been recorded.
INCOME TAX ISSUES
Section 29 Income Tax Credits
On July 1, 2004, SEF sold its investment in an enterprise that earns
Section 29 income tax credits. That investment comprised one-third of
Sempra Energy's Section 29 participation and was sold because the
company's alternative minimum tax position defers utilization of the
credits in the determination of income taxes currently payable. The
transaction has been accounted for under the cost recovery method,
whereby future proceeds in excess of the carrying value of the
37
investment will be recorded as income as received. As a result of this
sale, SEF will not be receiving Section 29 income tax credits in the
future.
During the third quarter of 2004, the IRS concluded its examinations of
the company's Section 29 income tax credits for certain years,
reporting no change in the credits. From acquisition of the facilities
in 1998 through December 31, 2003, the company has generated Section 29
income tax credits of $251 million. In addition, the company has
generated Section 29 tax credits of $75 million for the nine months
ended September 30, 2004, of which $24 million occurred in the third
quarter.
If the recent increases in oil prices continue and do not reverse, a
partial or complete phase out of Section 29 tax credits may occur in
2005 or in subsequent years in accordance with Section 29 regulations.
NOTE 8. SEGMENT INFORMATION
The company is a holding company, whose subsidiaries are primarily
engaged in the energy business. It has four separately managed
reportable segments: SoCalGas, SDG&E, SET and SER, which are described
in the Annual Report.
The accounting policies of the segments are described in the notes to
Consolidated Financial Statements in the Annual Report, and segment
performance is evaluated by management based on reported income. There
were no significant changes in segment assets during the nine months
ended September 30, 2004.
- -----------------------------------------------------------------------
Three months ended Nine months ended
September 30, September 30,
------------------- ------------------
(Dollars in millions) 2004 2003 2004 2003
- -----------------------------------------------------------------------
Operating Revenues:
Southern California Gas $ 826 $ 794 $ 2,821 $ 2,622
San Diego Gas & Electric 550 667 1,666 1,749
Sempra Energy Trading 355 304 981 832
Sempra Energy Resources 413 234 1,101 453
All other 84 74 215 206
Intersegment revenues (63) (15) (263) (41)
------------------------------------------
Total $ 2,165 $ 2,058 $ 6,521 $ 5,821
- -----------------------------------------------------------------------
Net Income (Loss):
Southern California Gas* $ 68 $ 53 $ 174 $ 148
San Diego Gas & Electric* 60 120 140 206
Sempra Energy Trading 44 22 143 39
Sempra Energy Resources 64 33 123 48
All other (5) (17) (31) (26)
------------------- ----------------------
Total $ 231 $ 211 $ 549 $ 415
- -----------------------------------------------------------------------
* after preferred dividends
38
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, "Management's Discussion and Analysis
of Financial Condition and Results of Operations" contained in the Annual
Report and "Risk Factors" contained in the Form 10-K.
OVERVIEW
Sempra Energy is a Fortune 500 energy services holding company. Its business
units provide a wide spectrum of value-added electric and natural gas
products and services to a diverse range of customers. Operations are divided
between delivery services, comprised of the California Utilities, and Sempra
Energy Global Enterprises.
39
RESULTS OF OPERATIONS
Net income and operating income for the three months and for the nine
months ended September 30, 2004 were up substantially from the
corresponding periods of 2003. The following table summarizes the major
factors affecting the comparisons for both periods.
<table>
<caption>
--------------------------------------------
Nine Months Three Months
- ----------------------------------------------------------------------------------------
Operating Net Operating Net
(Dollars in millions) Income Income Income Income
- ----------------------------------------------------------------------------------------
<s> <c> <c> <c> <c>
Reported amounts for the periods ended
September 30, 2003 $ 725 $ 415 $ 307 $ 211
Unusual items in 2003:
SDG&E power contract settlement (116) (65) (116) (65)
Impairment of Frontier Energy assets 77 47 77 47
California energy crisis litigation costs and
SoCalGas sublease losses 74 43 74 43
SoCalGas' natural gas procurement awards (48) (29) (48) (29)
Cumulative effect of EITF 02-3 through
December 31, 2002 -- 29 -- --
SONGS incentive pricing (ended 12/31/03) (65) (38) (18) (11)
Resolution of vendor disputes in Argentina -- (11) -- --
AEG income in 2003 - disposed of
in April 2004 -- (2) -- (7)
------------------------------------------
647 389 276 189
Unusual items in 2004:
Losses of AEG - disposed of in April 2004 -- (32) -- --
Income tax audit issues -- 18 -- (5)
Resolution of vendor disputes in Argentina -- 12 -- --
Unusual litigation expenses (16) (10) -- --
SoCalGas' gain on sale of partnership
property -- 9 -- 9
Gain on settlement of Cameron
liability -- 8 -- --
Gain on partial sale of Luz del Sur -- 5 -- --
Operations (2004 compared to 2003) 266 150 69 38
--------------------------------------------
Reported amounts for the periods ended
September 30, 2004 $ 897 $ 549 $ 345 $ 231
- ----------------------------------------------------------------------------------------
</table>
California Utility Revenues and Cost of Sales
Natural gas revenues increased to $3.2 billion for the nine months
ended September 30, 2004 from $3.0 billion for the corresponding period
in 2003, and the cost of natural gas increased to $1.7 billion in 2004
from $1.5 billion in 2003. Additionally, natural gas revenues were $909
million for the quarter ended September 30, 2004 compared to $870
million for the corresponding period in 2003, and the cost of natural
gas was $438 million in 2004 compared to $372 million in 2003. These
increases were primarily attributable to natural gas cost increases,
which are passed on to customers, offset by $55 million and $48
million, respectively, of approved performance awards recognized during
the nine-month and three-month periods ended September 30, 2003.
