UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2004
-------------------------------------
Commission file number 1-3779
---------------------------------------------
SAN DIEGO GAS & ELECTRIC COMPANY
----------------------------------------------------------
(Exact name of registrant as specified in its charter)
California 95-1184800
- ------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
8330 Century Park Court, San Diego, California 92123
- -------------------------------------------------------------------
(Address of principal executive offices)
(Zip Code)
(619) 696-2000
----------------------------------------------------------
(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 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: Wholly owned by Enova Corporation
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, the California Department of Water
Resources, and the Federal Energy Regulatory Commission; capital market
conditions, inflation rates, interest rates and exchange rates; energy
and trading markets, including the timing and extent of changes in
commodity prices; weather conditions and conservation efforts; war and
terrorist attacks; business, regulatory and legal decisions; the status
of deregulation of retail natural gas and electricity delivery; the
timing and success of business development efforts; and other
uncertainties, all of which are difficult to predict and many of which
are beyond the control of the company . Readers are cautioned not to
rely unduly on any forward-looking statements and are urged to review
and consider carefully the risks, uncertainties and other factors which
affect the company's business described in this report and other
reports filed by the company from time to time with the Securities and
Exchange Commission.
3
PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
<table>
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED INCOME
(Dollars in millions)
<caption>
Three months ended
June 30,
------------------
2004 2003
------- -------
<s> <c> <c>
Operating revenues
Electric $ 425 $ 402
Natural gas 111 118
------- -------
Total operating revenues 536 520
------- -------
Operating expenses
Cost of electric fuel and purchased power 155 137
Cost of natural gas 63 67
Other operating expenses 151 142
Depreciation and amortization 67 59
Income taxes 26 34
Franchise fees and other taxes 26 28
------- -------
Total operating expenses 488 467
------- -------
Operating income 48 53
------- -------
Other income and (deductions)
Interest income 1 1
Regulatory interest - net (2) (2)
Allowance for equity funds used
during construction 3 3
Income taxes on non-operating income (1) 4
------- -------
Total 1 6
------- -------
Interest charges
Long-term debt 16 17
Other 3 1
Allowance for borrowed funds
used during construction (1) (1)
------- -------
Total 18 17
------- -------
Net income 31 42
Preferred dividend requirements 1 1
------- -------
Earnings applicable to common shares $ 30 $ 41
======= =======
See notes to Consolidated Financial Statements.
</table>
4
<table>
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED INCOME
(Dollars in millions)
<caption>
Six months ended
June 30,
------------------
2004 2003
------- -------
<s> <c> <c>
Operating revenues
Electric $ 810 $ 799
Natural gas 306 283
------- -------
Total operating revenues 1,116 1,082
------- -------
Operating expenses
Cost of electric fuel and purchased power 282 300
Cost of natural gas 172 152
Other operating expenses 291 268
Depreciation and amortization 135 116
Income taxes 71 74
Franchise fees and other taxes 55 54
------- -------
Total operating expenses 1,006 964
------- -------
Operating income 110 118
------- -------
Other income and (deductions)
Interest income 6 3
Regulatory interest - net (3) (4)
Allowance for equity funds used
during construction 5 6
Income taxes on non-operating income (2) 1
Other - net 1 --
------- -------
Total 7 6
------- -------
Interest charges
Long-term debt 32 34
Other 5 3
Allowance for borrowed funds
used during construction (2) (2)
------- -------
Total 35 35
------- -------
Net income 82 89
Preferred dividend requirements 2 3
------- -------
Earnings applicable to common shares $ 80 $ 86
======= =======
See notes to Consolidated Financial Statements.
</table>
5
<table>
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
<caption>
-----------------------------
June 30, December 31,
2004 2003
------------- -------------
<s> <c> <c>
ASSETS
Utility plant - at original cost $ 6,021 $ 5,773
Accumulated depreciation and amortization (1,746) (1,737)
------- -------
Utility plant - net 4,275 4,036
------- -------
Nuclear decommissioning trusts 566 570
------- -------
Current assets:
Cash and cash equivalents 294 148
Accounts receivable - trade 156 173
Accounts receivable - other 29 17
Interest receivable 38 37
Due from affiliates 27 151
Deferred income taxes 78 64
Regulatory assets arising from fixed-price contracts
and other derivatives 58 59
Other regulatory assets 77 81
Inventories 62 60
Other 26 27
------- -------
Total current assets 845 817
------- -------
Other assets:
Deferred taxes recoverable in rates 267 273
Regulatory assets arising from fixed-price contracts
and other derivatives 473 502
Other regulatory assets 242 281
Sundry 60 48
------- -------
Total other assets 1,042 1,104
------- -------
Total assets $ 6,728 $ 6,527
======= =======
See notes to Consolidated Financial Statements.
</table>
6
<table>
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
<caption>
-----------------------------
June 30, December 31,
2004 2003
------------- -------------
<s> <c> <c>
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock (255 million shares authorized;
117 million shares outstanding) $ 938 $ 938
Retained earnings 284 369
Accumulated other comprehensive income (loss) (43) (43)
------- -------
Total common equity 1,179 1,264
Preferred stock not subject to mandatory redemption 79 79
------- -------
Total shareholders' equity 1,258 1,343
Long-term debt 1,055 1,087
------- -------
Total capitalization 2,313 2,430
------- -------
Current liabilities:
Accounts payable 160 193
Interest payable 10 10
Income taxes payable 208 240
Due to affiliates 11 --
Regulatory balancing accounts - net 348 338
Fixed-price contracts and other derivatives 58 59
Current portion of long-term debt 317 66
Other 234 294
------- -------
Total current liabilities 1,346 1,200
------- -------
Deferred credits and other liabilities:
Due to affiliates 183 21
Customer advances for construction 42 49
Deferred income taxes 370 353
Deferred investment tax credits 39 40
Regulatory liabilities arising from cost
of removal obligations 868 846
Regulatory liabilities arising from asset
retirement obligations 284 281
Fixed-price contracts and other derivatives 473 502
Asset retirement obligations 308 303
Mandatorily redeemable preferred securities 20 21
Deferred credits and other 482 481
------- -------
Total deferred credits and other liabilities 3,069 2,897
------- -------
Contingencies and commitments (Note 6)
Total liabilities and shareholders' equity $ 6,728 $ 6,527
======= =======
See notes to Consolidated Financial Statements.
</table>
7
<table>
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in millions)
<caption> Six months ended
June 30,
------------------
2004 2003
------- -------
<s> <c> <c>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 82 $ 89
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization 135 116
Deferred income taxes and investment tax credits 2 (69)
Non-cash rate reduction bond expense 36 32
Other - net -- (2)
Net change in other working capital components (86) 44
Changes in other assets (4) --
Changes in other liabilities (6) 7
------- -------
Net cash provided by operating activities 159 217
------- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (181) (183)
Affiliate loan 122 41
Other - net (3) (6)
------- -------
Net cash used in investing activities (62) (148)
------- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid (165) (100)
Preferred dividends paid (2) (3)
Issuances of long-term debt 251 --
Payments on long-term debt (32) (32)
Redemptions of preferred stock (3) (1)
------- -------
Net cash provided by (used in) financing activities 49 (136)
------- -------
Increase (decrease) in cash and cash equivalents 146 (67)
Cash and cash equivalents, January 1 148 159
------- -------
Cash and cash equivalents, June 30 $ 294 $ 92
======= =======
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized $ 32 $ 33
======= =======
Income tax payments, net of refunds $ 94 $ 138
======= =======
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 San Diego Gas & Electric
Company (SDG&E or the company). SDG&E's common stock is wholly owned by
Enova Corporation, which is a wholly owned subsidiary of Sempra Energy,
a California-based Fortune 500 holding company. The financial
statements herein are the Consolidated Financial Statements of SDG&E
and its sole subsidiary, SDG&E Funding LLC.
