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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
[..X..] Quarterly report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
June 30, 2004
For the quarterly period ended.......................................
Or
[.....] Transition report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the transition period from ________________ to _________________
Commission Name of Registrant, State of IRS Employer
File Incorporation, Address and Identification
Number Telephone Number Number
- ---------- ---------------------------------- --------------
1-40 Pacific Enterprises 94-0743670
(A California Corporation)
101 Ash Street
San Diego, California 92101
(619) 696-2020
1-1402 Southern California Gas Company 95-1240705
(A California Corporation)
555 West Fifth Street
Los Angeles, California 90013
(213) 244-1200
No Change
- -----------------------------------------------------------------------
Former name, former address and former fiscal year, if changed since
last report
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Sections 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....... No..X....
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:
Pacific Enterprises Wholly owned by Sempra Energy
Southern California Gas Company Wholly owned by Pacific Enterprises
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 and national economic,
competitive, political, legislative and regulatory conditions and
developments; actions by the California Public Utilities Commission,
the California Legislature, and the Federal Energy Regulatory
Commission; capital market conditions, inflation rates, interest rates
and exchange rates; energy and trading markets, including the timing
and extent of changes in commodity prices; weather conditions and
conservation efforts; war and terrorist attacks; business, regulatory
and legal decisions; the status of deregulation of retail natural gas
and electricity delivery; the timing and success of business
development efforts; and other uncertainties, all of which are
difficult to predict and many of which are beyond the control of the
companies. 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 companies'
business described in this report and other reports filed by the
companies from time to time with the Securities and Exchange
Commission.
3
PART I FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
PACIFIC ENTERPRISES AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
(Dollars in millions)
Three months ended
June 30,
------------------
2004 2003
------- -------
Operating revenues $ 847 $ 820
------- -------
Operating expenses
Cost of natural gas 425 421
Other operating expenses 230 223
Depreciation 76 72
Income taxes 37 27
Franchise fees and other taxes 24 25
------- -------
Total operating expenses 792 768
------- -------
Operating income 55 52
------- -------
Other income and (deductions)
Interest income 2 3
Regulatory interest - net 1 (1)
Allowance for equity funds used
during construction 2 2
Income taxes on non-operating income -- (1)
Preferred dividends of subsidiaries (1) (1)
Other - net 1 (5)
------- -------
Total 5 (3)
------- -------
Interest charges
Long-term debt 8 10
Other 4 4
Allowance for borrowed funds used
during construction (1) (1)
------- -------
Total 11 13
------- -------
Net income 49 36
Preferred dividend requirements 1 1
------- -------
Earnings applicable to common shares $ 48 $ 35
======= =======
See notes to Consolidated Financial Statements.
4
PACIFIC ENTERPRISES AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
(Dollars in millions)
Six months ended
June 30,
-----------------
2004 2003
------- -------
Operating revenues $ 1,995 $ 1,828
------- -------
Operating expenses
Cost of natural gas 1,146 1,021
Other operating expenses 440 420
Depreciation 150 141
Income taxes 81 72
Franchise fees and other taxes 57 54
------- -------
Total operating expenses 1,874 1,708
------- -------
Operating income 121 120
------- -------
Other income and (deductions)
Interest income 10 5
Regulatory interest - net (2) (1)
Allowance for equity funds used
during construction 3 4
Income taxes on non-operating income -- (2)
Preferred dividends of subsidiaries (1) (1)
Other - net -- (2)
------- -------
Total 10 3
------- -------
Interest charges
Long-term debt 17 22
Other 7 9
Allowance for borrowed funds used
during construction (1) (2)
------- -------
Total 23 29
------- -------
Net income 108 94
Preferred dividend requirements 2 2
------- -------
Earnings applicable to common shares $ 106 $ 92
======= =======
See notes to Consolidated Financial Statements.
5
PACIFIC ENTERPRISES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
-----------------------------
June 30, December 31,
2004 2003
------------- -------------
ASSETS
Utility plant - at original cost $ 7,131 $ 7,008
Accumulated depreciation (2,826) (2,739)
------- -------
Utility plant - net 4,305 4,269
------- -------
Current assets:
Cash and cash equivalents 34 32
Accounts receivable - trade 334 509
Accounts receivable - other -- 36
Interest receivable 31 30
Due from affiliates 187 76
Income taxes receivable 46 71
Regulatory assets arising from fixed-price
contracts and other derivatives 94 85
Other regulatory assets 23 8
Inventories 34 74
Other 9 12
------- -------
Total current assets 792 933
------- -------
Other assets:
Due from affiliates 397 356
Regulatory assets arising from fixed-price
contracts and other derivatives 96 148
Sundry 126 150
------- -------
Total other assets 619 654
------- -------
Total assets $ 5,716 $ 5,856
======= =======
See notes to Consolidated Financial Statements.
6
PACIFIC ENTERPRISES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
-----------------------------
June 30, December 31,
2004 2003
------------- -------------
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock (600 million shares authorized;
84 million shares outstanding) $ 1,367 $ 1,367
Retained earnings 259 253
Accumulated other comprehensive income (loss) (3) (3)
------- -------
Total common equity 1,623 1,617
Preferred stock 80 80
------- -------
Total shareholders' equity 1,703 1,697
Long-term debt 761 762
------- -------
Total capitalization 2,464 2,459
------- -------
Current liabilities:
Accounts payable - trade 248 227
Accounts payable - other 34 44
Due to affiliates 93 121
Interest payable 19 18
Deferred income taxes 23 24
Regulatory balancing accounts - net 173 86
Fixed-price contracts and other derivatives 96 86
Current portion of long-term debt -- 175
Customer deposits 45 43
Other 253 262
------- -------
Total current liabilities 984 1,086
------- -------
Deferred credits and other liabilities:
Customer advances for construction 42 40
Postretirement benefits other than pensions 60 72
Deferred income taxes 157 121
Deferred investment tax credits 43 44
Regulatory liabilities arising from cost of
removal obligations 1,429 1,392
Other regulatory liabilities 104 108
Fixed-price contracts and other derivatives 98 148
Preferred stock of subsidiary 20 20
Deferred credits and other 315 366
------- -------
Total deferred credits and other liabilities 2,268 2,311
------- -------
Contingencies and commitments (Note 5)
Total liabilities and shareholders' equity $ 5,716 $ 5,856
======= =======
See notes to Consolidated Financial Statements.