40
Electric revenues decreased to $1.2 billion for the nine months ended
September 30, 2004 from $1.4 billion for the same period in 2003, and
the cost of electric fuel and purchased power decreased to $425 million
in 2004 from $428 million in 2003. Additionally, electric revenues
decreased to $445 million for the quarter ended September 30, 2004 from
$576 million for the same period in 2003, and the cost of electric fuel
and purchased power increased to $143 million in 2004 from $128 million
in 2003. The decreases in revenues were due to the recognition of $116
million related to the approved settlement of intermediate-term
purchase power contracts in the third quarter of 2003, more power being
provided to SDG&E's customers by the DWR in 2004 as discussed in Note 6
of the notes to Consolidated Financial Statements, and higher earnings
from PBR awards in 2003. The decrease in the cost of electric fuel and
purchased power for the nine-month period was mainly due to more power
being provided by the DWR, while the increase for the three-month
period was due to higher electric commodity costs partially offset by
more power being provided by the DWR. Under the current regulatory
framework, changes in commodity costs normally do not affect net
income.
Performance awards are discussed in Note 6 of the notes to Consolidated
Financial Statements.
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
and in Note 6 of the notes to Consolidated Financial Statements. In
accordance with generally accepted accounting principles, the
California Utilities are generally recognizing 2004 revenue in a manner
consistent with the reduced rates contemplated by the proposed
settlements, except for the favorable effect of the recovery of pension
costs contemplated by the proposed settlements and provided by both
proposed decisions. To the extent that the revenues provided by the
CPUC's decision in the cost of service proceedings differ from those
previously recorded, a reconciling adjustment to revenues and resulting
net income would be recorded in the latest quarter for which financial
statements had not been published. To date, the impacts of accounting
consistent with the settlement have not had a material effect on the
financial statements.
The tables below summarize the natural gas and electric volumes and
revenues by customer class for the nine months ended September 30, 2004
and 2003.
41
<table>
Natural Gas Sales, Transportation and Exchange
(Volumes in billion cubic feet, dollars in millions)
<caption>
Gas Sales Transportation & Exchange Total
----------------------------------------------------------------
Volumes Revenue Volumes Revenue Volumes Revenue
----------------------------------------------------------------
<s> <c> <c> <c> <c> <c> <c>
2004:
Residential 197 $ 1,943 1 $ 5 198 $ 1,948
Commercial and industrial 91 718 207 141 298 859
Electric generation plants -- -- 190 67 190 67
Wholesale -- -- 13 5 13 5
---------------------------------------------------------------
288 $ 2,661 411 $ 218 699 2,879
Balancing accounts and other 310
--------
Total $ 3,189
- -------------------------------------------------------------------------------------------
2003:
Residential 189 $ 1,767 1 $ 5 190 $ 1,772
Commercial and industrial 90 649 209 138 299 787
Electric generation plants -- 3 186 61 186 64
Wholesale -- -- 14 2 14 2
---------------------------------------------------------------
279 $ 2,419 410 $ 206 689 2,625
Balancing accounts and other 336
--------
Total $ 2,961
- -------------------------------------------------------------------------------------------
</table>
<table>
Electric Distribution and Transmission
(Volumes in millions of kilowatt hours, dollars in millions)
<caption>
2004 2003
-----------------------------------------
Volumes Revenue Volumes Revenue
-----------------------------------------
<s> <c> <c> <c> <c>
Residential 5,242 $ 518 4,988 $ 561
Commercial 4,960 487 4,681 526
Industrial 1,533 98 1,460 125
Direct access 2,560 77 2,456 62
Street and highway lighting 71 8 68 8
Off-system sales -- - 26 1
-----------------------------------------
14,366 1,188 13,679 1,283
Balancing accounts and other 58 85
-----------------------------------------
Total $ 1,246 $ 1,368
-----------------------------------------
</table>
Although commodity-related revenues from the DWR's purchasing of
SDG&E's net short position or from the DWR's allocated contracts are
not included in revenue, the associated volumes and distribution
revenue are included herein.
42
Beginning in 2004, off-system sales are accounted for as a reduction of
the cost of purchased power.
Other Operating Revenues
Other operating revenues, which consist primarily of revenues at
Global, increased to $2.1 billion for the nine months ended September
30, 2004 from $1.5 billion for the same period of 2003, and increased
to $811 million for the quarter ended September 30, 2004 from $612
million for the same period of 2003. These increases were primarily due
to higher revenues at SER resulting from increased volumes of power
sales under the DWR contract and higher revenues at SET resulting from
increased commodity revenue, particularly from metals and petroleum.
Other Cost of Sales
Other cost of sales, which consists primarily of cost of sales at
Global, increased to $1.2 billion for the nine months ended September
30, 2004 from $886 million for the same period of 2003, and increased
to $484 million for the quarter ended September 30, 2004, from $371
million for the same period in 2003. The increases were primarily due
to costs related to the higher sales volume for SER as noted above.
Other Operating Expenses
Other operating expenses were $1.6 billion for the nine-month periods
ended September 30, 2004 and 2003, including $1.1 billion in both 2004
and 2003 related to the California Utilities. Other operating expenses
decreased to $530 million for the quarter ended September 30, 2004 from
$668 million for the same period in 2003, including $351 million and
$423 million in 2004 and 2003, respectively, related to the California
Utilities. The overall change was primarily due to lower costs at SEI
mainly due to a $77 million before-tax write-down of the carrying value
of the assets of Frontier Energy in the third quarter of 2003.
Additionally, there were lower costs at the California Utilities,
primarily as a result of a $74 million before-tax charge in the third
quarter of 2003 for litigation and for losses associated with a
sublease of portions of the SoCalGas headquarters building. These
decreases were offset by higher operating costs at SET related to
increased trading activity in 2004, the new SER generating plants
coming on line and litigation expenses in 2004.