Sempra Energy also indirectly owns all of the common stock of Southern
California Gas Company (SoCalGas). SDG&E and SoCalGas are collectively
referred to herein as "the California Utilities."
The accompanying Consolidated Financial Statements have been prepared
in accordance with the interim-period-reporting requirements of Form
10-Q. Results of operations for interim periods are not necessarily
indicative of results for the entire year. In the opinion of
management, the accompanying statements reflect all adjustments
necessary for a fair presentation. These adjustments are only of a
normal recurring nature. Certain changes in classification have been
made to prior presentations to conform to the current financial
statement presentation. Specifically, certain December 31, 2003 income
tax liabilities have been reclassified from Deferred Income Taxes to
current Income Taxes Payable and to Deferred Credits and Other
Liabilities to conform to the current presentation of these items.
Information in this Quarterly Report is unaudited and should be read in
conjunction with the Annual Report on Form 10-K for the year ended
December 31, 2003 (Annual Report) and the Quarterly Report on Form 10-Q
for the first quarter of 2004.
The company's significant accounting policies are described in Note 1
of the notes to Consolidated Financial Statements in the Annual Report.
The same accounting policies are followed for interim reporting
purposes.
SDG&E accounts for the economic effects of regulation on utility
operations in accordance with Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types
of Regulation."
NOTE 2. NEW ACCOUNTING STANDARDS
Stock-Based Compensation: On March 31, 2004, the Financial Accounting
Standards Board (FASB) issued a proposed Exposure Draft (ED) to amend
SFAS 123, "Accounting for Stock-Based Compensation." The proposed
statement would eliminate the choice of accounting for share-based
compensation transactions using Accounting Principles Board (APB)
Opinion No. 25, "Accounting for Stock Issued to Employees," whereby no
expense is recorded for most stock options and instead generally
require that such transactions be accounted for using a fair-value-
based method, whereby expense is recorded for stock options. It would
also prohibit application by restating prior periods and would require
9
that expense be recognized only for those options that actually vest.
If passed, the proposed ED would be effective for the company in 2005.
SFAS 132 (revised 2003), "Employers' Disclosures about Pensions and
Other Postretirement Benefits": This statement revises employers'
disclosures about pension plans and other postretirement benefit plans,
effective in 2004. It requires disclosures beyond those in the original
SFAS 132 related to the assets, obligations, cash flows and net
periodic benefit cost of defined benefit pension plans and other
defined postretirement plans. In addition, it requires interim-period
disclosures regarding the amount of net periodic benefit cost
recognized and the total amount of the employers' contributions paid
and expected to be paid during the current fiscal year. It does not
change the measurement or recognition of those plans.
The following table provides the components of benefit costs for the
three months and six months ended June 30:
<table>
<caption>
Other
Pension Benefits Postretirement Benefits
--------------------------------------------
Three months ended Three months ended
June 30, June 30,
--------------------------------------------
(Dollars in millions) 2004 2003 2004 2003
- -------------------------------------------------------------------------------
<s> <c> <c> <c> <c>
Service cost $ 1 $ 5 $ -- $ 1
Interest cost 10 11 1 1
Expected return on assets (9) (8) -- (1)
Amortization of
transition obligation -- -- 1 1
Regulatory adjustment -- -- (1) --
-------------------------------------------
Total net periodic benefit cost $ 2 $ 8 $ 1 $ 2
- -------------------------------------------------------------------------------
</table>
<table>
<caption>
Other
Pension Benefits Postretirement Benefits
--------------------------------------------
Six months ended Six months ended
June 30, June 30,
--------------------------------------------
(Dollars in millions) 2004 2003 2004 2003
- -------------------------------------------------------------------------------
<s> <c> <c> <c> <c>
Service cost $ 4 $ 10 $ 1 $ 1
Interest cost 20 21 2 2
Expected return on assets (19) (17) (1) (1)
Amortization of:
Transition obligation -- -- 1 1
Prior service cost 1 1 -- --
Actuarial loss -- 1 -- --
--------------------------------------------
Total net periodic benefit cost $ 6 $ 16 $ 3 $ 3
- -------------------------------------------------------------------------------
</table>
10
Note 6 of the notes to Consolidated Financial Statements in the Annual
Report discusses the company's expected contribution to its pension
plan and other postretirement benefit plans in 2004. $2 million and $1
million of contributions have been made to its other postretirement
benefit plans for the six months and the quarter, respectively, ended
June 30, 2004. There was no contribution made to its pension plan for
the six months ended June 30, 2004.
SFAS 143, "Accounting for Asset Retirement Obligations": Beginning in
2003, SFAS 143 requires entities to record liabilities for future costs
expected to be incurred when assets are retired from service, if the
retirement process is legally required. It also requires the
reclassification of estimated removal costs, which have historically
been recorded in accumulated depreciation, to a regulatory liability.
At June 30, 2004 and December 31, 2003, the estimated removal costs
recorded as a regulatory liability were $868 million and $846 million,
respectively.
The change in the asset retirement obligations for the six months ended
June 30, 2004 is as follows (dollars in millions):
Balance as of January 1, 2004 $ 326
Accretion expense (interest) 11
Payments (6)
------
Balance as of June 30, 2004 $ 331*
======
* The current portion of the obligation is included in Other Current
Liabilities on the Consolidated Balance Sheets.
SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities": Effective July 1, 2003, SFAS 149 amended and
clarified accounting for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging
activities under SFAS 133. Under SFAS 149 natural gas forward contracts
that are subject to unplanned netting generally do not qualify for the
normal purchases and normal sales exception, whereby derivatives are
not required to be marked to market when the contract is usually
settled by the physical delivery of natural gas. ("Netting" refers to
contract settlement by paying or receiving the monetary difference
between the contract price and the market price at the date on which
physical delivery would have occurred.) In addition, effective January
1, 2004, power contracts that are subject to unplanned netting and that
do not meet the normal purchases and normal sales exception under SFAS
149 will continue to be marked to market. Implementation of SFAS 149
did not have a material impact on reported net income. Additional
information on derivative instruments is provided in Note 4.
SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of Liabilities and Equity": The company adopted SFAS
150 beginning July 1, 2003 by reclassifying $24 million of mandatorily
redeemable preferred stock to Deferred Credits and Other Liabilities
and to Other Current Liabilities on the Consolidated Balance Sheets.
11
FASB Interpretation No. (FIN) 46, "Consolidation of Variable Interest
Entities an interpretation of Accounting Research Bulletin (ARB) No.
51": FIN 46 requires the primary beneficiary of a variable interest
entity's activities to consolidate the entity. Contracts under which
SDG&E acquires power from generation facilities otherwise unrelated to
SDG&E could result in a requirement for SDG&E to consolidate the entity
that owns the facility. As permitted by the interpretation, SDG&E is
continuing the process of determining whether it has any such
situations and, if so, gathering the information that would be needed
to perform the consolidation. The effects of this, if any, are not
expected to significantly affect the financial position of SDG&E and
there would be no effect on results of operations or liquidity.
FASB Staff Position (FSP) 106-1 and 106-2, "Accounting and Disclosure
Requirements Related to the Medicare Prescription Drug, Improvement and
Modernization Act of 2003": Issued January 12, 2004, FSP 106-1 allowed
the company to make a one-time election during the first quarter of
2004 to defer accounting for the effects of the Medicare Prescription
Drug, Improvement and Modernization Act of 2003 (the Act) until
authoritative guidance on the accounting for federal subsidies was
issued.
In May 2004, FSP 106-1 was superseded by FSP 106-2, which provides
guidance on the accounting for the effects of the Act by employers
whose prescription drug benefits are actuarially equivalent to the drug
benefit under Medicare Part D. In such a case, the employer includes
the federal subsidy in measuring the accumulated postretirement benefit
obligation (APBO). The resulting reduction in the APBO is recognized
as an actuarial gain and the employer's share of future costs under the
plan is reflected in current period service cost. FSP 106-2 also
provides disclosure guidance about the effects of the subsidy for an
employer who offers postretirement prescription drug coverage, but is
unable to determine whether the plan's provisions are actuarially
equivalent to the Medicare Part D benefit. For the company, FSP 106-2
is effective for the quarter ending September 30, 2004. The company has
not yet determined whether the benefits provided by the plans are
actuarially equivalent, and, at June 30, 2004, the APBO and net
periodic postretirement benefit costs do not reflect any amount
associated with the subsidy.