7
PACIFIC ENTERPRISES AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in millions)
Six months ended
June 30,
------------------
2004 2003
------- -------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 108 $ 94
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation 150 141
Deferred income taxes and investment tax credits 27 (41)
Net changes in other working capital components 384 252
Changes in other assets -- (2)
Changes in other liabilities (42) (4)
------- -------
Net cash provided by operating activities 627 440
------- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (144) (135)
Affiliate loans (204) 107
------- -------
Net cash used in investing activities (348) (28)
------- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid (100) (250)
Preferred dividends paid (2) (2)
Payments on long-term debt (175) (170)
------- -------
Net cash used in financing activities (277) (422)
------- -------
Increase (decrease) in cash and cash equivalents 2 (10)
Cash and cash equivalents, January 1 32 22
------- -------
Cash and cash equivalents, June 30 $ 34 $ 12
======= =======
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized $ 20 $ 26
======= =======
Income tax payments, net of refunds $ 33 $ 44
======= =======
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING
AND FINANCING ACTIVITIES
Assets contributed by Sempra Energy $ -- $ 48
Liabilities assumed -- (17)
------- -------
Net assets contributed by Sempra Energy $ -- $ 31
======= =======
See notes to Consolidated Financial Statements.
8
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
(Dollars in millions)
Three months ended
June 30,
------------------
2004 2003
------- -------
Operating revenues $ 847 $ 820
------- -------
Operating expenses
Cost of natural gas 425 421
Other operating expenses 229 226
Depreciation 76 72
Income taxes 38 28
Franchise fees and other taxes 24 25
------- -------
Total operating expenses 792 772
------- -------
Operating income 55 48
------- -------
Other income and (deductions)
Interest income 1 1
Regulatory interest - net 1 (1)
Allowance for equity funds used
during construction 2 2
Income taxes on non-operating income -- (1)
Other - net 1 --
------- -------
Total 5 1
------- -------
Interest charges
Long-term debt 8 10
Other 2 2
Allowance for borrowed funds used
during construction (1) (1)
------- -------
Total 9 11
------- -------
Net income 51 38
Preferred dividend requirements 1 1
------- -------
Earnings applicable to common shares $ 50 $ 37
======= =======
See notes to Consolidated Financial Statements.
9
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
(Dollars in millions)
Six months ended
June 30,
-----------------
2004 2003
------- -------
Operating revenues $ 1,995 $ 1,828
------- -------
Operating expenses
Cost of natural gas 1,146 1,021
Other operating expenses 438 421
Depreciation 150 141
Income taxes 81 73
Franchise fees and other taxes 57 54
------- -------
Total operating expenses 1,872 1,710
------- -------
Operating income 123 118
------- -------
Other income and (deductions)
Interest income 2 2
Regulatory interest - net (2) (1)
Allowance for equity funds used
during construction 3 4
Income taxes on non-operating income -- (2)
Other - net -- (1)
------- -------
Total 3 2
------- -------
Interest charges
Long-term debt 17 22
Other 3 4
Allowance for borrowed funds used
during construction (1) (2)
------- -------
Total 19 24
------- -------
Net income 107 96
Preferred dividend requirements 1 1
------- -------
Earnings applicable to common shares $ 106 $ 95
======= =======
See notes to Consolidated Financial Statements.
10
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
-----------------------------
June 30, December 31,
2004 2003
------------- -------------
ASSETS
Utility plant - at original cost $ 7,131 $ 7,008
Accumulated depreciation (2,826) (2,739)
------- -------
Utility plant - net 4,305 4,269
------- -------
Current assets:
Cash and cash equivalents 34 32
Accounts receivable - trade 334 509
Accounts receivable - other -- 35
Interest receivable 31 30
Due from affiliates 183 22
Income taxes receivable -- 24
Regulatory assets arising from fixed-priced contracts
and other derivatives 94 85
Other regulatory assets 23 8
Inventories 34 74
Other 8 9
------- -------
Total current assets 741 828
------- -------
Other assets:
Regulatory assets arising from fixed-priced contracts
and other derivatives 96 148
Sundry 103 127
------- -------
Total other assets 199 275
------- -------
Total assets $ 5,245 $ 5,372
======= =======
See notes to Consolidated Financial Statements.
11
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
-----------------------------
June 30, December 31,
2004 2003
------------- -------------
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock (100 million shares authorized;
91 million shares outstanding) $ 866 $ 866
Retained earnings 497 491
Accumulated other comprehensive income (loss) (3) (3)
------- -------
Total common equity 1,360 1,354
Preferred stock 22 22
------- -------
Total shareholders' equity 1,382 1,376
Long-term debt 761 762
------- -------
Total capitalization 2,143 2,138
------- -------
Current liabilities:
Accounts payable - trade 248 227
Accounts payable - other 34 44
Due to affiliates 27 55
Interest payable 18 18
Income taxes payable 2 --
Deferred income taxes 14 15
Regulatory balancing accounts - net 173 86
Fixed-price contracts and other derivatives 96 86
Current portion of long-term debt -- 175
Customer deposits 45 43
Other 252 262
------- -------
Total current liabilities 909 1,011
------- -------
Deferred credits and other liabilities:
Customer advances for construction 42 40
Postretirement benefits other than pensions 60 --
Deferred income taxes 163 136
Deferred investment tax credits 43 44
Regulatory liabilities arising from cost
of removal obligations 1,429 1,392
Other regulatory liabilities 104 180
Fixed-price contracts and other derivatives 98 148
Deferred credits and other 254 283
------- -------
Total deferred credits and other liabilities 2,193 2,223
------- -------
Contingencies and commitments (Note 5)
Total liabilities and shareholders' equity $ 5,245 $ 5,372
======= =======
See notes to Consolidated Financial Statements.