Other Income - Net
Other income, which primarily consists of equity earnings from
unconsolidated subsidiaries and interest on regulatory balancing
accounts, increased to $58 million for the nine months ended September
30, 2004 from $38 million for the same period of 2003, and increased to
$40 million for the quarter ended September 30, 2004 from $34 million
for the same period of 2003. The increases were due to the $15 million
before-tax gain at SoCalGas from the sale of partnership property,
lower equity losses at SEF and increased equity earnings at SER
resulting from the acquisition of the Coleto Creek coal plant, offset
partially by decreased equity earnings at SEI. In addition, the nine-
month period was impacted by the $13 million before-tax gain on 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
43
been recorded as a derivative) and $7 million before-tax at SEI from
the partial sale of Luz del Sur in 2004.
Interest Income
Interest income increased to $58 million for the nine months ended
September 30, 2004 from $30 million for the same period of 2003, and
increased to $25 million for the quarter ended September 30, 2004 from
$8 million for the same period of 2003. The changes were due primarily
to interest on income tax receivables during the first and third
quarters of 2004.
Interest Expense
Interest expense increased to $234 million for the nine months ended
September 30, 2004 from $223 million for the same period of 2003 due
primarily to the reclassification of preferred dividends on mandatorily
redeemable trust preferred securities and preferred stock of
subsidiaries to interest expense as a result of the adoption on July 1,
2003 of SFAS 150, Accounting for Certain Financial Instruments with
Characteristics of Liabilities and Equity, as well as higher
capitalized interest at SER in 2003.
Income Taxes
Income tax expense increased to $191 million for the nine months ended
September 30, 2004 from $109 million for the same period of 2003. The
corresponding effective income tax rates were 24.7 percent and 19.7
percent, respectively. Additionally, income tax expense increased to
$103 million for the third quarter of 2004 compared to $58 million for
the third quarter of 2003, and the effective income tax rate increased
to 30.6 percent in 2004 from 21.6 percent in 2003. The changes were due
primarily to higher taxable income and the resulting higher effective
income tax rate in 2004, despite the reduction in estimated income tax
liabilities for certain prior years. Discussion of Section 29 income
tax credits is provided in Note 7 herein and in Note 7 of the notes to
Consolidated Financial Statements of the Annual Report.
Discontinued Operations
During the first quarter of 2004, Sempra Energy's Board of Directors
approved management's plan to dispose of the company's interest in AEG.
On April 27, 2004, the company disposed of AEG at a $2 million loss net
of income taxes. Including the $2 million loss on disposal, AEG's
losses were $32 million for the nine months ended September 30, 2004.
Note 4 of the notes to Consolidated Financial Statements herein
provides further details.
During 2003, the company accounted for its investment in AEG under the
equity method of accounting. As such, for the nine-month and three-
month periods ended September 30, 2003, the company recorded its share
of AEG's net income, $1 million and $7 million, respectively, in Other
Income - Net on the Statements of Consolidated Income. Additionally,
for the nine-month and three-month periods the company recorded $2
million and $1 million, respectively, of interest income and for both
periods the company recorded offsetting income tax expense of $1
million. Effective December 31, 2003, AEG was consolidated as a result
44
of the adoption of FIN 46. This is discussed further in Note 2 herein
and in Note 1 of the Annual Report.
Net Income
Net income for the nine months ended September 30 increased to $549
million, or $2.36 per diluted share of common stock in 2004 from $415
million, or $1.98 per diluted share in 2003. Net income for the third
quarter was $231 million, or $0.98 per diluted share for 2004, compared
to $211 million or $1.00 per diluted share in 2003. Unusual items
affecting these comparisons are provided in the first table in this
section. Although net income increased for both periods, earnings per
share were affected by the issuance of 16.5 million additional shares
in the fourth quarter of 2003 and the effect on the Equity Units of the
change in the market price of company stock.
<table>
Net Income by Business Unit
<caption>
Three months ended Nine months ended
September 30, September 30,
(Dollars in millions) 2004 2003 2004 2003
- -------------------------------------------------------------------------------
<s> <c> <c> <c> <c>
California Utilities
Southern California Gas Company $ 68 $ 53 $ 174 $ 148
San Diego Gas & Electric 60 120 140 206
----- ----- ----- -----
Total Utilities 128 173 314 354
Global Enterprises
Sempra Energy Trading 44 22 143 67
Sempra Energy Resources 64 33 123 48
Sempra Energy International 7 (32) 35 (7)
Sempra Energy LNG (4) -- -- --
Sempra Energy Solutions 1 -- 1 8
----- ----- ----- -----
Total Global Enterprises 112 23 302 116
Sempra Energy Financial 10 13 26 32
Parent and other (19) 2 (61) (58)
----- ----- ----- -----
Continuing operations 231 211 581 444
Discontinued operations -- -- (32)* --
Cumulative effect of change in
accounting principle -- -- -- (29)**
----- ----- ----- -----
Consolidated net income $ 231 $ 211 $ 549 $ 415
===== ===== ===== =====
- -----------------------------------------------------------------------
* Includes ($2) million related to the loss on disposal of AEG.
** The effects were ($28) million at SET and ($1) million at SES.
</table>
Subsequent to September 30, 2004, SES will be reorganized such that its
commodity business will be moved to SET and its other businesses will
be moved to SER.
45
SOUTHERN CALIFORNIA GAS COMPANY
SoCalGas recorded net income of $174 million and $148 million for the
nine-month periods ended September 30, 2004 and 2003, respectively, and
net income of $68 million and $53 million for the quarters ended
September 30, 2004 and 2003, respectively. The increases were primarily
due to the $32 million after-tax charge for litigation and for losses
associated with a long-term sublease of portions of its headquarters
building in 2003, higher margins in 2004 and the gain on the sale of
partnership property, partially offset by higher GCIM awards in 2003
and higher depreciation expense in 2004.