12
NOTE 3. COMPREHENSIVE INCOME
The following is a reconciliation of net income to comprehensive
income.
Three months Six months
ended ended
June 30, June 30,
-----------------------------------
(Dollars in millions) 2004 2003 2004 2003
- -----------------------------------------------------------------
Net income $ 31 $ 42 $ 82 $ 89
Minimum pension liability
adjustments -- -- -- (6)*
-----------------------------------
Comprehensive income $ 31 $ 42 $ 82 $ 83
- -----------------------------------------------------------------
* This amount does not equal the change in the reported balance
of accumulated other comprehensive income due to rounding.
NOTE 4. FINANCIAL INSTRUMENTS
As described in Note 8 of the notes to Consolidated Financial
Statements in the Annual Report, the company follows the guidance of
SFAS 133 as amended by SFAS 138 and 149 (collectively SFAS 133) to
account for its derivative instruments and hedging activities.
Derivative instruments and related hedged items are recognized as
either assets or liabilities on the balance sheet, measured at fair
value.
SFAS 133 provides for hedge accounting treatment when certain criteria
are met. For derivative instruments designated as fair value hedges,
the gain or loss is recognized in earnings in the period of change
together with the offsetting gain or loss on the hedged item
attributable to the risk being hedged. For derivative instruments
designated as cash flow hedges, the effective portion of the derivative
gain or loss is included in Other Comprehensive Income, but not
reflected in the Statements of Consolidated Income until the
corresponding hedged transaction is settled. The ineffective portion is
reported in earnings immediately.
The company utilizes natural gas and energy derivatives to manage
commodity price risk associated with servicing its load requirements.
These contracts allow the company to predict with greater certainty the
effective prices to be received by the company and the prices to be
charged to its customers. The company also periodically enters into
interest-rate swap agreements to moderate exposure to interest-rate
changes and to lower the overall cost of borrowing. The use of
derivative financial instruments is subject to certain limitations
imposed by company policy and regulatory requirements.
Contracts that meet the definition of normal purchase and sales
generally are long-term contracts that are settled by physical delivery
and, therefore, are eligible for the normal purchases and sales
13
exception of SFAS 133. The contracts are accounted for under accrual
accounting and recorded in Revenues or Cost of Sales on the Statements
of Consolidated Income when physical delivery occurs. Due to the
adoption of SFAS 149, the company has determined that its natural gas
contracts entered into after June 30, 2003 generally do not qualify for
the normal purchases and sales exception. However, the effect of this
is minimal.
Fixed-priced Contracts and Other Derivatives
Fixed-priced Contracts and Other Derivatives on the Consolidated
Balance Sheets primarily reflect SDG&E's unrealized gains and losses
related to long-term delivery contracts for purchased power and natural
gas transportation. The California Utilities have established
offsetting regulatory assets and liabilities to the extent that these
gains and losses are included in the calculation of future rates. If
gains and losses are not recoverable or payable through future rates,
the company applies hedge accounting if certain criteria are met. If a
contract no longer meets the requirements of SFAS 133, the unrealized
gains and losses and the related regulatory asset or liability will be
amortized over the remaining contract life.
The changes in Fixed-price Contracts and Other Derivatives on the
Consolidated Balance Sheets for the six months ended June 30, 2004 were
primarily due to physical deliveries under long-term purchased-power
and natural gas transportation contracts.
The transactions associated with fixed-price contracts and other
derivatives had no material impact to the Statements of Consolidated
Income for the six months ended June 30, 2004 and 2003.
NOTE 5. REGULATORY MATTERS
ELECTRIC INDUSTRY REGULATION
The restructuring of California's electric utility industry has
significantly affected the company's electric utility operations. In
addition, the power crisis of 2000-2001 caused the California Public
Utilities Commission (CPUC) to adjust its plan for restructuring the
electricity industry. The background of these issues is described in
the Annual Report.
The California Department of Water Resources' (DWR) operating agreement
with SDG&E, approved by the CPUC, provides that SDG&E is acting as a
limited agent on behalf of the DWR in undertaking energy sales and
natural gas procurement functions under the DWR contracts allocated to
SDG&E's customers. Legal and financial responsibility associated with
these activities continues to reside with the DWR. Therefore, the
revenues and costs associated with the contracts are not included in the
Statements of Consolidated Income.
On May 27, 2004, the CPUC denied Southern California Edison's (Edison)
Petition to Modify the CPUC decision that allocates charges related to
the DWR bonds issued in connection with the power crisis to customers
of California's three investor-owned utilities (IOUs) based on energy
usage. Edison did not appeal the decision on its application for
14
rehearing to the courts and, therefore, the decision has become final
and unappealable.
In October 2003, the CPUC initiated a proceeding to consider a
permanent methodology for allocating the DWR's revenue requirement
beginning in 2004 through the remaining life of the DWR contracts. An
interim allocation based on the current 2003 methodology was utilized
beginning January 1, 2004, and will remain in effect until a decision
is reached on a permanent methodology. In April 2004, Edison, Pacific
Gas & Electric (PG&E) and a northern California consumer advocacy group
proposed a limited joint settlement to allocate the DWR revenue
requirement among the IOUs. This settlement proposes to shift more than
$1 billion in additional costs to SDG&E customers and would have a
significant impact on commodity rates over the remaining eight-year
life of the DWR contracts. On July 19, 2004, the CPUC issued a proposed
decision and an alternate decision recommending permanent allocations
of DWR contract costs to the IOUs. Neither proposed decision would
adopt the settlement; instead, both would permanently allocate 12.5
percent of the fixed costs of the contracts to SDG&E for the remaining
life of the contracts (2004-2013). This would shift a total of $976
million in additional costs to SDG&E customers over an eight-year
period. Although these proposed decisions would have no effect on
SDG&E's net income, they would adversely affect its customer rates and
SDG&E's cash flows. In the near term the effect on SDG&E's cash flows
would be minor, but would become significant in the later years unless
rate ceilings were increased to provide more-contemporaneous recovery.
The CPUC may consider these draft decisions at its August 19, 2004
meeting.
SDG&E's long-term resource plan identifies the forecasted needs for
capacity resources within its service territory to support transmission
grid reliability. An updated 10-year resource plan was filed on July 9,
2004, in a CPUC proceeding to consider utility resource planning,
including energy efficiency, contracted power, demand response,
qualifying facilities, renewable generation and distributed generation.
SDG&E's updated long-term resource plan incorporates the resources
approved as a result of the May 2003 Request for Proposals (RFP)
discussed below, and recognizes updated goals to reach 20% renewable
resources by 2010. The updated plan recommends a 500-kV transmission
line addition in 2010.
In order to satisfy SDG&E's recognized near-term need for grid
reliability and capacity, in May 2003 SDG&E issued an RFP for the years
2005-2007 for at least 69 megawatts (MWs) of electric capacity in 2005
increasing to 291 MWs in 2007.
As a result of its RFP, in October 2003, SDG&E filed a motion
requesting CPUC authorization to enter into five new electric resource
contracts (including two under which SDG&E would take ownership, on a
turnkey basis, of new generating assets, including a 550-MW plant
(Palomar) being developed by Sempra Energy Resources, an affiliate, for
completion in 2006), as more fully described in the Annual Report. A
June 9, 2004 CPUC decision approved all five proposed contracts, along
with an additional demand response contract. The decision authorized
SDG&E to recover the costs of both contracted resources and turnkey
resources, but did not adopt SDG&E's specific cost recovery, ratemaking
and revenue requirement proposals for the proposed turnkey resources.