12
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in millions)
Six months ended
June 30,
--------------------
2004 2003
------- -------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 107 $ 96
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation 150 141
Deferred income taxes and investment tax credits 25 (41)
Net changes in other working capital components 325 253
Changes in other assets -- (1)
Changes in other liabilities (22) --
------- -------
Net cash provided by operating activities 585 448
------- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (144) (135)
Affiliate loan (163) (102)
------- -------
Net cash used in investing activities (307) (237)
------- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid (100) (50)
Preferred dividends paid (1) (1)
Payments on long-term debt (175) (170)
------- -------
Net cash used in financing activities (276) (221)
------- -------
Increase (decrease) in cash and cash equivalents 2 (10)
Cash and cash equivalents, January 1 32 22
------- -------
Cash and cash equivalents, June 30 $ 34 $ 12
======= =======
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized $ 17 $ 24
======= =======
Income tax payments, net of refunds $ 33 $ 44
======= =======
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING
AND FINANCING ACTIVITIES
Assets contributed by Sempra Energy $ -- $ 48
Liabilities assumed -- (18)
------- -------
Net assets contributed by Sempra Energy $ -- $ 30
======= =======
See notes to Consolidated Financial Statements.
13
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. GENERAL
This Quarterly Report on Form 10-Q is that of Pacific Enterprises (PE)
and of Southern California Gas Company (SoCalGas)(collectively referred
to as the company or the companies). PE's common stock is wholly owned
by Sempra Energy, a California-based Fortune 500 holding company, and
PE owns all of the common stock of SoCalGas. The financial statements
herein are, in one case, the Consolidated Financial Statements of PE
and its subsidiary SoCalGas, and, in the second case, the Consolidated
Financial Statements of SoCalGas and its subsidiaries, which comprise
less than one percent of SoCalGas' consolidated financial position and
results of operations.
Sempra Energy also indirectly owns all of the common stock of San Diego
Gas & Electric (SDG&E). SoCalGas and SDG&E are collectively referred to
herein as "the California Utilities."
The accompanying Consolidated Financial Statements have been prepared
in accordance with the interim-period-reporting requirements of Form
10-Q. Results of operations for interim periods are not necessarily
indicative of results for the entire year. In the opinion of
management, the accompanying statements reflect all adjustments
necessary for a fair presentation. These adjustments are only of a
normal recurring nature. Certain changes in classification have been
made to prior presentations to conform to the current financial
statement presentation. Specifically, certain December 31, 2003 income
tax liabilities have been reclassified from Deferred Income Taxes to
current Income Taxes Payable and to Deferred Credits and Other
Liabilities to conform to the current presentation of these items.
Information in this Quarterly Report is unaudited and should be read in
conjunction with the Annual Report on Form 10-K for the year ended
December 31, 2003 (Annual Report) and the Quarterly Report on Form 10-Q
for the first quarter of 2004.
The companies' 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.
For the quarters ended June 30, 2004 and 2003, comprehensive income was
equal to earnings applicable to common shares.
SoCalGas accounts for the economic effects of regulation on utility
operations in accordance with Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types
of Regulation."
NOTE 2. NEW ACCOUNTING STANDARDS
Stock-Based Compensation: On March 31, 2004, the Financial Accounting
Standards Board (FASB) issued a proposed Exposure Draft (ED) to amend
SFAS 123, "Accounting for Stock-Based Compensation." The proposed
statement would eliminate the choice of accounting for share-based
14
compensation transactions using Accounting Principles Board (APB)
Opinion No. 25, "Accounting for Stock Issued to Employees," whereby no
expense is recorded for most stock options and instead generally
require that such transactions be accounted for using a fair-value-
based method, whereby expense is recorded for stock options. It would
also prohibit application by restating prior periods and would require
that expense be recognized only for those options that actually vest.
If passed, the proposed ED would be effective for the company in 2005.
SFAS 132 (revised 2003), "Employers' Disclosures about Pensions and
Other Postretirement Benefits": This statement revises employers'
disclosures about pension plans and other postretirement benefit plans,
effective in 2004. It requires disclosures beyond those in the original
SFAS 132 related to the assets, obligations, cash flows and net
periodic benefit cost of defined benefit pension plans and other
defined postretirement plans. In addition, it requires interim-period
disclosures regarding the amount of net periodic benefit cost
recognized and the total amount of the employers' contributions paid
and expected to be paid during the current fiscal year. It does not
change the measurement or recognition of those plans.
The following table provides the components of benefit costs for the
three months and six months ended June 30:
Other
Pension Benefits Postretirement Benefits
--------------------------------------------
Three months ended Three months ended
June 30, June 30,
--------------------------------------------
(Dollars in millions) 2004 2003 2004 2003
- -------------------------------------------------------------------------------
Service cost $ 7 $ 8 $ 4 $ 4
Interest cost 23 23 13 12
Expected return on assets (25) (26) (8) (8)
Amortization of:
Transition obligation -- -- 2 2
Prior service cost 2 1 -- --
Actuarial loss 1 -- 2 2
Regulatory adjustment (8) (5) 2 (1)
--------------------------------------------
Total net periodic benefit cost $ -- $ 1 $ 15 $ 11
- -------------------------------------------------------------------------------
15
Other
Pension Benefits Postretirement Benefits
--------------------------------------------
Six months ended Six months ended
June 30, June 30,
--------------------------------------------
(Dollars in millions) 2004 2003 2004 2003
- -------------------------------------------------------------------------------
Service cost $ 15 $ 16 $ 9 $ 8
Interest cost 46 45 25 23
Expected return on assets (49) (53) (16) (16)
Amortization of:
Transition obligation -- -- 4 4
Prior service cost 3 3 -- --
Actuarial loss 2 -- 5 3
Regulatory adjustment (16) (10) -- --
--------------------------------------------
Total net periodic benefit cost $ 1 $ 1 $ 27 $ 22
- -------------------------------------------------------------------------------
Note 5 of the notes to Consolidated Financial Statements in the Annual
Report discusses the company's expected contribution to its pension
plan and other postretirement benefit plans in 2004. For the six months
ended June 30, 2004, $3 million and $27 million of contributions have
been made to its pension plan and other postretirement benefit plans,
respectively, including $3 million and $15 million, respectively, for
the three months ended June 30, 2004.
