SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act
of 1934
Date of Report
(Date of earliest event reported): May 5, 1999
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SEMPRA ENERGY
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(Exact name of registrant as specified in its charter)
CALIFORNIA 1-14201 33-0732627
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(State of incorporation (Commission (I.R.S. Employer
or organization) File Number) Identification No.
101 ASH STREET, SAN DIEGO, CALIFORNIA 92101
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(Address of principal executive offices) (Zip Code)
(619) 696-2034
Registrant's telephone number, including area code-------------------
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(Former name or former address, if changed since last report.)
FORM 8-K
Item 5. Other Events
Sempra Energy Holdings (Holdings) will be filing a shelf
registration of debt securities to be offered on a delayed or
continuous basis pursuant to Rule 415 under the Securities Act
of 1933. Because the debt securities will be guaranteed by
Sempra Energy, of which Holdings is a wholly owned subsidiary,
summarized financial information of Holdings is provided
herein. Consolidated financial information for Sempra Energy,
as previously filed in its 1998 Form 10-K is also presented
herein, because it is referred to in the accompanying
independent auditors' report which also refers to the
summarized financial information of Holdings.
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareholders of Sempra Energy:
We have audited the accompanying consolidated balance sheets of
Sempra Energy and subsidiaries (the "company") as of December 31,
1998 and 1997, and the related statements of consolidated income,
changes in shareholders' equity, and cash flows for each of the
three years in the period ended December 31, 1998. These financial
statements are the responsibility of the company's management. Our
responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements. An audit also
includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of Sempra
Energy and subsidiaries as of December 31, 1998, and 1997, and the
results of their operations and their cash flows for each of the
three years in the period ended December 31, 1998, in conformity
with generally accepted accounting principles.
/s/ Deloitte & Touche LLP
San Diego, California
January 27, 1999, except for Note 16 as to which the date is
February 22, 1999
SEMPRA ENERGY
Statements of Consolidated Income
Years Ended December 31,
-------------------------------
(Dollars in millions, except per share amounts) 1998 1997 1996
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Revenues and Other Income
Utility revenues:
Natural gas $ 2,772 $ 2,964 $ 2,710
Electric 1,865 1,769 1,591
PX/ISO power 500 -- --
Other operating revenues 344 336 195
Other income 44 58 28
-------- -------- --------
Total 5,525 5,127 4,524
-------- -------- --------
Expenses
Cost of natural gas distributed 954 1,168 958
PX/ISO power 468 -- --
Purchased power 292 441 311
Electric fuel 177 164 134
Operating expenses 1,872 1,615 1,405
Depreciation and amortization 929 604 587
Franchise payments and other taxes 182 178 180
Preferred dividends of subsidiaries 12 18 22
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Total 4,886 4,188 3,597
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Income Before Interest and Income Taxes 639 939 927
Interest 207 206 200
-------- -------- --------
Income Before Income Taxes 432 733 727
Income taxes 138 301 300
-------- -------- --------
Net Income $ 294 $ 432 $ 427
======== ======== ========
Net Income Per Share of Common Stock (Basic) $ 1.24 $ 1.83 $ 1.77
======== ======== ========
Net Income Per Share of Common Stock (Diluted) $ 1.24 $ 1.82 $ 1.77
======== ======== ========
Common Dividends Declared Per Share $ 1.56 $ 1.27 $ 1.24
======== ======== ========
See notes to Consolidated Financial Statements.
SEMPRA ENERGY
Consolidated Balance Sheets
December 31,
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(Dollars in millions) 1998 1997
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Assets
Current assets:
Cash and cash equivalents $ 424 $ 814
Accounts receivable - trade 586 633
Accounts and notes receivable - other 159 202
Deferred income taxes 93 15
Energy trading assets 906 587
Inventories 151 111
Regulatory balancing accounts - net -- 297
Other 139 102
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Total current assets 2,458 2,761
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Investments and other assets:
Regulatory assets 980 1,186
Nuclear-decommissioning trusts 494 399
Investments 548 429
Other assets 535 439
------- -------
Total investments and other assets 2,557 2,453
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Property, plant and equipment:
Property, plant and equipment 11,235 10,902
Less accumulated depreciation
and amortization (5,794) (5,360)
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Total property, plant and
equipment - net 5,441 5,542
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Total assets $ 10,456 $ 10,756
======= =======
See notes to Consolidated Financial Statements.