SAN DIEGO GAS & ELECTRIC COMPANY
SDG&E recorded net income of $140 million and $206 million for the
nine-month periods ended September 30, 2004 and 2003, respectively, and
net income of $60 million and $120 million for the quarters ended
September 30, 2004 and 2003, respectively. The decreases were primarily
due to income of $65 million after-tax in 2003 related to the approved
settlement of intermediate-term purchase power contracts, the 2003
Incremental Cost Incentive Pricing for SONGS, higher performance awards
in 2003 and higher depreciation expense in 2004 partially offset by
higher electric transmission and distribution revenues (excluding the
effects of the settlement, which are included in Revenues) in 2004, and
by higher operating expenses in 2003 including litigation charges in
the third quarter.
SEMPRA ENERGY TRADING
SET recorded net income of $143 million and $67 million for the nine-
month periods ended September 30, 2004 and 2003, respectively,
excluding the cumulative effect of the change in accounting principle
of ($28) million in 2003. Additionally, SET recorded net income of $44
million and $22 million for the quarters ended September 30, 2004 and
2003, respectively. The increases were primarily attributable to higher
trading margins, particularly on metals and petroleum, partially offset
by litigation expenses. Net income for the third quarter of 2004 was
$38 million lower than the true economic value of SET's activities due
to timing differences between economic valuations and accounting
principles. It is expected that most of that deferred income will be
recognized in the fourth quarter of 2004.
A summary of SET's unrealized revenues for trading activities for the
nine months ended September 30, 2004 and 2003 follows:
(Dollars in millions) 2004 2003
- -----------------------------------------------------------------
Balance at beginning of period $ 269 $ 180
Cumulative effect adjustment -- (48)
Additions 710 833
Realized (189) (552)
----------------------
Balance at end of period $ 790 $ 413
- -----------------------------------------------------------------
46
The estimated fair values for SET's trading activities as of September
30, 2004, and the periods during which unrealized revenues are expected
to be realized, are (dollars in millions):
<table>
<caption>
Fair Market
Value at
September 30, /--Scheduled Maturity (in months)--/
Source of fair value 2004 0-12 13-24 25-36 >36
- -------------------------------------------------------------------------
<s> <c> <c> <c> <c> <c>
Prices actively quoted $ 623 $ 548 $ 50 $ (1) $ 26
Prices provided by other
external sources 1 (9) -- -- 10
Prices based on models
and other valuation
methods (22) (33) -- -- 11
------------------------------------------------
Over-the-counter
revenue * 602 506 50 (1) 47
Exchange contracts ** 188 249 (58) (1) (2)
------------------------------------------------
Total $ 790 $ 755 $ (8) $ (2) $ 45
- -------------------------------------------------------------------------
* The present value of unrealized revenue to be received or (paid) from
outstanding OTC contracts.
** Cash (paid) or received associated with open exchange contracts.
</table>
SET's Value at Risk (VaR) amounts are described in Item 3.
The CPUC prohibits the California Utilities and the other IOUs from
procuring electricity from their affiliates. This is discussed in
"Electric Industry Regulation" in Note 13 of the Annual Report.
SEMPRA ENERGY RESOURCES
SER recorded net income of $123 million and $48 million for the nine-
month periods ended September 30, 2004 and 2003, respectively, and net
income of $64 million and $33 million for the quarters ended September
30, 2004 and 2003, respectively. The increased earnings in 2004 were
primarily due to higher volumes of power sales under the DWR contract.
SEMPRA ENERGY INTERNATIONAL
SEI recorded net income of $35 million for the nine-month period ended
September 30, 2004 compared to a net loss of $7 million for the same
period of 2003, and recorded net income of $7 million for the quarter
ended September 30, 2004 compared to a net loss of $32 million for the
same period of 2003. The increases for both periods were due to the
2003 charge recorded to write down the carrying value of assets at
Frontier Energy, as previously discussed, and increased earnings from
the company's Gasoducto Bajanorte natural gas pipeline in 2004.
Additionally, the increase for the nine-month period was due to a gain
on the sale of a portion of SEI's interests in Luz del Sur, a Peruvian
electric utility, offset by the impact of changes in estimates for
certain income tax issues in the second quarter of 2004.
47
SEMPRA ENERGY LNG
SELNG recorded break-even results for the nine months ended September
30, 2004 and a net loss of $4 million for the quarter ended September
30, 2004. For the nine-month period, the income from 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) was offset by start-up costs. The loss for the three-
month period was due to the start-up costs.
SEMPRA ENERGY SOLUTIONS
SES recorded net income of $1 million and $8 million for the nine-month
periods ended September 30, 2004 and 2003, respectively, excluding the
cumulative effect of the change in accounting principle of ($1) million
in 2003. Additionally, SES recorded net income of $1 million for the
quarter ended September 30, 2004 compared to break-even results for the
same period of 2003. The decrease for the nine-month period was
primarily due to lower net commodity revenues.
SEMPRA ENERGY FINANCIAL
SEF recorded net income of $26 million and $32 million for the nine-
month periods ended September 30, 2004 and 2003, respectively, and net
income of $10 million and $13 million for the quarters ended September
30, 2004 and 2003, respectively. During the third quarter of 2004, SEF
sold its alternative fuel investment, Carbontronics. The transaction
has been accounted for under the cost recovery method, whereby future
proceeds in excess of Carbontronics' carrying value will be recorded as
income as received. As a result of this sale, SEF will not be
recognizing Section 29 income tax credits in the future.
PARENT AND OTHER
Net losses for Parent and Other were $61 million and $58 million for
the nine-month periods ended September 30, 2004 and 2003. Additionally,
net losses were $19 million for the quarter ended September 30, 2004,
compared to net income of $2 million for the same period of 2003. The
change for the quarter was due primarily to a lower 2003 income tax
expense as a result of a positive adjustment to reflect the company's
consolidated effective tax rate.