SFAS 143, "Accounting for Asset Retirement Obligations": Beginning in
2003, SFAS 143 requires entities to record liabilities for future costs
expected to be incurred when assets are retired from service, if the
retirement process is legally required. It also requires the
reclassification of estimated removal costs, which have historically
been recorded in accumulated depreciation, to a regulatory liability.
At both June 30, 2004 and December 31, 2003, the estimated removal
costs recorded as a regulatory liability were $1.4 billion.
The change in the asset retirement obligations for the six months ended
June 30, 2004 is as follows (dollars in millions):
Balance as of January 1, 2004 $ 11
Accretion expense (interest) --
------
Balance as of June 30, 2004 $ 11*
======
* The current portion of the obligation is included in Other Current
Liabilities on the Consolidated Balance Sheets.
SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities": Effective July 1, 2003, SFAS 149 amended and
clarified accounting for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging
activities under SFAS 133. Under SFAS 149 natural gas forward contracts
that are subject to unplanned netting generally do not qualify for the
16
normal purchases and normal sales exception, whereby derivatives are
not required to be marked to market when the contract is usually
settled by the physical delivery of natural gas. ("Netting" refers to
contract settlement by paying or receiving the monetary difference
between the contract price and the market price at the date on which
physical delivery would have occurred.) Implementation of SFAS 149 did
not have a material impact on reported net income. Additional
information on derivative instruments is provided in Note 3.
FASB Staff Position (FSP) 106-1 and 106-2, "Accounting and Disclosure
Requirements Related to the Medicare Prescription Drug, Improvement and
Modernization Act of 2003": Issued January 12, 2004, FSP 106-1 allowed
the company to make a one-time election during the first quarter of
2004 to defer accounting for the effects of the Medicare Prescription
Drug, Improvement and Modernization Act of 2003 (the Act) until
authoritative guidance on the accounting for federal subsidies was
issued.
In May 2004, FSP 106-1 was superseded by FSP 106-2, which provides
guidance on the accounting for the effects of the Act by employers
whose prescription drug benefits are actuarially equivalent to the drug
benefit under Medicare Part D. In such a case, the employer includes
the federal subsidy in measuring the accumulated postretirement benefit
obligation (APBO). The resulting reduction in the APBO is recognized as
an actuarial gain and the employer's share of future costs under the
plan is reflected in current period service cost. FSP 106-2 also
provides disclosure guidance about the effects of the subsidy for an
employer who offers postretirement prescription drug coverage, but is
unable to determine whether the plan's provisions are actuarially
equivalent to the Medicare Part D benefit. For the company, FSP 106-2
is effective for the quarter ending September 30, 2004. The company has
not yet determined whether the benefits provided by the plans are
actuarially equivalent, and, at June 30, 2004, the APBO and net
periodic postretirement benefit costs do not reflect any amount
associated with the subsidy.
NOTE 3. FINANCIAL INSTRUMENTS
As described in Note 7 of the notes to Consolidated Financial
Statements in the Annual Report, the company follows the guidance of
SFAS 133 as amended by SFAS 138 and 149 (collectively SFAS 133) to
account for its derivative instruments and hedging activities.
Derivative instruments and related hedged items are recognized as
either assets or liabilities on the balance sheet, measured at fair
value.
SFAS 133 provides for hedge accounting treatment when certain criteria
are met. For derivative instruments designated as fair value hedges,
the gain or loss is recognized in earnings in the period of change
together with the offsetting gain or loss on the hedged item
attributable to the risk being hedged. For derivative instruments
designated as cash flow hedges, the effective portion of the derivative
gain or loss is included in Other Comprehensive Income, but not
reflected in the Statements of Consolidated Income until the
corresponding hedged transaction is settled. The ineffective portion is
reported in earnings immediately.
17
The company utilizes natural gas derivatives to manage commodity price
risk associated with servicing its load requirements. These contracts
allow the company to predict with greater certainty the effective
prices to be received by the company and the prices to be charged to
its customers. The company also periodically enters into interest-rate
swap agreements to moderate exposure to interest-rate changes and to
lower the overall cost of borrowing. The use of derivative financial
instruments is subject to certain limitations imposed by company policy
and regulatory requirements.
Contracts that meet the definition of normal purchase and sales
generally are long-term contracts that are settled by physical delivery
and, therefore, are eligible for the normal purchases and sales
exception of SFAS 133. The contracts are accounted for under accrual
accounting and recorded in Revenues or Cost of Natural Gas on the
Statements of Consolidated Income when physical delivery occurs. Due to
the adoption of SFAS 149, the company has determined that its natural
gas contracts entered into after June 30, 2003 generally do not qualify
for the normal purchases and sales exception. However, the effect of
this is minimal.
Fixed-priced Contracts and Other Derivatives
Fixed-priced Contracts and Other Derivatives on the Consolidated
Balance Sheets primarily reflect SoCalGas' unrealized gains and losses
related to long-term delivery contracts for natural gas transportation.
The company has established offsetting regulatory assets and
liabilities to the extent that these gains and losses are included in
the calculation of future rates. If gains and losses are not
recoverable or payable through future rates, the company applies hedge
accounting if certain criteria are met. If a contract no longer meets
the requirements of SFAS 133, the unrealized gains and losses and the
related regulatory asset or liability will be amortized over the
remaining contract life.
The changes in Fixed-price Contracts and Other Derivatives on the
Consolidated Balance Sheets for the six months ended June 30, 2004 were
primarily due to physical deliveries under long-term natural gas
transportation contracts.
The transactions associated with fixed-price contracts and other
derivatives had no material impact to the Statements of Consolidated
Income for the six months ended June 30, 2004 and 2003.
NOTE 4. REGULATORY MATTERS
NATURAL GAS INDUSTRY RESTRUCTURING (GIR)
As discussed in the Annual Report, in December 2001 the CPUC issued a
decision related to GIR, with implementation anticipated during 2002.