SEMPRA ENERGY
Consolidated Balance Sheets
December 31,
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(Dollars in millions) 1998 1997
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Liabilities
Current liabilities:
Short-term debt $ 43 $ 354
Accounts payable - trade 702 625
Accrued income taxes 27 5
Energy trading liabilities 805 557
Dividends and interest payable 168 121
Regulatory balancing accounts - net 120 --
Long-term debt due within one year 330 270
Other 271 279
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Total current liabilities 2,466 2,211
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Long-term debt:
Long-term debt 2,795 3,045
Debt of Employee Stock Ownership Plan -- 130
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Total long-term debt 2,795 3,175
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Deferred credits and other liabilities:
Customer advances for construction 72 72
Post-retirement benefits other than pensions 240 248
Deferred income taxes 634 741
Deferred investment tax credits 147 155
Deferred credits and other liabilities 985 916
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Total deferred credits and
other liabilities 2,078 2,132
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Preferred stock of subsidiaries 204 279
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Commitments and contingent liabilities (Note 13)
Shareholders' Equity
Common stock 1,883 1,849
Retained earnings 1,075 1,157
Less deferred compensation relating to
Employee Stock Ownership Plan (45) (47)
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Total shareholders' equity 2,913 2,959
------- -------
Total liabilities and shareholders'
equity $ 10,456 $ 10,756
======= =======
See notes to Consolidated Financial Statements.
SEMPRA ENERGY
Statements of Consolidated Cash Flows
Years Ended December 31
---------------------------------
(Dollars in millions) 1998 1997 1996
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CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 294 $ 432 $ 427
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 929 604 587
Deferred income taxes and investment tax credits (199) (16) 26
Other - net (180) 62 56
Net changes in other working capital components 479 (164) 68
---------- --------- ---------
Net cash provided by operating activities 1,323 918 1,164
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CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment (438) (397) (413)
Acquisitions of subsidiaries (191) (206) (50)
Contributions to decommissioning trusts (22) (22) (22)
Other (28) 23 (29)
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Net cash used in investing activities (679) (602) (514)
--------- ----------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Common stock dividends (325) (301) (300)
Sale of common stock 34 17 8
Repurchase of common stock (1) (122) (24)
Redemption of preferred stock (75) -- (225)
Issuances of other long-term debt 75 140 304
Issuance of rate-reduction bonds -- 658 --
Payment on long-term debt (431) (416) (459)
Increase (decrease) in short-term debt - net (311) 92 29
--------- ----------- ----------
Net cash provided by (used in) financing activities (1,034) 68 (667)
--------- ----------- ----------
Increase (Decrease) in Cash and Cash Equivalents (390) 384 (17)
Cash and Cash Equivalents, January 1 814 430 447
--------- ----------- ----------
Cash and Cash Equivalents, December 31 $ 424 $ 814 $ 430
========= =========== ==========
See notes to Consolidated Financial Statements.
SEMPRA ENERGY
Statements of Consolidated Cash Flows
Years Ended December 31
---------------------------------
(Dollars in millions) 1998 1997 1996
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CHANGES IN OTHER WORKING CAPITAL COMPONENTS
(Excluding cash and cash equivalents, short-term
debt and long-term debt due within one year)
Accounts and notes receivable $ 90 $ (129) $ (58)
Net trading assets (71) -- --
Inventories (40) (2) 32
Regulatory balancing accounts 417 48 9
Other current assets (26) 41 40
Accounts payable and other current liabilities 109 (122) 45
-------- -------- --------
Net change in other working
capital components $ 479 $ (164) $ 68
======== ======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid during the year for:
Interest (net of amounts capitalized) $ 211 $ 193 $ 205
Income taxes (net of refunds) $ 366 $ 274 $ 268
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES
Acquisition of Sempra Energy Trading:
Assets acquired $ -- $ 609 $ --
Cash paid -- (225) --
---------- ----------- ---------
Liabilities assumed $ -- $ 384 $ --
========== =========== =========
Liabilities assumed for real estate investments $ 36 $ 126 $ 97
========== =========== =========
Nonutility electric generation assets sold:
Book value of assets sold $ -- $ 77 $ --
Cash received -- (20) --
Loss on sale -- (6) --
---------- ----------- ---------
Note receivable obtained $ -- $ 51 $ --
========== =========== =========
See notes to Consolidated Financial Statements.