15
On July 15, 2004, three parties filed requests for rehearing of the
decision. SDG&E filed its response on July 30, 2004, opposing the
request. The CPUC is expected to rule on the requests in the next few
months. In August 2004, SDG&E will file its revenue requirement and
ratemaking proposals for the 45-MW combustion turbine which SDG&E will
acquire as a turnkey project (Ramco facility) and will file for the
Palomar facility later in 2004. The decision did not approve SDG&E's
proposals for a return on equity (ROE) for SDG&E's new generation
investments higher than SDG&E's ROE on distribution assets, an equity
offset for the debt equivalency of purchase power contracts, and an
equity buildup for construction. These matters may be re-introduced for
consideration in future CPUC proceedings.
NATURAL GAS INDUSTRY RESTRUCTURING (GIR)
As discussed in the Annual Report, in December 2001 the CPUC issued a
decision related to GIR, with implementation anticipated during 2002.
On April 1, 2004, after many delays and changes, the CPUC issued a
decision that adopts tariffs to implement the 2001 decision. However,
by that same decision, the CPUC stayed implementation of the GIR
tariffs until it issues a decision in Phase I of the Natural Gas Market
Order Instituting Ratemaking (OIR) discussed below. At that time, the
CPUC will reconcile the GIR market structure with whatever structure
results from the Phase I decision of the Natural Gas Market OIR.
NATURAL GAS MARKET OIR
The CPUC's Natural Gas Market OIR was approved on January 22, 2004, and
will be addressed in two concurrent phases. The schedule calls for a
Phase I decision by September 2004 and a Phase II decision by the end
of 2004. Further discussion of Phase I and Phase II is included in the
Annual Report. The focus of the Gas OIR is the period from 2006 to
2016. Since GIR (discussed above) would end in August 2006 and there is
overlap between GIR and the OIR issues, a number of parties (including
SoCalGas) have requested the CPUC not to implement GIR.
The California Utilities have made comprehensive filings in the OIR
outlining a proposed market structure that will help create access to
new natural gas supply sources (such as LNG) for California. In the
Phase I filing, SoCalGas and SDG&E proposed a framework to provide firm
tradable access rights for intrastate natural gas transportation;
provide SoCalGas with continued balancing account protection for
intrastate transmission and distribution revenues, thereby eliminating
throughput risk; and integrate the transmission systems of SoCalGas and
SDG&E so as to have common rates and rules. The California Utilities
have proposed that the investments necessary to access new sources of
supply be included in ratebase and that the total amount of the
investments would not exceed $200 million.
In addition, the California Utilities have filed a recommended
methodology and framework to be used by the CPUC for granting pre-
approval of new interstate transportation agreements. A draft Phase I
decision was issued on July 20, 2004. The draft decision recommends
that the utilities' pre-approval procedures be approved with some
modifications and that several issues, including supply access rate
treatment, firm access rights and transmission system integration, be
16
addressed by separate applications. A final CPUC decision in Phase I is
expected in September 2004.
COST OF SERVICE FILINGS
In 2002, the California Utilities filed Cost Of Service applications
with the CPUC, seeking rate increases reflecting forecasts of 2004
capital and operating costs, as further discussed in the Annual Report.
SDG&E is requesting revenue increases of $64 million. On December 19,
2003, settlements were filed with the CPUC for SDG&E that, if approved,
would resolve most of the Cost of Service issues. A CPUC decision is
expected later this year. The SDG&E settlement would reduce its
electric rate revenues by $19.6 million from 2003 rate revenues and
increase its natural gas rate revenues by $1.8 million from 2003 rate
revenues. A CPUC order has provided that the new rates will be
retroactive to January 1, 2004. Beginning in the first quarter of 2004,
SDG&E generally is recognizing revenue consistent with the proposed
settlement, except for amounts related to pension costs, which are
pending the CPUC decision and CPUC acceptance of a related compliance
filing. Resolution of the pension matter consistent with the proposed
settlement would result in the recording of additional income at that
time. To the extent, if any, that the final CPUC decision varies from
the method used to recognize revenue prior to that decision, an
accounting adjustment will be recorded at that time. To date, the
impacts of accounting consistent with the settlement have not had a
material effect on the financial statements.
The remaining issues are included in Phase II of the Cost of Service
proceeding. In addition to recommending changes in the performance-
based regulation (PBR) formulas, the CPUC's Office of Ratepayers
Advocates (ORA) also proposed the possibility of performance penalties,
without the possibility of performance awards. Hearings took place in
June 2004. On July 21, 2004, all of the active parties in Phase II who
dealt with post test year ratemaking and performance incentives filed
for adoption of an all-party settlement agreement for most of the Phase
II issues, including annual inflation adjustments and revenue sharing.
The agreement does not cover performance incentives. The settlement
requires the California Utilities to file their next rate cases based
on a 2008 test year. For the interim years of 2005-2007, the Consumer
Price Index will be used to adjust the escalatable authorized base rate
revenues within identified floors and ceilings. It is anticipated that
the CPUC will address this matter in its decision related to Phase II
of this proceeding expected by year-end 2004.
SDG&E had filed for continuation of existing PBR mechanisms for service
quality and safety that would otherwise expire at the end of 2003. In
January 2004, the CPUC issued a decision that extended 2003 service and
safety targets through 2004, but did not determine the applicability of
rewards or penalties.
Edison has received the CPUC's decision on its Cost of Service
application. This decision sets rates for San Onofre Nuclear Generating
Station (SONGS), 20 percent of which is owned by SDG&E. As discussed in
the Annual Report, SDG&E's SONGS ratebase restarted at $0 on January 1,
2004 and, therefore, SDG&E's earnings from SONGS will generally be
limited to a return on new capital additions. Edison has applied for
permission to replace SONGS' steam generator, which would increase the
17
total cost of SONGS by an estimated $800 million ($160 million for
SDG&E). SDG&E has the option of not participating in the project and
has informed Edison of its intention to exercise this option. This
would reduce SDG&E's ownership percentage in SONGS. The reduction in
SDG&E's ownership percentage is subject to arbitration, which is
expected to occur prior to year-end. If the proposed reduction of
SDG&E's ownership percentage resulting from the arbitration is
unacceptable, SDG&E could elect to participate in the replacement
project.
PERFORMANCE-BASED REGULATION
As further described in the Annual Report, under PBR, the CPUC requires
future income potential to be tied to achieving or exceeding specific
performance and productivity goals, rather than relying solely on
expanding utility plant to increase earnings. PBR and demand-side
management (DSM) rewards are not included in the company's earnings
before CPUC approval is received.
The cumulative amount of rewards subject to refund based on the outcome
of the Border Price Investigation described below is $8.2 million.
At June 30, 2004, the following performance incentives were pending
CPUC approval and, therefore, were not included in the company's
earnings (dollars in millions):
Program
-----------------------------------
DSM/Energy Efficiency* $ 37.7
2003 Distribution PBR 8.2
Natural gas PBR Year 10 1.5
-----------------------------------
Total $ 47.4
-----------------------------------
* Dollar amounts shown do not include interest, franchise fees or
uncollectible amounts.
SOUTHERN CALIFORNIA FIRES
Several major wildfires that began on October 26, 2003 severely damaged
SDG&E's infrastructure, causing a significant number of customers to be
without utility services. On October 27, 2003, then governor Gray Davis
declared a State of Emergency for the State of California. The
declaration authorized the establishment of catastrophic event
memorandum accounts (CEMA) to record all incremental costs (costs not
already included in rates) associated with the repair of facilities and
the restoration of service. Incremental electric distribution and
natural gas related costs are recovered through the CEMA. Electric
transmission related costs are recovered through the annual FERC true-
up proceeding. Total costs incurred related to the wildfires were $66
million, of which $58 million is under CPUC jurisdiction while $8
million is electric transmission subject to FERC jurisdiction. Of that
$58 million, $38 million is incremental and recoverable through the
CEMA.