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 September 30, 2004, the company had $267 million in cash and $3.3
billion in available unused, committed lines of credit. See "Cash
Flows from Financing Activities" for discussion on changes in credit
facilities in 2004.
Management believes these amounts and cash flows from operations and
new security issuances will be adequate to finance capital expenditure
48
requirements, shareholder dividends, any new business acquisitions or
start-ups, and other commitments. If cash flows from operations were to
be significantly reduced or the company were to be unable to issue new
securities on acceptable terms, neither of which is considered likely,
the company would be required to reduce non-utility capital
expenditures and investments in new businesses. Management continues to
regularly monitor the company's ability to finance the needs of its
operating, financing and investing activities in a manner consistent
with its intention to maintain strong, investment-quality credit
ratings. Rating agencies and others that evaluate a company's liquidity
generally consider a company's capital expenditures and working capital
requirements in comparison to cash from operations, available credit
lines and other sources available to meet liquidity requirements.
At the California Utilities, cash flows from operations and from debt
issuances are expected to continue to be adequate to meet utility
capital expenditure requirements and provide dividends to Sempra
Energy. In June 2004, SDG&E received CPUC approval of its plans to
purchase (in 2006) from SER a 550-MW generating facility being
constructed in Escondido, California. As a result, the level of
SDG&E's dividends to Sempra Energy is expected to be significantly
lower during the construction of the facility to enable SDG&E to
increase its equity in preparation for the purchase of the completed
facility.
SET provides or requires cash as the level of its net trading assets
fluctuates with prices, volumes, margin requirements (which are
substantially affected by credit ratings and commodity price
fluctuations) and the length of its various trading positions. Its
status as a source or use of cash also varies with its level of
borrowing from its own sources. SET's intercompany borrowings were
$618 million at September 30, 2004, up from $359 million at December
31, 2003. SET's external debt was $145 million at September 30, 2004.
Company management continuously monitors the level of SET's cash
requirements in light of the company's overall liquidity.
SER's projects are expected to be financed through a combination of
project financing, SER's cash from operations and borrowings, and funds
from the company.
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; Louisiana; and Texas, as discussed in "Cash Flows
From Investing Activities," below.
SELNG will require funding for its planned development of LNG receiving
facilities. While funding from the company is expected to be adequate
for these requirements, the company may decide to use project financing
if that is believed to be advantageous.
In the longer term, SEF is expected to again be a net provider of cash
through reductions of consolidated income tax payments resulting from
its investments in affordable housing. However, that was not true in
2003 and 2004, and will not be true in the near term, while the company
is in an alternative minimum tax position.
49
CASH FLOWS FROM OPERATING ACTIVITIES
Net cash provided by operating activities totaled $493 million and $923
million for the nine months ended September 30, 2004 and 2003,
respectively. The change was attributable to an increase in net trading
assets in 2004 compared to a decrease in 2003, partially offset by
higher net income and a higher decrease in accounts receivable in 2004.
For the nine months ended September 30, 2004, the company made pension
plan and other postretirement benefit plan contributions of $10 million
and $44 million, respectively.
CASH FLOWS FROM INVESTING ACTIVITIES
Net cash used in investing activities totaled $294 million and $887
million for the nine months ended September 30, 2004 and 2003,
respectively. The change was primarily attributable to proceeds from
the sale of U.S. Treasury obligations which previously securitized the
Mesquite synthetic lease. The collateral was no longer necessary as
SER bought out the lease in January 2004. The decrease in cash used in
investing activities was also due to lower investments primarily as a
result of completion of the Elk Hills and Mesquite power plants. In
addition, the company had proceeds of $137 million from the disposal of
AEG's discontinued operations.
On April 1, 2004, SEI and PSEG Global, an unaffiliated company, sold a
portion of their interests in Luz del Sur for a total of $62 million.
Each party had a 44-percent interest in Luz del Sur prior to the sale
compared to a 38-percent interest after the sale was completed. SEI
recognized an after-tax gain of $5 million as a result of the sale.
Starting in 2003 and through the end of the third quarter of 2004, SET
has spent $87 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 market-based-pricing facility
started injecting natural gas during the second quarter of 2004.
On April 16, 2004, the company announced the acquisition of land and
associated rights for the development of a salt-cavern natural gas
storage facility in Evangeline Parish, Louisiana. This facility,
operating as the Pine Prairie Energy Center, will consist of three salt
caverns with a total capacity of 24 billion cubic feet (bcf) of natural
gas and is expected to begin operations in 2006 and to cost
approximately $175 million. The company is currently negotiating
contracts to sell the capacity of this facility. FERC approval for the
construction and operation of the facility is pending.
On July 20, 2004, the company announced that it had acquired the rights
to develop a salt-cavern natural gas storage facility located in
Calcasieu Parish, Louisiana, called "Liberty," that is expected to have
capacity of 17 bcf.
On April 21, 2004, SELNG announced plans to develop and construct a new
$600 million LNG receiving terminal near Port Arthur, Texas. The
terminal would be capable of processing 1.5 bcf of natural gas per day
50
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.
In October 2004, SELNG signed a sale and purchase agreement with
British Petroleum and its partners for the supply of 500 million cubic
feet of gas a day from Indonesia's Tangguh LNG liquefaction facility to
Energia Costa Azul, a planned SELNG regasification terminal in Baja
California that is expected to be fully operational in 2008 and to cost
between $900 million and $1 billion, including related pipeline costs,
of which $50 million had been expended through September 30, 2004. The
20-year agreement provides for pricing tied to the Southern California
border index for natural gas and will cover half the capacity of the
Energia Costa Azul receipt facility. Also in October 2004, SELNG
entered into an agreement with Shell International Gas Limited (Shell)
by which Shell has purchased half of the initial capacity of the
Energia Costa Azul terminal for an initial period of 20 years. This
replaces a prior arrangement that contemplated that Shell would have a
50% equity interest in the terminal.