SEMPRA ENERGY
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
For the years ended December 31, 1998, 1997, 1996
(Dollars in millions)
Deferred
Compensation Total
Common Retained Relating Shareholders'
Stock Earnings to ESOP Equity
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Balance at December 31, 1995 $ 1,968 $ 899 $ (52) $ 2,815
Net income 427 427
Common stock dividends declared (300) (300)
Sale of common stock 8 8
Repurchase of common stock (24) (24)
Common stock released
from ESOP 3 3
Long-term incentive plan 1 1
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Balance at December 31, 1996 1,953 1,026 (49) 2,930
Net income 432 432
Common stock dividends declared (301) (301)
Sale of common stock 17 17
Repurchase of common stock (122) (122)
Common stock released
from ESOP 2 2
Long-term incentive plan 1 1
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Balance at December 31, 1997 1,849 1,157 (47) 2,959
Net income 294 294
Common stock dividends declared (376) (376)
Sale of common stock 34 34
Repurchase of common stock (1) (1)
Common stock released
from ESOP 2 2
Long-term incentive plan 1 1
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Balance at December 31, 1998 $ 1,883 $1,075 $ (45) $ 2,913
====================================================================================
See notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1 BUSINESS COMBINATION
On June 26, 1998, Enova Corporation (Enova) and Pacific Enterprises
(PE) combined into a new company named Sempra Energy (the company).
As a result of the combination, (i) each outstanding share of
common stock of Enova was converted into one share of common stock
of Sempra Energy, (ii) each outstanding share of common stock of PE
was converted into 1.5038 shares of common stock of Sempra Energy
and (iii) the preferred stock and preference stock of Enova's
principal subsidiary, San Diego Gas & Electric Company (SDG&E); PE;
and PE's principal subsidiary, Southern California Gas Company
(SoCalGas) remained outstanding. The combination was approved by
the shareholders of both companies on March 11, 1997, and was a
tax-free transaction.
As required by the March 1998 decision of the California
Public Utilities Commission (CPUC) approving the business
combination, SDG&E has entered into agreements to sell its fossil-
fueled generation units. The sales are subject to regulatory
approvals and are expected to close during the first half of 1999.
Additional information concerning the sale of SDG&E's power plants
is provided in Note 14. In addition, SoCalGas has sold its options
to purchase the California portions of the Kern River and Mojave
Pipeline natural gas-transmission facilities. The Federal Energy
Regulatory Commission's (FERC) approval of the combination includes
conditions that the combined company will not unfairly use any
potential market power regarding natural gas transportation to
fossil-fueled electric-generation plants. The FERC also
specifically noted that the divestiture of SDG&E's fossil-fueled
generation plants would eliminate any concerns about vertical
market power arising from transactions between SDG&E and SoCalGas.
The Consolidated Financial Statements are those of the company
and its subsidiaries and give effect to the business combination
using the pooling-of-interests method and, therefore, are presented
as if the companies were combined during all periods included
therein. The per-share data shown on the Statements Of Consolidated
Income reflect the conversion of Enova common stock and of PE
common stock into Sempra Energy common stock as described above.
All significant intercompany transactions, including SoCalGas'
sales of natural gas transportation and storage to SDG&E, have been
eliminated. These sales amounted to approximately $60 million in
each of the years presented.