On April 1, 2004, after many delays and changes, the CPUC issued a
decision that adopts tariffs to implement the 2001 decision. However,
by that same decision, the CPUC stayed implementation of the GIR
tariffs until it issues a decision in Phase I of the Natural Gas Market
Order Instituting Ratemaking (OIR) discussed below. At that time, the
CPUC will reconcile the GIR market structure with whatever structure
results from the Phase I decision of the Natural Gas Market OIR. The
18
stayed decision, if implemented, would unbundle the costs of SoCalGas'
backbone transmission system from rates and result in revising noncore
balancing account treatment to exclude the balancing of SoCalGas'
backbone transmission costs and place SoCalGas at risk for recovery of
$80 million for transmission and $81 million for storage (current
dollars). The decision would create firm tradable rights for the
transmission system. Other noncore costs/revenues would continue to be
fully balanced until the decision in the next Biennial Cost Allocation
Proceeding (BCAP) discussed below.
NATURAL GAS MARKET OIR
The CPUC's Natural Gas Market OIR was approved on January 22, 2004, and
will be addressed in two concurrent phases. The schedule calls for a
Phase I decision by September 2004 and a Phase II decision by the end
of 2004. Further discussion of Phase I and Phase II is included in the
Annual Report. The focus of the Gas OIR is the period from 2006 to
2016. Since GIR (discussed above) would end in August 2006 and there is
overlap between GIR and the OIR issues, a number of parties (including
SoCalGas) have requested the CPUC not to implement GIR.
The California Utilities have made comprehensive filings in the OIR
outlining a proposed market structure that will help create access to
new natural gas supply sources (such as LNG) for California. In the
Phase I filing, SoCalGas and SDG&E proposed a framework to provide firm
tradable access rights for intrastate natural gas transportation;
provide SoCalGas with continued balancing account protection for
intrastate transmission and distribution revenues, thereby eliminating
throughput risk; and integrate the transmission systems of SoCalGas and
SDG&E so as to have common rates and rules. The California Utilities
have proposed that the investments necessary to access new sources of
supply be included in ratebase and that the total amount of the
investments would not exceed $200 million.
In addition, the California Utilities have filed a recommended
methodology and framework to be used by the CPUC for granting pre-
approval of new interstate transportation agreements. A draft Phase I
decision was issued on July 20, 2004. The draft decision recommends
that the utilities' pre-approval procedures be approved with some
modifications and that several issues, including supply access rate
treatment, firm access rights and transmission system integration, be
addressed by separate applications. A final CPUC decision in Phase I is
expected in September 2004.
COST OF SERVICE FILINGS
In 2002, the California Utilities filed Cost Of Service applications
with the CPUC, seeking rate increases reflecting forecasts of 2004
capital and operating costs, as further discussed in the Annual Report.
SoCalGas is requesting revenue increases of $37 million. On December
19, 2003, settlements were filed with the CPUC for SoCalGas that, if
approved, would resolve most of the Cost of Service issues. A CPUC
decision is expected later this year. The SoCalGas settlement would
reduce rate revenues by $33 million from 2003 rate revenues. A CPUC
order has provided that the new rates will be retroactive to January 1,
2004. Beginning in the first quarter of 2004, SoCalGas generally is
recognizing revenue consistent with the proposed settlement, except for
19
amounts related to pension costs, which are pending the CPUC decision
and CPUC acceptance of a related compliance filing. Resolution of the
pension matter consistent with the proposed settlement would result in
the recording of additional income at that time. To the extent, if any,
that the final CPUC decision varies from the method used to recognize
revenue prior to that decision, an accounting adjustment will be
recorded at that time. To date, the impacts of accounting consistent
with the settlement have not had a material effect on the financial
statements.
The remaining issues are included in Phase II of the Cost of Service
proceeding. In addition to recommending changes in the performance-
based regulation (PBR) formulas, the CPUC's Office of Ratepayers
Advocates (ORA) also proposed the possibility of performance penalties,
without the possibility of performance awards. Hearings took place in
June 2004. On July 21, 2004, all of the active parties in Phase II who
dealt with post test year ratemaking and performance incentives filed
for adoption of an all-party settlement agreement for most of the Phase
II issues, including annual inflation adjustments and revenue sharing.
The agreement does not cover performance incentives. The settlement
requires the California Utilities to file their next rate cases based
on a 2008 test year. For the interim years of 2005-2007, the Consumer
Price Index will be used to adjust the escalatable authorized base rate
revenues within identified floors and ceilings. It is anticipated that
the CPUC will address this matter in its decision related to Phase II
of this proceeding expected by year-end 2004.
SoCalGas 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.
PERFORMANCE-BASED REGULATION
As further described in the Annual Report, under PBR, the CPUC requires
future income potential to be tied to achieving or exceeding specific
performance and productivity goals, rather than relying solely on
expanding utility plant to increase earnings. PBR, demand-side
management (DSM) and Gas Cost Incentive Mechanism (GCIM) rewards are
not included in the company's earnings before CPUC approval is
received.
The only incentive reward approved during the first six months of 2004
was $6.3 million related to SoCalGas' Year 9 GCIM, which was approved
on February 26, 2004. This reward is subject to refunds based on the
outcome of the Border Price Investigation. The cumulative amount of
rewards subject to refund based on the outcome of the Border Price
Investigation described below is $56.9 million.
20
At June 30, 2004, the following performance incentives were pending
CPUC approval and, therefore, were not included in the company's
earnings (dollars in millions):
Program
-----------------------------------
DSM/Energy Efficiency* $ 10.9
GCIM Year 10 2.4
2003 safety .5
-----------------------------------
Total $ 13.8
-----------------------------------
* Dollar amounts shown do not include interest, franchise fees or
uncollectible amounts.
COST OF CAPITAL
Effective January 1, 2003, SoCalGas' authorized rate of return on
equity (ROE) is 10.82 percent and its return on ratebase is 8.68
percent. As discussed in the Annual Report, these rates will continue
to be effective until 2008 unless market interest-rate changes are
large enough to trigger an automatic adjustment. The automatic
adjustment occurs when the 12-month trailing average of 30-year
Treasury bond rates and the Global Insight forecast of the 30-year
Treasury bond rate 12 months ahead vary by greater than 150 basis
points from the benchmark, which is currently 5.38 percent. The 12-
month trailing average was 5.11 percent at June 30, 2004.