On July 1, 2004, Topaz Power Partners (Topaz), a 50/50 joint venture
between Sempra Energy Partners and Carlyle/Riverstone acquired ten
Texas power plants from AEP, including the 632-MW coal-fired Coleto
Creek Power Station. Topaz acquired these assets for $430 million in
cash and the assumption of various environmental and asset retirement
liabilities associated with the plants, initially estimated at $63
million. $355 million of the purchase price was provided by non-
recourse project financing related solely to the acquisition of the
Coleto Creek Power Station.
The transaction included the acquisition of six operating power plants
with generating capacity of 1,950 MW and four inactive power plants
(capable of generating 1,863 MW). Concurrently with the acquisition,
Topaz sold one of the inactive power plants and no gain or loss was
recorded on the transaction. Topaz has entered into several power sales
agreements, with a weighted-average life of 4.3 years, for 572 MW of
Coleto Creek Power Station's capacity.
In conjunction with the acquisition of the plants, Sempra Energy
provided AEP a guarantee for certain specified liabilities described in
the acquisition agreement. This guarantee is limited to $75 million for
the first five years after the acquisition date and $25 million for the
next five years, but not more than $75 million over the entire 10-year
period. Management does not expect any material losses to result from
the guarantee because performance is not expected to be required and,
therefore, believes that the fair value of the guarantee is immaterial.
The allocation of the purchase price remains subject to adjustment
until June 30, 2005.
The company expects to make capital expenditures and investments of
$1.2 billion in 2004, of which $852 million had been expended as of
September 30, 2004. Significant capital expenditures and investments
are expected to include $750 million for California utility plant
improvements, $130 million for the Palomar plant and $100 million for
the development of LNG regasification terminals. These expenditures and
51
investments are expected to be financed by cash flows from operations
and security issuances.
In September 2004, the CPUC approved a proposed framework for the
contracting of interstate pipeline capacity for core customers.
Discussions are underway for the California Utilities to acquire
pipeline capacity to replace capacity contracts expiring over the next
two years. The CPUC also approved requests to establish receipt points
to accept new supplies, including imported LNG, to the California
Utilities' service area. Approval for a point of receipt to import
natural gas from Mexico to Southern California via pipelines at Otay
Mesa was also obtained. As a result, the California Utilities expect to
install capital facilities starting in 2005, in order to receive
natural gas supplies from new delivery locations. The CPUC has
determined that project developers, not the utilities, will be presumed
to pay for the costs for access-related infrastructure, subject to
future applications to be filed when more is known about the particular
projects. Note 6 of the notes to Consolidated Financial Statements
herein provides further details.
Under terms of a franchise agreement and Memorandum of Understanding
reached in October 2004 between SDG&E and the City of Chula Vista,
SDG&E has committed to support at the CPUC for undergrounding a part of
the proposed Otay Mesa transmission line through Chula Vista's
bayfront, upon CPUC approval of a substation upgrade, and replacement
of certain other overhead transmission lines with underground
facilities. Other transmission lines are to be undergrounded pursuant
to the tariff Rule 20A undergrounding program. If the Otay Mesa
undergrounding project is approved by the CPUC, SDG&E's expected share
of cost will be $36 million. If SDG&E does not complete the
undergrounding project by April 2010, there will not be an automatic
renewal of the franchise at the end of the initial ten-year term.
CASH FLOWS FROM FINANCING ACTIVITIES
Net cash used in financing activities totaled $364 million and $80
million for the nine months ended September 30, 2004 and 2003,
respectively. The change was due to higher long-term debt payments,
partially offset by an increase in long-term debt issuances and a net
increase in short-term debt in 2004.
In July 2004, Global obtained a $1.5 billion three-year syndicated
revolving credit facility to replace its expiring $500 million
revolving credit facility and the expiring $400 million revolving
credit facility of SER. Global continues to have a substantially
identical $500 million three-year revolving credit facility that
expires in 2006. Borrowings under each facility are guaranteed by
Sempra Energy and bear interest at rates varying with market rates and
Sempra Energy's credit rating. Each facility requires Sempra Energy to
maintain, at the end of each quarter, a ratio of total indebtedness to
total capitalization (as identically defined in each facility) of no
more than 65 percent.
In September 2004, Pacific Enterprises (PE) extended the termination
date of its revolving credit agreement to September 30, 2005 and
increased the revolving credit commitment from $250 million to $500
million. Borrowings under the credit agreement, none of which are
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outstanding, are available to provide loans to Global and would bear
interest at rates varying with market rates, PE's credit ratings and
amounts borrowed. The borrowings would be guaranteed by the company and
would be subject to mandatory repayment if the company's or SoCalGas'
ratio of debt to total capitalization (as defined in the agreement)
were to exceed 65%, or if there were to be a change in law materially
and adversely affecting SoCalGas' ability to pay dividends or make
other distributions to PE.
At September 30, 2004 outstanding extensions of credit under SET's $1
billion credit facility totaled $350 million. Details concerning this
credit facility are provided in the Form 10-Q for the six-month period
ended June 30, 2004.
SER's energy contracts typically contain collateral requirements
related to credit lines. The collateral arrangements provide for SER
and/or the counterparty to post cash, guarantees or letters of credit
to the other party for exposure in excess of established thresholds.
SER may be required to provide collateral when market price movements
adversely affect the counterparty's cost of alternative energy should
SER fail to deliver the contracted amounts. As of September 30, 2004,
SER had outstanding collateral requirements under these contracts of
$171 million.
FACTORS INFLUENCING FUTURE PERFORMANCE
Base results of the company in the near future will depend primarily on
the results of the California Utilities, while earnings growth and
variability will result primarily from activities at SET, SER, SELNG
and SEI. Notes 6 and 7 of the notes to Consolidated Financial
Statements herein and Notes 13 through 15 of the Annual Report describe
events in the deregulation of California's electric and natural gas
industries and various FERC, SET and income tax issues.