The results of operations for PE and Enova as reported as
separate companies through June 30, 1998, are as follows:
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Six months
ended June 30,
(Dollars in millions) 1998 1997 1996
- ---------------------------------------------------------------
PACIFIC ENTERPRISES
Revenue and Other Income $1,263 $2,777 $2,588
Net Income $ 50 $ 180 $ 196
ENOVA
Revenue and Other Income $1,299 $2,224 $1,996
Net Income $ 68 $ 252 $ 231
- ---------------------------------------------------------------
2 SIGNIFICANT ACCOUNTING POLICIES
Property, Plant and Equipment
This primarily represents the buildings, equipment and other
facilities used by SDG&E and SoCalGas to provide natural gas and
electric utility service. The cost of utility plant includes labor,
materials, contract services and related items, and an allowance
for funds used during construction. The cost of retired depreciable
utility plant, plus removal costs minus salvage value, is charged
to accumulated depreciation. Information regarding electric-
industry restructuring and its effect on utility plant is included
in Note 14. Utility plant balances by major functional categories
at December 31, 1998, are: natural gas operations $7.0 billion,
electric distribution $2.4 billion, electric transmission $0.7
billion, electric generation $0.6 billion and other electric $0.3
billion. The corresponding amounts at December 31, 1997, were
essentially the same. Accumulated depreciation and decommissioning
of natural gas and electric utility plant in service at December
31, 1998, are $3.5 billion and $2.2 billion, respectively, and at
December 31, 1997, were $3.3 billion and $2.0 billion,
respectively. Depreciation expense is based on the straight-line
method over the useful lives of the assets or a shorter period
prescribed by the CPUC. The provisions for depreciation as a
percentage of average depreciable utility plant (by major
functional categories) in 1998, 1997, and 1996, respectively are:
natural gas operations 4.32, 4.31, 4.35, electric generation 6.49,
5.60, 5.60, electric distribution 4.49, 4.39, 4.38, electric
transmission 3.31, 3.28, 3.25, and other electric 6.29, 6.02, 5.95.
The increase for electric generation in 1998 reflects the
accelerated recovery of generation facilities. See Note 14 for
additional discussion of generation facilities and industry
restructuring.
Inventories
Included in inventories at December 31, 1998, are $61 million of
utility materials and supplies ($56 million in 1997), and $78
million of natural gas and fuel oil ($47 million in 1997).
Materials and supplies are generally valued at the lower of average
cost or market; fuel oil and natural gas are valued by the last-in
first-out method.
Trading Instruments
Trading assets and trading liabilities are recorded on a trade-date
basis at fair value and include option premiums paid and received,
and unrealized gains and losses from exchange-traded futures and
options, over the counter (OTC) swaps, forwards, and options.
Unrealized gains and losses on OTC transactions reflect amounts
which would be received from or paid to a third party upon
settlement of the contracts. Unrealized gains and losses on OTC
transactions are reported separately as assets and liabilities
unless a legal right of setoff exists under a master netting
arrangement enforceable by law. Revenues are recognized on a trade-
date basis and include realized gains and losses, and the net
change in unrealized gains and losses.
Futures and exchange-traded option transactions are recorded
as contractual commitments on a trade-date basis and are carried at
fair value based on closing exchange quotations. Commodity swaps
and forward transactions are accounted for as contractual
commitments on a trade-date basis and are carried at fair value
derived from dealer quotations and underlying commodity-exchange
quotations. OTC options are carried at fair value based on the use
of valuation models that utilize, among other things, current
interest, commodity and volatility rates, as applicable. For long-
dated forward transactions, where there are no dealer or exchange
quotations, fair values are derived using internally developed
valuation methodologies based on available market information.
Where market rates are not quoted, current interest, commodity and
volatility rates are estimated by reference to current market
levels. Given the nature, size and timing of transactions,
estimated values may differ from realized values. Changes in the
fair value are recorded currently in income.
Effects of Regulation
SDG&E and SoCalGas accounting policies conform with generally
accepted accounting principles for regulated enterprises and
reflect the policies of the CPUC and the FERC. The company's
interstate natural gas transmission subsidiary follows accounting
policies authorized by the FERC.