18
On June 28, 2004, SDG&E filed its CEMA application to recover
incremental operating and maintenance costs and capital costs
associated with the fire. In that application, SDG&E is requesting a
revenue requirement of $20 million effective January 1, 2005, which
includes $16 million in expenses recorded through May 31, 2004 and
estimated to be incurred through the end of 2004, plus an additional $4
million for its capital-related costs, which will continue in future
years until the $22 million of capital costs and the authorized return
thereon are recovered. The company expects no significant effect on
earnings from the fires.
COST OF CAPITAL
Effective January 1, 2003, SDG&E's authorized ROE is 10.9 percent and
its return on ratebase is 8.77 percent, for SDG&E's electric
distribution and natural gas businesses. The electric-transmission
cost of capital is determined under a separate FERC proceeding. As
discussed in the Annual Report, these rates will continue to be
effective until 2008 unless market interest-rate changes are large
enough to trigger an automatic adjustment. The Moody's Aa utility bond
yield as published by Mergent Bond Record must average less than 6.24
percent or greater than 8.24 percent during the April-September
timeframe of any given year to trigger an automatic adjustment. The
Moody's Aa utility bond yield averaged 6.35 percent during the April-
July 2004 time period and was 6.08 percent on July 30, 2004.
BIENNIAL COST ALLOCATION PROCEEDING
The BCAP determines the allocation of authorized costs between
customer classes for natural gas transportation service provided by
the company and adjusts rates to reflect variances in customer demand
as compared to the forecasts previously used in establishing
transportation rates. SDG&E filed with the CPUC its 2005 BCAP
application in September 2003, requesting updated transportation rates
effective January 1, 2005. In November 2003, an Assigned Commissioner
Ruling delayed the BCAP applications until a decision is issued in the
GIR implementation proceeding. As a result of the April 1, 2004
decision on GIR implementation as described in "Natural Gas Industry
Restructuring," above, on May 27, 2004 the Administrative Law Judge
(ALJ) in the 2005 BCAP issued a decision dismissing the BCAP
applications. The California Utilities would be required to file new
BCAP applications after the stay of the GIR implementation decision is
lifted.
BORDER PRICE INVESTIGATION
In November 2002, the CPUC instituted an investigation into the
Southern California natural gas market and the price of natural gas
delivered to the California-Arizona border between March 2000 and May
2001. If the investigation determines that the conduct of any party to
the investigation, including the California Utilities, contributed to
the natural gas price spikes, the CPUC may modify the party's natural
gas procurement incentive mechanism, reduce the amount of any
shareholder award for the period involved, and/or order the party to
issue a refund to ratepayers. Hearings began on June 29, 2004 and
continued through July 15, 2004. A draft decision is expected in
October 2004. The CPUC may hold a second round of hearings to consider
19
whether Sempra Energy or any of its non-utility subsidiaries
contributed to the price spikes. Final decisions are expected by late
2004. The company believes that the CPUC will find that the California
Utilities acted in the best interests of its core customers and that
none of the Sempra Energy companies was responsible for the price
spikes.
CPUC INVESTIGATION OF ENERGY-UTILITY HOLDING COMPANIES
The CPUC has initiated an investigation into the relationship between
California's IOUs and their parent holding companies. The CPUC broadly
determined that it could, in appropriate circumstances, require the
holding company to provide cash to a utility subsidiary to cover its
operating expenses and working capital to the extent they are not
adequately funded through retail rates. This would be in addition to
the requirement of holding companies to cover their utility
subsidiaries' capital requirements, as the IOUs previously acknowledged
in connection with the holding companies' formations. In January 2002,
the CPUC ruled on jurisdictional issues, deciding that the CPUC had
jurisdiction to create the holding company system and, therefore,
retains jurisdiction to enforce conditions to which the holding
companies had agreed.
In an opinion issued May 21, 2004, the California Court of Appeal
upheld the CPUC's assertion of limited enforcement jurisdiction, but
concluded that the CPUC's interpretation of the "first priority"
condition (that the holding companies could be required to infuse cash
into the utilities as necessary to meet the utilities' obligation to
serve) was not ripe for review at this time. On June 30, 2004, the
company requested review of the Court of Appeal's decision on the
jurisdictional issue by the California Supreme Court. To date, the
Supreme Court, which has discretionary authority to grant or deny
review, has not acted upon this request.
RECOVERY OF CERTAIN DISALLOWED TRANSMISSION COSTS
In August 2002, the FERC issued Opinion No. 458, which effectively
disallowed SDG&E's recovery of the differentials between certain
payments to SDG&E by its co-owners of the Southwest Powerlink (SWPL)
under the Participation Agreements and charges assessed to SDG&E under
the California Independent System Operator (ISO) FERC tariff for
transmission line losses and grid management charges related to energy
schedules of Arizona Public Service Co. (APS) and the Imperial
Irrigation District (IID), its SWPL co-owners. As a result, SDG&E is
incurring unreimbursed costs of $4 million to $8 million per year.
After SDG&E petitioned the United States Court of Appeals for review of
this order, the court remanded the case back to the FERC for further
consideration. FERC issued its Order on Remand on May 6, 2004. Although
it corrected several misstatements in its earlier opinions, FERC
essentially reaffirmed its original conclusions. After the Court of
Appeals rejected FERC's argument that SDG&E and other petitioners were
required to file for rehearing of the Order on Remand, the parties
jointly asked the court to set a schedule for completion of briefing.
The Court of Appeals has not yet ruled on this joint motion.
On July 6, 2001, in a separate matter related to ISO charges giving
rise to most of the cost differentials described above, SDG&E filed an
20
arbitration claim against the ISO, claiming the ISO should not charge
SDG&E for the transmission losses attributable to energy schedules on
the APS and the IID portions of the SWPL. The independent arbitrator
found in SDG&E's favor, awarding to SDG&E all amounts claimed, which
totaled $22 million, including interest, as of the time of the award.
The ISO appealed this result to the FERC and a FERC decision is
expected in 2004. SDG&E has also commenced a private arbitration to
reform the Participation Agreements to remove prospectively SDG&E's
obligation to provide the services that result in unreimbursed ISO
tariff charges. On April 6, 2004, the ISO filed its reply brief to
SDG&E's brief and the matter was submitted to the FERC. In addition,
APS, IID and Edison filed briefs in support of SDG&E's arbitration
award.
FERC ACTIONS
Refund Proceedings
The FERC is investigating prices charged to buyers in the California
Power Exchange (PX) and ISO markets by various electric suppliers. The
FERC is seeking to determine the extent to which individual sellers
have yet to be paid for power supplied during the period of October 2,
2000 through June 20, 2001 and to estimate the amounts by which
individual buyers and sellers paid and were paid in excess of
competitive market prices. Based on these estimates, the FERC could
find that individual net buyers, such as SDG&E, are entitled to refunds
and individual net sellers are required to provide refunds. To the
extent any such refunds are actually realized by SDG&E, they would
reduce SDG&E's rate-ceiling balancing account.
In December 2002, a FERC ALJ issued preliminary findings indicating
that the California PX and ISO owe power suppliers $1.2 billion (the
$3.0 billion that the California PX and ISO still owe energy companies
less $1.8 billion that the energy companies charged California
customers in excess of the preliminarily determined competitive market
clearing prices). On March 26, 2003, the FERC adopted its ALJ's
findings, but changed the calculation of the refund by basing it on a
different estimate of natural gas prices. The March 26 order estimates
that the replacement formula for estimating natural gas prices will
increase the refund obligations from $1.8 billion to more than $3
billion.
The FERC recently released additional instructions and ordered the ISO
and PX to recalculate the precise number through their settlement
models. California is seeking $8.9 billion in refunds from its
electricity suppliers and has appealed the FERC's preliminary findings
and requested rehearing of the March 26 order. In March 2004, the
Attorney General of California requested the Ninth Circuit Court of
Appeals to compel the FERC to comply with the Court's earlier orders,
contending that the FERC had violated an August 2002 court order that
should have resulted in larger refunds to California and that the FERC
had failed to properly weigh evidence of market manipulation by power
companies when deciding the refunds due California ratepayers.