California Utilities
Note 6 of the notes to Consolidated Financial Statements contains
discussions of electric and natural gas restructuring and rates, the
pending cost of service proceedings and the CPUC's investigation of
compliance with affiliate rules.
Sempra Energy Global Enterprises
Electric-Generation Assets
As discussed in more detail in "Cash Flows From Investing Activities,"
the company is involved in the expansion of its electric-generation
capabilities, including the AEP-related acquisition noted above, which
will significantly impact the company's future performance.
Investments
As discussed in "Cash Flows From Investing Activities," the company's
investments will significantly impact the company's future performance.
SELNG is in the process of developing Energia Costa Azul, an LNG
receiving terminal in Baja California, Mexico; the Cameron LNG
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receiving terminal in Louisiana; and the Port Arthur LNG receiving
terminal in Texas. The viability and future profitability of this
business unit is dependent upon numerous factors, including the
quantities of and 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. In October 2004, SELNG signed
a sale and purchase agreement with British Petroleum for the supply of
500 million cubic feet of gas a day from Indonesia's Tangguh LNG
liquefaction facility to Energia Costa Azul that is expected to cost
between $900 million and $1 billion, including related pipeline costs,
of which $50 million had been expended through September 30, 2004. Also
in October 2004, SELNG entered into a 20-year agreement with Shell by
which Shell has purchased half of the initial capacity of the Energia
Costa Azul terminal. Additional information regarding these activities
is provided above in "Cash Flows From Investing Activities."
Beginning in 2003, the company started expanding its natural gas
storage capacity by developing Bluewater Gas Storage, LLC. In April
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, operating as the Pine Prairie
Energy Center. In July 2004, the company announced that it had acquired
the rights to develop a salt-cavern gas storage facility located in
Calcasieu Parish, Louisiana, called "Liberty." Additional information
regarding these activities is provided above in "Cash Flows From
Investing Activities."
The Argentine economic decline and government responses (including
Argentina's unilateral, retroactive abrogation of utility agreements
early in 2002) are continuing to adversely affect the company's
investment in two Argentine utilities. Information regarding this
situation is provided in Note 7 of the notes to Consolidated Financial
Statements.
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 and its 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 SFAS Nos. 132 (revised
2003), 143, 149 and 150, FASB Staff Position 106-2, FIN 45 and 46, and
the rescission of EITF 98-10, as discussed in Note 2 of the notes to
Consolidated Financial Statements. Pronouncements that have or are
likely to have a material effect on future earnings are described
below.
EITF Issue 98-10, "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities": In accordance with the EITF's
rescission of Issue 98-10 by the release of Issue 02-3, the company no
longer marks to market energy-related contracts unless the contracts
meet the requirements stated under SFAS 133, Accounting for Derivative
Instruments and Hedging Activities, and SFAS 149, Amendment of
54
Statement 133 on Derivative Instruments and Hedging Activities. A
substantial majority of the company's contracts do meet these
requirements. Upon adoption of this consensus on January 1, 2003, the
company recorded the initial effect of rescinding Issue 98-10 as a
cumulative effect of a change in accounting principle, which reduced
after-tax earnings by $29 million.
SFAS 143, "Accounting for Asset Retirement Obligations": Beginning in
2003, SFAS 143 requires entities to record liabilities for future costs
expected to be incurred when assets are retired from service, if the
retirement process is legally required. It also requires most energy
utilities, including the California Utilities, to reclassify amounts
recovered in rates for future removal costs not covered by a legal
obligation from accumulated depreciation to a regulatory liability.
Further discussion is provided in Note 2 of the notes to Consolidated
Financial Statements.
In June 2004, the FASB issued a proposed interpretation of SFAS 143,
Accounting for Conditional Asset Retirement Obligations, an
interpretation of FASB Statement No. 143. The interpretation would
clarify that a legal obligation to perform an asset retirement activity
that is conditional on a future event is within the scope of SFAS 143.
Accordingly, the interpretation would require an entity to recognize a
liability for a conditional asset retirement obligation if the
liability's fair value can be reasonably estimated. The proposed
interpretation would be effective for the company on December 31, 2005.
SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities": SFAS 149 amends and clarifies accounting for
derivative instruments and for hedging activities under SFAS 133. Under
SFAS 149, natural gas forward contracts that are subject to unplanned
netting do not qualify for the normal purchases and normal sales
exception, whereby derivatives are not required to be marked to market
when the contract is usually settled by the physical delivery of
natural gas. The company has determined that all natural gas contracts
are subject to unplanned netting and as such, these contracts are
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 are
further marked to market. Implementation of SFAS 149 on July 1, 2003
did not have a material impact on reported net income.
FIN 46, "Consolidation of Variable Interest Entities (an interpretation
of ARB No. 51)": In January 2003, the FASB issued FIN 46 to strengthen
existing accounting guidance that addresses when a company should
consolidate a VIE in its financial statements.
Adoption of FIN 46 on December 31, 2003 resulted in the consolidation
of two VIEs for which Sempra Energy is the primary beneficiary. One of
the VIEs (Mesquite Trust) was the owner of the Mesquite Power plant for
which the company had a synthetic lease agreement. (The company bought
out the lease in January 2004.) The other VIE relates to the investment
in AEG. Sempra Energy consolidated these entities in its financial
statements at December 31, 2003. During the first quarter of 2004,
Sempra Energy's Board of Directors approved management's plan to
dispose of AEG. Note 4 of the notes to Consolidated Financial
55
Statements provides further discussion on this matter and the disposal
of AEG, which occurred in April 2004.
In accordance with FIN 46, the company has deconsolidated a wholly
owned subsidiary trust from its financial statements at December 31,
2003.