SDG&E and SoCalGas have been preparing their financial
statements in accordance with the provisions of Statement of
Financial Accounting Standards (SFAS) No. 71, "Accounting for the
Effects of Certain Types of Regulation," under which a regulated
utility may record a regulatory asset if it is probable that,
through the ratemaking process, the utility will recover that asset
from customers. Regulatory liabilities represent future reductions
in rates for amounts due to customers. To the extent that portions
of the utility operations were no longer subject to SFAS No. 71, or
recovery was no longer probable as a result of changes in
regulation or their competitive position, the related regulatory
assets and liabilities would be written off. In addition, SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of," affects utility plant and
regulatory assets such that a loss must be recognized whenever a
regulator excludes all or part of an asset's cost from rate base.
As discussed in Note 14, California enacted a law restructuring the
electric-utility industry. The law adopts the December 1995 CPUC
policy decision, and allows California electric utilities the
opportunity to recover existing utility plant and regulatory assets
over a transition period that ends in 2001. In 1997, SDG&E ceased
the application of SFAS No. 71 with respect to its electric-
generation business. The application of SFAS No. 121 continues to
be evaluated as industry restructuring progresses. Additional
information concerning regulatory assets and liabilities is
described below in "Revenues and Regulatory Balancing Accounts" and
in Note 14.
Revenues and Regulatory Balancing Accounts
Revenues from utility customers consist of deliveries to customers
and the changes in regulatory balancing accounts. The amounts
included in regulatory balancing accounts at December 31, 1998,
represent a $129 million net payable for SoCalGas combined with a
$9 million net receivable for SDG&E. The corresponding amounts at
December 31, 1997 were $355 million net receivable and $58 million
net payable for SoCalGas and SDG&E, respectively.
Previously, earnings fluctuations from changes in the costs of
fuel oil, purchased energy and natural gas, and consumption levels
for electricity and the majority of natural gas were eliminated by
balancing accounts authorized by the CPUC. This is still the case
for most natural gas operations. However, as a result of
California's electric-restructuring law, overcollections recorded
in SDG&E's Energy Cost Adjustment Clause and Electric Revenue
Adjustment Mechanism balancing accounts were transferred to the
Interim Transition Cost Balancing Account, which is being applied
to transition cost recovery, and fluctuations in costs and
consumption levels can affect earnings from electric operations.
Additional information on electric-industry restructuring is
included in Note 14.
Regulatory Assets
Regulatory assets include San Onofre Nuclear Generating Station
(SONGS), unrecovered premium on early retirement of debt, post-
retirement benefit costs, deferred income taxes recoverable in
rates and other regulatory-related expenditures that the utilities
expect to recover in future rates. See Note 14 for additional
information.
Nuclear-Decommissioning Liability
Deferred credits and other liabilities at December 31, 1998,
include $146 million ($117 million in 1997) of accumulated
decommissioning costs associated with SDG&E's SONGS Unit 1, which
was permanently shut down in 1992. Additional information on SONGS
Unit 1 decommissioning costs is included in Note 6. The
corresponding liability for Units 2 and 3 is included in
accumulated depreciation and amortization.
Comprehensive Income
In 1998, the company adopted SFAS No. 130, "Reporting Comprehensive
Income." This statement requires reporting of comprehensive income
and its components (revenues, expenses, gains and losses) in any
complete presentation of general-purpose financial statements.
Comprehensive income describes all changes, except those resulting
from investments by owners and distributions to owners, in the
equity of a business enterprise from transactions and other events
including, as applicable, foreign-currency items, minimum pension
liability adjustments and unrealized gains and losses on certain
investments in debt and equity securities. Comprehensive income was
equal to net income for the years ended December 31, 1998, 1997,
and 1996.