21
Manipulation Investigation
The FERC is also investigating whether there was manipulation of short-
term energy markets in the West that would constitute violations of
applicable tariffs and warrant disgorgement of associated profits. In
this proceeding, the FERC's authority is not confined to the October 2,
2000 through June 20, 2001 period relevant to the refund proceeding. In
May 2002, the FERC ordered all energy companies engaged in electric
energy trading activities to state whether they had engaged in various
specific trading activities in violation of the PX and ISO tariffs
(generally described as manipulating or "gaming" the California energy
markets).
On June 25, 2003, the FERC issued several orders requiring various
entities to show cause why they should not be found to have violated
California ISO and PX tariffs. FERC directed 43 entities, including
SDG&E, to show cause why they should not disgorge profits from certain
transactions between January 1, 2000 and June 20, 2001 that are
asserted to have constituted gaming and/or anomalous market behavior
under the California ISO and/or PX tariffs. SDG&E and the FERC resolved
the matter through a settlement which documents the ISO's finding that
SDG&E did not engage in market activities in violation of the ISO or PX
tariffs, and in which SDG&E agreed to pay $27,792 into a FERC-
established fund to conclude the matter.
SDG&E has also worked with the California PX to address questions
raised in connection with certain ancillary service capacity
transactions that the PX carried out on behalf of SDG&E. SDG&E believes
that its data show that all of these transactions were legitimate and
that SDG&E always had capacity available to support its sales in the
ISO's ancillary service capacity markets. The PX has petitioned the
FERC, asking that the PX be dismissed from the show-cause proceeding.
The FERC has not yet acted on the PX's request.
On June 25, 2003, the FERC determined that it was appropriate to
initiate an investigation into possible physical and economic
withholding in the California ISO and PX markets. On August 1, 2003,
the FERC staff issued an initial report that determined there was no
need to further investigate particular entities for physical
withholding of generation. For the purpose of investigating economic
withholding, the FERC used an initial screen of all bids exceeding $250
per megawatt between May 1, 2000 and October 2, 2000. SDG&E received
data requests from the FERC staff and provided responses. In May 2004,
based on the results of its investigation, the FERC's Office of Market
Oversight and Investigation informed SDG&E that its bidding procedures
are no longer being investigated by the FERC.
Settlement of Claims Associated with FERC's Investigations
During June and July, 2004, three settlements of claims associated with
FERC's investigations were announced. One settlement, in which SDG&E
will receive a net payment of $11.5 million, resolves all but a few
claims against The Williams Companies and Williams Power Company for
the period May 1, 2000 through June 20, 2001 and was approved by the
FERC on July 2, 2004. Another settlement, in which SDG&E will receive a
net payment of $13.8 million, resolves all claims against Dynegy, NRG
Energy and West Coast Power LLC for the period January 1, 2000 through
22
June 20, 2001 and has been submitted to the FERC for approval. A third
settlement, in which SDG&E will receive a net payment of $14.7 million,
resolves specified claims against Duke Energy for the period January 1,
2000 though June 20, 2001 and will be submitted to the FERC for
approval in the next few months. In all cases, the majority of the
funds would be received within 20 days of receiving FERC approval with
the remainder contingent on certain actions by the FERC, the ISO and
the PX. Receipt of the remaining amount by SDG&E would take place at
the conclusion of the FERC refund proceeding, now expected to be in
early 2006. These funds would be received for the benefit of SDG&E's
bundled customers and will reimburse SDG&E for the costs of litigating
this matter.
NOTE 6. CONTINGENCIES
NUCLEAR INSURANCE
SDG&E and the other owners of SONGS have insurance to respond to
nuclear liability claims related to SONGS. Detail to the coverage is
provided in the Annual Report. As of June 30, 2004, the secondary
financial protection provided by the Price-Anderson Act is $10.5
billion if the liability loss exceeds the insurance limit of $300
million. In addition, the maximum SDG&E could be assessed is $8.8
million should there be a retrospective premium call under the risk
sharing arrangements of the nuclear property, decontamination and
debris removal insurance policy.
Both the nuclear liability and property insurance programs subscribed
to by members of the nuclear power generating industry include industry
aggregate limits for non-certified acts, as defined by the Terrorism
Risk Insurance Act, of terrorism-related SONGS losses, including
replacement power costs. An industry aggregate limit of $300 million
exists for liability claims, regardless of the number of non-certified
acts affecting SONGS or any other nuclear energy liability policy or
the number of policies in place. An industry aggregate limit of $3.24
billion exists for property claims, including replacement power costs,
for non-certified acts of terrorism affecting SONGS or any other
nuclear energy facility property policy within twelve months from the
date of the first act. These limits are the maximum amount to be paid
to members who sustain losses or damages from these non-certified
terrorist acts. For certified acts of terrorism, the individual policy
limits stated above apply.
SPENT NUCLEAR FUEL
SONGS owners have responsibility for the interim storage of spent
nuclear fuel generated at San Onofre, until it is accepted by the DOE
for final disposal. Spent nuclear fuel is stored in the San Onofre
Units 1, 2 and 3 Spent Fuel Pools (SFP) and the San Onofre Independent
Spent Fuel Storage Installation (ISFSI). Movement of Unit 1 spent fuel
from the Unit 3 SFP to the ISFSI was completed in late 2003. Movement
of Unit 1 spent fuel from the Unit 1 SFP to the ISFSI is scheduled to
be completed by late 2004 and from the Unit 2 SFP to the ISFSI by late
2005. With these moves, there will be sufficient space in the Unit 2
and 3 SFPs to meet plant requirements through mid-2007 and mid-2008,
respectively.
23
LITIGATION
Except for the matters referred to below, neither the company nor its
subsidiary are party to, nor is their property the subject of, any
material pending legal proceedings other than routine litigation
incidental to their businesses. Management believes that none of these
matters will have further material adverse effect on the company's
financial condition or results of operations.
Antitrust Litigation
Class-action and individual lawsuits filed in 2000 and currently
consolidated in San Diego Superior Court seek damages, alleging that
Sempra Energy, SoCalGas and SDG&E, along with El Paso Energy Corp. (El
Paso) and several of its affiliates, unlawfully sought to control
natural gas and electricity markets. In March 2003, plaintiffs in these
cases and the applicable El Paso entities (whose cases involved
unrelated claims not applicable to Sempra Energy, SoCalGas or SDG&E)
announced that they had reached a $1.7 billion settlement, of which
$125 million is allocated to customers of the California Utilities. The
Court approved that settlement in December 2003. The proceeding
against Sempra Energy and the California Utilities has not been settled
and continues to be litigated. On July 22, 2004, the court heard oral
argument on a motion for summary judgment brought by Sempra Energy and
the California Utilities and is expected to issue a decision in August
2004. Trial is set for September 7, 2004.
Natural Gas Cases: Lawsuits have been filed by the Attorneys General
of Arizona and Nevada, alleging that El Paso and certain Sempra Energy
subsidiaries unlawfully sought to control the natural gas market in
their respective states. In October 2003, the Nevada state court denied
defendants' motion to dismiss the complaint. On April 12, 2004, the
Sempra Energy defendants filed a motion for reconsideration. In April
2003, Sierra Pacific Resources and its utility subsidiary Nevada Power
filed a lawsuit in U.S. District Court in Las Vegas against major
natural gas suppliers, including Sempra Energy, the California
Utilities and other company subsidiaries, seeking damages resulting
from an alleged conspiracy to drive up or control natural gas prices,
eliminate competition and increase market volatility, breach of
contract and wire fraud. On January 27, 2004, the U.S. District Court
dismissed the Sierra Pacific Resources case against all of the
defendants, determining that this is a matter for the FERC to resolve.