Further discussion regarding FIN 46 is provided in Note 2 of the notes
to Consolidated Financial Statements.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
There have been no significant changes in the risk issues affecting the
company subsequent to those discussed in the Annual Report.
The VaR for SET at September 30, 2004, and the average VaR for the nine
months ended September 30, 2004, at the 95-percent and 99-percent
confidence intervals (one-day holding period) were as follows (in
millions of dollars):
95% 99%
- ------------------------------------------------------
At September 30, 2004 $ 7.2 $ 10.2
Average for the nine months
ended September 30, 2004 $ 6.9 $ 9.7
- ------------------------------------------------------
As of September 30, 2004, the total VaR of the California Utilities'
and SES's positions was not material.
ITEM 4. CONTROLS AND PROCEDURES
The company has designed and maintains disclosure controls and
procedures to ensure that information required to be disclosed in the
company's reports under the Securities Exchange Act of 1934 is
recorded, processed, summarized and reported within the time periods
specified in the rules and forms of the Securities and Exchange
Commission and is accumulated and communicated to the company's
management, including its Chief Executive Officer and Chief Financial
Officer, as appropriate, to allow timely decisions regarding required
disclosure. In designing and evaluating these controls and procedures,
management recognizes that any system of controls and procedures, no
matter how well designed and operated, can provide only reasonable
assurance of achieving the desired objectives and necessarily applies
judgment in evaluating the cost-benefit relationship of other possible
controls and procedures. In addition, the company has investments in
unconsolidated entities that it does not control or manage and,
consequently, its disclosure controls and procedures with respect to
these entities are necessarily substantially more limited than those it
maintains with respect to its consolidated subsidiaries.
Under the supervision and with the participation of management,
including the Chief Executive Officer and the Chief Financial Officer,
the company evaluated the effectiveness of the design and operation of
the company's disclosure controls and procedures as of September 30,
2004, the end of the period covered by this report. Based on that
evaluation, the company's Chief Executive Officer and Chief Financial
56
Officer concluded that the company's disclosure controls and procedures
were effective at the reasonable assurance level.
There has been no change in the company's internal controls over
financial reporting during the company's most recent fiscal quarter
that has materially affected, or is reasonably likely to materially
affect, the company's internal controls over financial reporting.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
SDG&E and the County of San Diego are continuing to negotiate the
remaining terms of a settlement relating to alleged environmental law
violations by SDG&E and its contractors in connection with the
abatement of asbestos-containing materials during the demolition of a
natural gas storage facility that was completed in 2001. The expected
settlement would involve payments by SDG&E of less than $750,000.
Except as described above and in Notes 6 and 7 of the notes to
Consolidated Financial Statements herein, 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 5. OTHER INFORMATION
The company currently anticipates that its 2005 Annual Meeting of
Shareholders will be held on April 5, 2005. Any shareholder satisfying
the Securities and Exchange Commission's eligibility requirements who
wishes to submit a proposal to be included in the proxy statement for
the annual meeting should do so in writing to the Corporate Secretary,
101 Ash Street, San Diego, California 92101-3017.
As a consequence of having advanced the date of the annual meeting by
32 days from the date of the previous annual meeting, Securities and
Exchange Commission rules provide that the new deadline for the
company's receipt of shareholder proposals for inclusion in the proxy
statement is a reasonable time before the company begins to print and
mail proxy materials for the annual meeting. The company will regard
any proposals that it receives on or before November 19, 2004 (the
previously published deadline and that which would have been applicable
if the annual meeting date had not been advanced by more than 30 days)
as having been timely received. Any such proposals received after
November 19, will be regarded as untimely and will not be considered
for inclusion in the proxy statement.
Shareholders who wish to present other business, including director
nominations, for consideration at the 2005 Annual Meeting must notify
the Corporate Secretary of their intention to do so during the period
beginning on January 4, 2005 and ending on March 5, 2005. The notice
must also provide the information required by the company's bylaws.
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ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
Exhibit 10 - Material Contracts
Compensation
10.1 Sempra Energy Employee Stock Incentive Plan
10.2 Sempra Energy Amended and Restated Executive Life
Insurance Plan
10.3 Sempra Energy Excess Cash Balance Plan
10.4 Form of Sempra Energy 1998 Long Term Incentive Plan
Performance-Based Restricted Stock Award
10.5 Form of Sempra Energy 1998 Long Term Incentive Plan
Nonqualified Stock Option Agreement
10.6 Form of Sempra Energy 1998 Non-Employee Directors' Stock
Plan Nonqualified Stock Option Agreement
10.7 Sempra Energy Supplemental Executive Retirement Plan
10.8 Neal Schmale Restricted Stock Award Agreement
10.9 Severance Pay Agreement between Sempra Energy and
Donald E. Felsinger
10.10 Severance Pay Agreement between Sempra Energy and
Neal Schmale
10.11 Sempra Energy Executive Personal Financial Planning Program
Policy Document
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.
58
(b) Reports on Form 8-K
The following reports on Form 8-K were filed after June 30, 2004:
Current Report on Form 8-K filed August 5, 2004, filing as an exhibit
Sempra Energy's press release of August 5, 2004, giving the financial
results for the quarter ended June 30, 2004.
Current Report on Form 8-K filed September 30, 2004, announcing
proposed decisions issued by the CPUC's Administrative Law Judge and
the Assigned CPUC Commissioner on September 28, 2004, in the California
Utilities' Cost of Service Proceedings.
Current Report on Form 8-K filed October 27, 2004, discussing the
current status of the California Utilities' Cost of Service Proceedings
and the Border Price Investigation.
Current Report on Form 8-K filed November 4, 2004, filing as an exhibit
Sempra Energy's press release of November 4, 2004, giving the financial
results for the quarter ended September 30, 2004.
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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: November 4, 2004 By: /s/ F. H. Ault
----------------------------
F. H. Ault
Sr. Vice President and Controller