Quasi-Reorganization
In 1993, PE completed a strategic plan to refocus on its natural
gas utility and related businesses. The strategy included the
divestiture of its merchandising operations and all of its oil and
gas exploration and production business. In connection with the
divestitures, PE effected a quasi-reorganization for financial
reporting purposes, effective December 31, 1992. Certain of the
liabilities established in connection with discontinued operations
and the quasi-reorganization will be resolved in future years.
Management believes the provisions previously established for these
matters are adequate at December 31, 1998.
Use of Estimates in the Preparation of the Financial Statements
The preparation of the consolidated financial statements in
conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the
reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during
the reporting period. Actual results could differ from those
estimates.
Statements of Consolidated Cash Flows
Cash equivalents are highly liquid investments with original
maturities of three months or less, or investments that are readily
convertible to cash.
Basis of Presentation
Certain prior-year amounts have been reclassified from the
predecessor companies' classifications to conform to the format of
these financial statements.
New Accounting Standard
In June 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards (SFAS) No. 133
"Accounting for Derivative Instruments and Hedging Activities."
This statement, which is effective January 1, 2000, requires that
an entity recognize all derivatives as either assets or liabilities
in the statement of financial position, measure those instruments
at fair value and recognize changes in the fair value of
derivatives in earnings in the period of change unless the
derivative qualifies as an effective hedge that offsets certain
exposures. The effect of this standard on the company's
Consolidated Financial Statements has not yet been determined.
3 ACQUISITIONS AND JOINT VENTURES
Sempra Energy Trading
In December 1997, PE and Enova jointly acquired Sempra Energy
Trading (SET) for $225 million. SET is a wholesale-energy trading
company based in Stamford, Connecticut. It participates in
marketing and trading physical and financial energy products,
including natural gas, power, crude oil and associated commodities.
In July 1998, SET purchased CNG Energy Services Corporation, a
subsidiary of Pittsburgh-based Consolidated Natural Gas Company,
for $36 million. The acquisition expands SET's business volume by
adding large, commodity-trading contracts with local distribution
companies, municipalities and major industrial corporations in the
eastern United States.
Sempra Energy Resources
In December 1997, Sempra Energy Resources (SER) in partnership with
Reliant Energy Power Generation, formed El Dorado Energy. In April
1998, El Dorado Energy began construction on a 480-megawatt power
plant near Boulder City, Nevada. SER invested $2.3 million in 1997
and $19.7 million in 1998 on this $263-million project. In October
1998, El Dorado Energy obtained a $158-million senior secured
credit facility, which entails both construction and 15-year term
financing for the project. This financing represents approximately
60 percent of estimated total project costs.
Sempra Energy Utility Ventures
In September 1997, Sempra Energy Utility Ventures (SEUV) formed a
joint venture with Bangor Hydro to build, own and operate a $40-
million natural gas distribution system in Bangor, Maine.
Construction began in June 1998. The new Bangor Gas Company expects
to begin deliveries in the fourth quarter of 1999.
In December 1997, SEUV formed Frontier Energy with Frontier
Utilities of North Carolina to build and operate a $55-million
natural gas distribution system in North Carolina. Natural gas
delivery began in December 1998. Subsequent to December 31, 1998,
SEUV purchased Frontier Utilities' interest and acquired 100
percent ownership of the system.
Sempra Energy Solutions
In January 1998, Sempra Energy Solutions completed the acquisition
of CES/Way International, a national leader in energy-service
performance contracting headquartered in Houston, Texas. CES/Way
provides energy-efficiency services, including energy audits,
engineering design, project management, construction, financing and
contract maintenance.
In May 1997, Sempra Energy Solutions entered into a joint
venture agreement with Conectiv Thermal Systems, Inc. (formerly
Atlantic Thermal System, Inc.) to form Atlantic-Pacific Las Vegas,
with each receiving a 50-percent interest. Atlantic-Pacific Las
Vegas provides integrated energy-management services to commercial
and industrial customers, including the construction of facilities.
In May 1997, Atlantic-Pacific Las Vegas entered into an energy-
services agreement with three other parties to finance, own,
operate and maintain an integrated thermal-energy production
facility at the site of the future Venetian Casino Resort in Las
Vegas. Construction costs incurred to date are $48 million.