The court granted plaintiffs' request to amend their complaint, which
they did. On July 15, 2004, Sempra Energy filed another motion to
dismiss, which is scheduled to be heard on September 23, 2004.
Electricity Cases: Various lawsuits, which seek class-action
certification, allege that Sempra Energy and certain subsidiaries,
including SDG&E, unlawfully manipulated the electric-energy market. In
January 2003, the federal court granted a motion to dismiss a similar
lawsuit on the grounds that the claims contained in the complaint were
subject to the Filed Rate Doctrine and were preempted by the Federal
Power Act. That ruling was appealed to the Ninth Circuit Court of
Appeals and oral argument was heard on June 14, 2004. In May and June
2004, two new cases were filed in federal court against Sempra Energy
and certain subsidiaries, including SDG&E.
24
SDG&E and two other subsidiaries of Sempra Energy, along with all other
sellers in the western power market, have been named defendants in a
complaint filed at the FERC by the California Attorney General's office
seeking refunds for electricity purchases based on alleged violations
of FERC tariffs. The FERC has dismissed the complaint. The California
Attorney General filed an appeal in the Ninth Circuit of Appeals and
oral argument was heard in October 2003. No decision has yet been
rendered.
Price Reporting Practices
On July 8, 2004, the City and County of San Francisco and the County of
Santa Clara and on July 18, 2004 the County of San Diego brought
actions, alleging that energy prices were unlawfully manipulated by
defendants' reporting artificially inflated natural gas prices to trade
publications and by entering into wash trades, in San Diego Superior
Court against Sempra Energy, SET, SoCalGas and SDG&E.
Other
The Utility Consumers' Action Network (UCAN), a consumer-advocacy group
which had requested a CPUC rehearing of a CPUC decision concerning the
allocation of certain power contract gains between SDG&E customers and
the company, appealed the CPUC's rehearing denial to the California
Court of Appeal. On July 12, 2004, the Court of Appeal affirmed the
CPUC's decision. UCAN has 40 days to appeal.
Customers of the California Utilities will receive benefits under
a settlement with El Paso resolving a number of civil and
administrative proceedings surrounding the high natural gas and
electric prices experienced in several Western states during the March
2000 through May 2001 period. A total amount of settlement funds of
$33.3 million to SDG&E's core gas customers and $66.6 million to
SDG&E's electric customers will be received over a period of 20 years.
An initial lump sum payment of $30 million was received in June 2004,
which will be followed by 19 annual payments.
25
ITEM 2.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with the
financial statements contained in this Form 10-Q and "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" contained in the Annual Report.
RESULTS OF OPERATIONS
Electric revenues increased to $810 million for the six months ended
June 30, 2004 from $799 million for the same period in 2003, and the
cost of electric fuel and purchased power decreased to $282 million in
2004 from $300 million in 2003. The increase in revenues was the
result of higher volumes and higher operating costs that are recovered
in rates via balancing accounts, offset by more power being provided by
the DWR as discussed in Note 5 of the notes to Consolidated Financial
Statements, while the decrease in the cost of electric fuel and
purchased power was mainly due to more power being provided by the DWR.
Additionally, electric revenues increased to $425 million for the
quarter ended June 30, 2004 from $402 million for the same period in
2003, and the cost of electric fuel and purchased power increased to
$155 million in 2004 from $137 million in 2003. These changes were
mainly due to higher volumes. Under the current regulatory framework,
changes in commodity costs normally do not affect net income.
Natural gas revenues increased to $306 million for the six months ended
June 30, 2004 from $283 million for the corresponding period in 2003,
and the cost of natural gas increased to $172 million in 2004 from $152
million in 2003. These increases were primarily attributable to natural
gas cost increases, which are passed on to customers. Additionally,
natural gas revenues were relatively unchanged at $111 million for the
quarter ended June 30, 2004 compared to $118 million for the
corresponding period in 2003, and the cost of natural gas was
relatively unchanged at $63 million in 2004 compared to $67 million in
2003.
Under the current regulatory framework, the cost of natural gas
purchased for customers and the variations in that cost are passed
through to the customers on a substantially concurrent basis. However,
SDG&E's natural gas procurement PBR mechanism provides an incentive
mechanism by measuring SDG&E's procurement of natural gas against a
benchmark price comprised of monthly natural gas indices, resulting in
shareholder rewards for costs achieved below the benchmark and
shareholder penalties when costs exceed the benchmark.
In 2002, the California Utilities filed Cost Of Service applications
with the CPUC, seeking rate increases reflecting forecasts of 2004
capital and operating costs, as further discussed in the Annual Report.
In accordance with generally accepted accounting principles, SDG&E is
generally recognizing 2004 revenue consistent with the proposed
settlement, except for amounts related to pension costs which are
pending the CPUC decision and CPUC acceptance of a related compliance
26
filing. Resolution of the pension matter consistent with the proposed
settlement would result in the recording of additional income at that
time. To the extent, if any, that the final CPUC decision varies from
the method used to recognize revenue prior to that decision, an
accounting adjustment will be recorded at that time. To date, the
impacts of accounting consistent with the settlement have not had a
material effect on the financial statements.
The tables below summarize the electric and natural gas volumes and
revenues by customer class for the six months ended June 30, 2004 and
2003.
<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 3,396 $ 338 3,161 $ 366
Commercial 3,142 302 2,922 333
Industrial 980 64 907 81
Direct access 1,658 49 1,565 37
Street and highway lighting 47 6 45 5
Off-system sales -- -- 33 1
-----------------------------------------
9,223 759 8,633 823
Balancing accounts and other 51 (24)
-----------------------------------------
Total $ 810 $ 799
-----------------------------------------
</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.
Beginning in 2004, off-system sales are accounted for as a reduction of
the cost of purchased power.
27
<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 20 $ 188 -- $ -- 20 $ 188
Commercial and industrial 9 75 2 2 11 77
Electric generation plants -- - 35 17 35 17
-------------------------------------------------------------
29 $ 263 37 $ 19 66 282
Balancing accounts and other 24
--------
Total $ 306
- -----------------------------------------------------------------------------------------
2003:
Residential 19 $ 173 -- $ -- 19 $ 173
Commercial and industrial 9 69 2 3 11 72
Electric generation plants -- 1 28 12 28 13
-------------------------------------------------------------
28 $ 243 30 $ 15 58 258
Balancing accounts and other 25
--------
Total $ 283
- -----------------------------------------------------------------------------------------
</table>
Other operating expenses increased to $291 million for the six months
ended June 30, 2004 from $268 million for the same period in 2003 and
increased to $151 million for the quarter ended June 30, 2004 from $142
million for the same period in 2003 due to nuclear refueling costs at
SONGS and increases in other operating expenses.
SDG&E recorded net income of $82 million and $89 million for the six-
month periods ended June 30, 2004 and 2003, respectively, and net
income of $31 million and $42 million for the quarters ended June 30,
2004 and 2003, respectively. The decreases were primarily due to the
absence of the 2003 Incremental Cost Incentive Pricing for SONGS and
performance-based regulation gains and higher operating costs, offset
by higher revenues.
CAPITAL RESOURCES AND LIQUIDITY
The company's operations are the major source of liquidity. At June 30,
2004, the company had $294 million in cash and $242 million in available
unused, committed lines of credit. Total available unused, committed
lines of credit increased to $300 million at July 31, 2004. See "Cash
Flows from Financing Activities" for discussion on changes in the credit
facility in 2004.
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 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
28
expenditures and working capital requirements in comparison to cash from
operations, available credit lines and other sources available to meet
liquidity requirements.
CASH FLOWS FROM OPERATING ACTIVITIES
Net cash provided by operating activities totaled $159 million and $217
million for the six months ended June 30, 2004 and 2003, respectively.
The decrease was mainly due to a lower increase in overcollected
regulatory balancing accounts in 2004 and a decrease in accounts payable
in 2004 compared to an increase in 2003.
For the six months ended June 30, 2004, the company contributed $2
million to other postretirement benefit plans but made no contribution
to the pension plan.