BIENNIAL COST ALLOCATION PROCEEDING
The BCAP determines the allocation of authorized costs between customer
classes for natural gas transportation service provided by the company
and adjusts rates to reflect variances in customer demand as compared
to the forecasts previously used in establishing transportation rates.
SoCalGas filed with the CPUC its 2005 BCAP application in September
2003, requesting updated transportation rates effective January 1,
2005. In November 2003, an Assigned Commissioner Ruling delayed the
BCAP applications until a decision is issued in the GIR implementation
proceeding. As a result of the April 1, 2004 decision on GIR
implementation as described in "Natural Gas Industry Restructuring,"
above, on May 27, 2004 the Administrative Law Judge (ALJ) in the 2005
BCAP issued a decision dismissing the BCAP applications. The California
Utilities would be required to file new BCAP applications after the
stay of the GIR implementation decision is lifted. As a result of the
deferrals and the forecasted significant decline in noncore gas
throughput on SoCalGas' system, in December 2002 the CPUC issued a
decision approving 100 percent balancing account protection for
SoCalGas' risk on local transmission and distribution revenues from
January 1, 2003 until the CPUC issues its next BCAP decision. SoCalGas
is seeking to continue this balancing account protection in the Natural
Gas OIR proceeding.
21
BORDER PRICE INVESTIGATION
In November 2002, the CPUC instituted an investigation into the
Southern California natural gas market and the price of natural gas
delivered to the California-Arizona border between March 2000 and May
2001. If the investigation determines that the conduct of any party to
the investigation, including the California Utilities, contributed to
the natural gas price spikes, the CPUC may modify the party's natural
gas procurement incentive mechanism, reduce the amount of any
shareholder award for the period involved, and/or order the party to
issue a refund to ratepayers. Hearings began on June 29, 2004 and
continued through July 15, 2004. A draft decision is expected in
October 2004. The CPUC may hold a second round of hearings to consider
whether Sempra Energy or any of its non-utility subsidiaries
contributed to the price spikes. Final decisions are expected by late
2004. The company believes that the CPUC will find that the California
Utilities acted in the best interests of its core customers and that
none of the Sempra Energy companies was responsible for the price
spikes. The ORA filed testimony supporting the GCIM and the actions of
SoCalGas during this period.
CPUC INVESTIGATION OF ENERGY-UTILITY HOLDING COMPANIES
The CPUC has initiated an investigation into the relationship between
California's IOUs and their parent holding companies. The CPUC broadly
determined that it could, in appropriate circumstances, require the
holding company to provide cash to a utility subsidiary to cover its
operating expenses and working capital to the extent they are not
adequately funded through retail rates. This would be in addition to
the requirement of holding companies to cover their utility
subsidiaries' capital requirements, as the IOUs previously acknowledged
in connection with the holding companies' formations. In January 2002
the CPUC ruled on jurisdictional issues, deciding that the CPUC had
jurisdiction to create the holding company system and, therefore,
retains jurisdiction to enforce conditions to which the holding
companies had agreed.
In an opinion issued May 21, 2004, the California Court of Appeal
upheld the CPUC's assertion of limited enforcement jurisdiction, but
concluded that the CPUC's interpretation of the "first priority"
condition (that the holding companies could be required to infuse cash
into the utilities as necessary to meet the utilities' obligation to
serve) was not ripe for review at this time. On June 30, 2004, the
company requested review of the Court of Appeal's decision on the
jurisdictional issue by the California Supreme Court. To date, the
Supreme Court, which has discretionary authority to grant or deny
review, has not acted upon this request.
22
NOTE 5. 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.
Antitrust Litigation
Class-action and individual lawsuits filed in 2000 and currently
consolidated in San Diego Superior Court seek damages, alleging that
Sempra Energy, SoCalGas and SDG&E, along with El Paso Energy Corp. (El
Paso) and several of its affiliates, unlawfully sought to control
natural gas and electricity markets. In March 2003, plaintiffs in these
cases and the applicable El Paso entities (whose cases involved
unrelated claims not applicable to Sempra Energy, SoCalGas or SDG&E)
announced that they had reached a $1.7 billion settlement, of which
$125 million is allocated to customers of the California Utilities. The
Court approved that settlement in December 2003. The proceeding
against Sempra Energy and the California Utilities has not been settled
and continues to be litigated. On July 22, 2004, the court heard oral
argument on a motion for summary judgment brought by Sempra Energy and
the California Utilities and is expected to issue a decision in August
2004. Trial is set for September 7, 2004.
Natural Gas Cases: Lawsuits have been filed by the Attorneys General
of Arizona and Nevada, alleging that El Paso and certain Sempra Energy
subsidiaries unlawfully sought to control the natural gas market in
their respective states. In October 2003, the Nevada state court denied
defendants' motion to dismiss the complaint. On April 12, 2004, the
Sempra Energy defendants filed a motion for reconsideration. In April
2003, Sierra Pacific Resources and its utility subsidiary Nevada Power
filed a lawsuit in U.S. District Court in Las Vegas against major
natural gas suppliers, including Sempra Energy, the California
Utilities and other company subsidiaries, seeking damages resulting
from an alleged conspiracy to drive up or control natural gas prices,
eliminate competition and increase market volatility, breach of
contract and wire fraud. On January 27, 2004, the U.S. District Court
dismissed the Sierra Pacific Resources case against all of the
defendants, determining that this is a matter for the FERC to resolve.
The court granted plaintiffs' request to amend their complaint, which
they did. On July 15, 2004, Sempra Energy filed another motion to
dismiss, which is scheduled to be heard on September 23, 2004.
Price Reporting Practices
On July 8, 2004, the City and County of San Francisco and the County of
Santa Clara and on July 18, 2004 the County of San Diego brought
actions, alleging that energy prices were unlawfully manipulated by
defendants' reporting artificially inflated natural gas prices to trade
publications and by entering into wash trades, in San Diego Superior
Court against Sempra Energy, Sempra Energy Trading, SoCalGas and SDG&E.
23
Other
Customers of the California Utilities will receive benefits under
a settlement with El Paso resolving a number of civil and
administrative proceedings surrounding the high natural gas and
electric prices experienced in several Western states during the March
2000 through May 2001 period. A total amount of settlement funds of
$40.7 million to SoCalGas' core gas customers will be received over a
period of 20 years. An initial lump sum payment of $12 million was
received in June 2004, which will be followed by 19 annual payments.
ITEM 2.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with the
financial statements contained in this Form 10-Q and "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" contained in the Annual Report.
RESULTS OF OPERATIONS
Natural gas revenues increased to $2.0 billion for the six months ended
June 30, 2004 from $1.8 billion for the corresponding period in 2003,
and the cost of natural gas increased to $1.1 billion in 2004 from $1.0
billion in 2003. These increases were primarily attributable to natural
gas cost increases, which are passed on to customers, and increased
volumes. Additionally, natural gas revenues were relatively unchanged
at $847 million for the quarter ended June 30, 2004 compared to $820
million for the corresponding period in 2003, and the cost of natural
gas was relatively unchanged at $425 million in 2004 compared to $421
million in 2003. Higher natural gas costs in the second quarter of 2004
were offset by lower gas sales volumes.
Under the current regulatory framework, the cost of natural gas
purchased for customers and the variations in that cost are passed
through to the customers on a substantially concurrent basis. However,
SoCalGas' GCIM allows SoCalGas to share in the savings or costs from
buying natural gas for customers below or above monthly benchmarks. The
mechanism permits full recovery of all costs within a tolerance band
above the benchmark price and refunds all savings within a tolerance
band below the benchmark price. The costs or savings outside the
tolerance band are shared between customers and shareholders.
In 2002, the California Utilities filed Cost Of Service applications
with the CPUC, seeking rate increases reflecting forecasts of 2004
capital and operating costs, as further discussed in the Annual Report.
In accordance with generally accepted accounting principles, SoCalGas
is generally recognizing 2004 revenue consistent with the proposed
settlement, except for amounts related to pension costs which are
pending the CPUC decision and CPUC acceptance of a related compliance
filing. Resolution of the pension matter consistent with the proposed
settlement would result in the recording of additional income at that
time. To the extent, if any, that the final CPUC decision varies from
the method used to recognize revenue prior to that decision, an
24
accounting adjustment will be recorded at that time. To date, the
impacts of accounting consistent with the settlement have not had a
material effect on the financial statements.
The table below summarizes natural gas volumes and revenues by customer
class for the six months ended June 30, 2004 and 2003.
Natural Gas Sales, Transportation and Exchange
(Volumes in billion cubic feet, dollars in millions)
Gas Sales Transportation & Exchange Total
--------------------------------------------------------------
Volumes Revenue Volumes Revenue Volumes Revenue
--------------------------------------------------------------
2004:
Residential 136 $ 1,323 1 $ 4 137 $ 1,327
Commercial and industrial 56 442 134 92 190 534
Electric generation plants -- -- 67 20 67 20
Wholesale -- -- 78 16 78 16
--------------------------------------------------------------
192 $ 1,765 280 $ 132 472 1,897
Balancing accounts and other 98
--------
Total $ 1,995
- -----------------------------------------------------------------------------------------
2003:
Residential 129 $ 1,188 1 $ 4 130 $ 1,192
Commercial and industrial 58 411 138 86 196 497
Electric generation plants -- -- 67 18 67 18
Wholesale -- -- 68 13 68 13
--------------------------------------------------------------
187 $ 1,599 274 $ 121 461 1,720
Balancing accounts and other 108
--------
Total $ 1,828
- -----------------------------------------------------------------------------------------
SoCalGas recorded net income of $107 million and $96 million for the
six-month periods ended June 30, 2004 and 2003, respectively, and net
income of $51 million and $38 million for the quarters ended June 30,
2004 and 2003, respectively. The changes were primarily due to improved
operating results in 2004.
CAPITAL RESOURCES AND LIQUIDITY
SoCalGas' operations are the major source of liquidity. In addition,
working capital requirements can be met through the issuance of short-
term and long-term debt. Cash requirements primarily consist of capital
expenditures for utility plant.
At June 30, 2004, the company had $34 million in cash and $550 million
in available unused, committed lines of credit (of which PE had $250
million for the sole purpose of providing loans to Sempra Energy Global
Enterprises, another subsidiary of Sempra Energy, and SoCalGas had $300
million). See "Cash Flows from Financing Activities" for discussion on
changes in the credit facility in 2004.
25
Management believes that cash flows from operations and debt issuances
will be adequate to finance capital expenditure requirements and other
commitments. Management continues to regularly monitor SoCalGas' 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.
CASH FLOWS FROM OPERATING ACTIVITIES
Net cash provided by PE's operating activities totaled $627 million and
$440 million for the six months ended June 30, 2004 and 2003,
respectively. PE's operating activities included $585 million and $448
million, respectively, from SoCalGas. The increases were primarily
attributable to 2004's higher increase in overcollected regulatory
balancing accounts and a higher decrease in accounts receivable.
For the six months ended June 30, 2004, the company made pension plan
contributions of $3 million and payments for other postretirement
benefit plans of $27 million.
CASH FLOWS FROM INVESTING ACTIVITIES
Net cash used in PE's investing activities totaled $348 million and $28
million for the six months ended June 30, 2004 and 2003, respectively.
Net cash used in SoCalGas' investing activities totaled $307 million and
$237 million for the six months ended June 30, 2004 and 2003,
respectively. The changes were primarily due to increased advances to
Sempra Energy in 2004.
Significant capital expenditures in 2004 are expected to be for
improvements to the distribution and transmission systems. These
expenditures are expected to be financed by cash flows from operations
and security issuances.
In connection with the importation of additional sources of natural gas
into Southern California, for which the California Utilities have made
filings with the CPUC, the California Utilities could install capital
facilities estimated at up to $200 million over three years, starting in
2005, in order to connect with new delivery locations. The expenditures
would be included in utility ratebases or would be reimbursed by LNG
project developers dependent on CPUC review of the projects and on the
outcome of the Gas Market Order Instituting Investigation Phase II
proceeding.
CASH FLOWS FROM FINANCING ACTIVITIES
Net cash used in PE's financing activities totaled $277 million and $422
million for the six months ended June 30, 2004 and 2003, respectively.