CASH FLOWS FROM INVESTING ACTIVITIES
Net cash used in investing activities totaled $62 million and $148
million for the six months ended June 30, 2004 and 2003, respectively.
The change was primarily due to the $122 million repayment of an
intercompany loan by Sempra Energy in 2004.
Significant capital expenditures in 2004 are expected to be for
additions to the company's natural gas and electric distribution
systems. These expenditures are expected to be financed by cash flows
from operations and security issuances.
In connection with the importation of additional sources of natural gas
into Southern California, for which the California Utilities have made
filings with the CPUC, the California Utilities could install capital
facilities estimated at up to $200 million over three years, starting
in 2005, in order to connect with new delivery locations. The
expenditures would be included in utility ratebases or would be
reimbursed by LNG project developers dependent on CPUC review of the
projects and on the outcome of the Gas Market Order Instituting
Investigation Phase II proceeding.
CASH FLOWS FROM FINANCING ACTIVITIES
Net cash provided by (used in) financing activities totaled $49 million
and $(136) million for the six months ended June 30, 2004 and 2003,
respectively. The change was due to $251 million of long-term debt
issuances in 2004, partially offset by higher dividends paid to Sempra
Energy in 2004.
In June 2004, SDG&E issued $251 million of first mortgage bonds and
applied the proceeds in July to refund an identical amount of first
mortgage bonds and related tax-exempt industrial development bonds of a
shorter maturity. The bonds, which mature in 2034 ($176 million) and in
2039 ($75 million), bear interest at rates that are periodically reset
through auction procedures. They secure the repayment of tax-exempt
industrial development bonds of an identical amount, maturity and
interest rate issued by City of Chula Vista, the proceeds of which were
loaned to SDG&E and repaid with payments on the first mortgage bonds.
29
In May 2004, the California Utilities obtained a combined $500 million
three-year syndicated revolving credit facility to replace their
expiring 364-day facility of a like amount. Under the facility, each
utility may borrow up to $300 million, subject to a combined borrowing
limit of $500 million. Borrowings would bear interest at rates varying
with market rates and the borrowing utility's credit rating. The
agreement requires each utility to maintain, at the end of each
quarter, a ratio of total indebtedness to total capitalization (as
defined in the agreement) of no more than 60 percent. Borrowings under
the agreement would be individual obligations of the borrowing utility
and a default by one utility would not constitute a default or preclude
borrowings by the other.
FACTORS INFLUENCING FUTURE PERFORMANCE
Performance of the company will depend primarily on the ratemaking and
regulatory process, electric and natural gas industry restructuring,
and the changing energy marketplace. These factors are discussed in the
Annual Report and in Note 5 of the notes to Consolidated Financial
Statements herein.
NEW ACCOUNTING STANDARDS
Relevant pronouncements that have recently become effective and have
had a significant effect on the company are SFAS Nos. 143, 149 and 150,
and FIN 46, as discussed in Note 2 of the notes to Consolidated
Financial Statements. Pronouncements that have or are likely to have a
material effect on future earnings are described below.
SFAS 143, "Accounting for Asset Retirement Obligations": Beginning in
2003, SFAS 143 requires entities to record liabilities for future costs
expected to be incurred when assets are retired from service, if the
retirement process is legally required. It also requires the company to
reclassify amounts recovered in rates for future removal costs not
covered by a legal obligation from accumulated depreciation to a
regulatory liability. Further discussion is provided in Note 2 of the
notes to Consolidated Financial Statements.
SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities": SFAS 149 amends and clarifies accounting for
derivative instruments, including certain derivative instruments
embedded in other contracts, and for hedging activities under SFAS 133.
Under SFAS 149, natural gas forward contracts that are subject to
unplanned netting do not qualify for the normal purchases and normal
sales exception, whereby derivatives are not required to be marked to
market when the contract is usually settled by the physical delivery of
natural gas. The company has determined that all natural gas contracts
are subject to unplanned netting and as such, these contracts will be
marked to market. In addition, effective January 1, 2004, power
contracts that are subject to unplanned netting and that do not meet
the normal purchases and normal sales exception under SFAS 149 will be
further marked to market. Implementation of SFAS 149 on July 1, 2003
did not have a material impact on reported net income.
30
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
There have been no significant changes in the risk issues affecting the
company subsequent to those discussed in the Annual Report.
As of June 30, 2004, the total Value at Risk of SDG&E's positions was
not material.
ITEM 4. CONTROLS AND PROCEDURES
The company has designed and maintains disclosure controls and
procedures to ensure that information required to be disclosed in the
company's reports under the Securities Exchange Act of 1934 is
recorded, processed, summarized and reported within the time periods
specified in the rules and forms of the Securities and Exchange
Commission and is accumulated and communicated to the company's
management, including its Chief Executive Officer and Chief Financial
Officer, as appropriate, to allow timely decisions regarding required
disclosure. In designing and evaluating these controls and procedures,
management recognizes that any system of controls and procedures, no
matter how well designed and operated, can provide only reasonable
assurance of achieving the desired objectives and necessarily applies
judgment in evaluating the cost-benefit relationship of other possible
controls and procedures.
Under the supervision and with the participation of management,
including the Chief Executive Officer and the Chief Financial Officer,
the company evaluated the effectiveness of the design and operation of
the company's disclosure controls and procedures as of June 30, 2004,
the end of the period covered by this report. Based on that evaluation,
the company's Chief Executive Officer and Chief Financial Officer
concluded that the company's disclosure controls and procedures were
effective at the reasonable assurance level.
There has been no change in the internal controls over financial
reporting during the company's most recent fiscal quarter that has
materially affected, or is reasonably likely to materially affect, the
company's internal controls over financial reporting.
ITEM 5. OTHER INFORMATION
Effective May 1, 2004, Debra L. Reed, President of SoCalGas and SDG&E,
also became their Chief Operating Officer. Simultaneously, Steven D.
Davis, who remains Senior Vice President, External Relations, succeeded
her as Chief Financial Officer.
31
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
SDG&E and the County of San Diego are in the process of negotiating the
remaining terms of a settlement relating to alleged environmental law
violations by SDG&E and its contractors in connection with the
abatement of asbestos-containing materials during the demolition of a
natural gas storage facility that was completed in 2001. The expected
settlement would involve payments by SDG&E of less than $750,000.
Except as described above and in Notes 5 and 6 of the notes to
Consolidated Financial Statements, neither the company nor its
subsidiary is party to, nor is their property the subject of, any
material pending legal proceedings other than routine litigation
incidental to their businesses.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
Exhibit 12 -- Computation of ratios
12.1 Computation of Ratio of Earnings to Combined Fixed
Charges and Preferred Stock Dividends.
Exhibit 31 -- Section 302 Certifications
31.1 Statement of Registrant's Chief Executive Officer pursuant
to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
31.2 Statement of Registrant's Chief Financial Officer pursuant
to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
Exhibit 32 -- Section 906 Certifications
32.1 Statement of Registrant's Chief Executive Officer pursuant
to 18 U.S.C. Sec. 1350.
32.2 Statement of Registrant's Chief Financial Officer pursuant
to 18 U.S.C. Sec. 1350.
(b) Reports on Form 8-K
The following reports on Form 8-K were filed after March 31, 2004:
Current Report on Form 8-K filed April 29, 2004, filing as an exhibit
Sempra Energy's press release of April 29, 2004, giving the financial
results for the quarter ended March 31, 2004.
Current Report on Form 8-K filed August 5, 2004, filing as an exhibit
Sempra Energy's press release of August 5, 2004, giving the financial
results for the quarter ended June 30, 2004.
32
SIGNATURE
Pursuant to the requirement of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
SAN DIEGO GAS & ELECTRIC COMPANY
-------------------------------
(Registrant)
Date: August 5, 2004 By: /s/ S. D. Davis
------------------------------
S. D. Davis
Sr. Vice President-External Relations
and Chief Financial Officer