Net cash used in SoCalGas' financing activities totaled $276 million and
$221 million for the six months ended June 30, 2004 and 2003,
respectively. The changes were attributable to lower dividend payments
by PE and higher dividend payments by SoCalGas in 2004.
26
In May 2004, the California Utilities obtained a combined $500 million
three-year syndicated revolving credit facility to replace their
expiring 364-day facility of a like amount. Under the facility, each
utility may borrow up to $300 million, subject to a combined borrowing
limit of $500 million. Borrowings would bear interest at rates varying
with market rates and the borrowing utility's credit rating. The
agreement requires each utility to maintain, at the end of each
quarter, a ratio of total indebtedness to total capitalization (as
defined in the agreement) of no more than 60 percent. Borrowings under
the agreement would be individual obligations of the borrowing utility
and a default by one utility would not constitute a default or preclude
borrowings by the other.
FACTORS INFLUENCING FUTURE PERFORMANCE
Performance of the companies will depend primarily on the ratemaking
and regulatory process, electric and natural gas industry
restructuring, and the changing energy marketplace. These factors are
discussed in the Annual Report and in Note 4 of the notes to
Consolidated Financial Statements herein.
NEW ACCOUNTING STANDARDS
Relevant pronouncements that have recently become effective and have
had a significant effect on the company are SFAS Nos. 143 and 149 as
discussed in Note 2 of the notes to Consolidated Financial Statements.
Pronouncements that have or are likely to have a material effect on
future earnings are described below.
SFAS 143, "Accounting for Asset Retirement Obligations": Beginning in
2003, SFAS 143 requires entities to record liabilities for future costs
expected to be incurred when assets are retired from service, if the
retirement process is legally required. It also requires the company to
reclassify amounts recovered in rates for future removal costs not
covered by a legal obligation from accumulated depreciation to a
regulatory liability. Further discussion is provided in Note 2 of the
notes to Consolidated Financial Statements.
SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities": SFAS 149 amends and clarifies accounting for
derivative instruments, including certain derivative instruments
embedded in other contracts, and for hedging activities under SFAS 133.
Under SFAS 149, natural gas forward contracts that are subject to
unplanned netting do not qualify for the normal purchases and normal
sales exception, whereby derivatives are not required to be marked to
market when the contract is usually settled by the physical delivery of
natural gas. The company has determined that all natural gas contracts
are subject to unplanned netting and as such, these contracts will be
marked to market. Implementation of SFAS 149 on July 1, 2003 did not
have a material impact on reported net income.
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.
27
As of June 30, 2004, the total Value at Risk of SoCalGas' positions was
not material.
ITEM 4. CONTROLS AND PROCEDURES
The companies have designed and maintain disclosure controls and
procedures to ensure that information required to be disclosed in the
companies' 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 companies'
management, including their Chief Executive Officers and Chief
Financial Officers, as appropriate, to allow timely decisions regarding
required disclosure. In designing and evaluating these controls and
procedures, management recognizes that any system of controls and
procedures, no matter how well designed and operated, can provide only
reasonable assurance of achieving the desired objectives and
necessarily applies judgment in evaluating the cost-benefit
relationship of other possible controls and procedures.
Under the supervision and with the participation of management,
including the Chief Executive Officers and the Chief Financial
Officers, the companies evaluated the effectiveness of the design and
operation of the companies' disclosure controls and procedures as of
June 30, 2004, the end of the period covered by this report. Based on
that evaluation, the companies' Chief Executive Officers and Chief
Financial Officers concluded that the companies' disclosure controls
and procedures were effective at the reasonable assurance level.
There has been no change in the companies' internal controls over
financial reporting during the companies' most recent fiscal quarter
that has materially affected, or is reasonably likely to materially
affect, the companies' internal controls over financial reporting.
ITEM 5. OTHER INFORMATION
Effective May 1, 2004, Debra L. Reed, President of SoCalGas and SDG&E,
also became their Chief Operating Officer. Simultaneously, Steven D.
Davis, who remains Senior Vice President, External Relations, succeeded
her as Chief Financial Officer.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Except as described in Notes 4 and 5 of the notes to Consolidated
Financial Statements, neither the companies nor their subsidiaries are
party to, nor is their property the subject of, any material pending
legal proceedings other than routine litigation incidental to their
businesses.
28
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
Exhibit 12 - Computation of ratios
12.1 Computation of Ratio of Earnings to Fixed Charges of PE.
12.2 Computation of Ratio of Earnings to Fixed Charges of
SoCalGas.
Exhibit 31 -- Section 302 Certifications
31.1 Statement of PE's Chief Executive Officer pursuant
to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
31.2 Statement of PE's Chief Financial Officer pursuant
to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
31.3 Statement of SoCalGas' Chief Executive Officer pursuant
to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
31.4 Statement of SoCalGas' 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 PE's Chief Executive Officer pursuant
to 18 U.S.C. Sec. 1350.
32.2 Statement of PE's Chief Financial Officer pursuant
to 18 U.S.C. Sec. 1350.
32.3 Statement of SoCalGas' Chief Executive Officer pursuant
to 18 U.S.C. Sec. 1350.
32.4 Statement of SoCalGas' Chief Financial Officer pursuant
to 18 U.S.C. Sec. 1350.
(b) Reports on Form 8-K
The following reports on Form 8-K were filed after March 31, 2004:
Current Report on Form 8-K filed April 29, 2004, filing as an exhibit
Sempra Energy's press release of April 29, 2004, giving the financial
results for the quarter ended March 31, 2004.
Current Report on Form 8-K filed August 5, 2004, filing as an exhibit
Sempra Energy's press release of August 5, 2004, giving the financial
results for the quarter ended June 30, 2004.
29
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrants have duly caused this report to be signed on their behalf by
the undersigned thereunto duly authorized.
PACIFIC ENTERPRISES
-------------------
(Registrant)
Date: August 5, 2004 By: /s/ F. H. Ault
----------------------------
F. H. Ault
Sr. Vice President and Controller
SOUTHERN CALIFORNIA GAS COMPANY
-------------------------------
(Registrant)
Date: August 5, 2004 By: /s/ S. D. Davis
---------------------------
S. D. Davis
Sr. Vice President-External Relations
and Chief Financial Officer