A second joint venture agreement was entered into with
Conectiv Thermal Systems to form Atlantic-Pacific Glendale in
August 1997, with each receiving a 50-percent interest. Atlantic-
Pacific Glendale entered into an integrated energy-management
services agreement with Dreamworks Animation, LLC to develop,
manage and finance the construction and operation of a central
chiller plant, emergency power generators and chilled-water
distribution and circulation system at Dreamworks' Glendale
facilities. The cost of the project, completed in May 1998, was $7
million.
International Natural Gas Projects
Sempra Energy International (SEI) is a wholly owned subsidiary of
Sempra Energy. Sempra Energy International and Proxima Gas S.A. de
C.V., partners in the Mexican companies Distribuidora de Gas
Natural (DGN) de Mexicali and Distribuidora de Gas Natural de
Chihuahua, are the licensees to build and operate natural gas
distribution systems in Mexicali and Chihuahua. DGN-Mexicali will
invest up to $25 million during the first five years of the 30-year
license period. DGN-Chihuahua will invest up to $50 million over
the first five years of operation. DGN-Mexicali and DGN-Chihuahua
assumed ownership of natural gas distribution facilities during the
third quarter of 1997. SEI owns interests of 60 and 95 percent in
the DGN-Mexicali and DGN-Chihuahua projects, respectively. In
August 1998, SEI was awarded a 10-year agreement by the Mexican
Federal Electric Commission to provide a complete energy-supply
package for a power plant in Rosarito, Baja California. The
contract includes provisions for delivery of up to 300 million
cubic feet per day of natural gas, transportation services in the
U.S. and construction of a 23-mile pipeline from the U.S.-Mexico
border to the plant. The pipeline is expected to cost approximately
$35 million and take a year to build. Delivery of natural gas is
expected to commence in December 1999.
SEI also has interests in Argentina and Uruguay. In March
1998, SEI increased its existing investment in two Argentine
natural gas utility holding companies (Sodigas Pampeana S.A. and
Sodigas Sur S.A.) from 12.5 percent to 21.5 percent by purchasing
an additional interest for $40 million.
4 SHORT-TERM BORROWINGS
PE has a $300 million multi-year credit agreement. SoCalGas has an
additional $400 million multi-year credit agreement. These
agreements expire in 2001 and bear interest at various rates based
on market rates and the companies' credit ratings. SoCalGas' lines
of credit are available to support commercial paper. At December
31, 1998, PE had $43 million of bank loans under the credit
agreement outstanding, due and paid in January 1999. SoCalGas' bank
line of credit was unused. At December 31, 1997, both bank lines of
credit were unused.
SDG&E has $30 million of bank lines available to support
commercial paper and $265 million of bank lines available to
support variable-rate, long-term debt. The credit agreements expire
at varying dates from 1999 through 2000 and bear interest at
various rates based on market rates and the company's credit
rating. SDG&E's bank lines of credit were unused at both December
31, 1998, and 1997.
At December 31, 1998, there were no commercial-paper
obligations outstanding. At December 31, 1997, SoCalGas had $354
million of commercial-paper obligations outstanding, of which
approximately $94 million related to the restructuring costs
associated with certain long-term gas-supply contracts under the
Comprehensive Settlement. See Note 14 for additional information.
5 LONG-TERM DEBT
- --------------------------------------------------------------
December 31,
(Dollars in millions) 1998 1997
- --------------------------------------------------------------
Long-Term Debt
First mortgage bonds
5.25% March 1, 1998 $ - $ 100
7.625% June 15, 2002 28 80
6.875% August 15, 2002 100 100
5.75% November 15, 2003 100 100
6.8% June 1, 2015 14 14
5.9% June 1, 2018 71 71
5.9% September 1, 2018 93 93
6.1% and 6.4% September 1, 2018
and 2019 118 118
9.625% April 15, 2020 10 54
Variable rates September 1, 2020 58 75
5.85% June 1, 2021 60 60
8.75% October 1, 2021 150 150
8.5% April 1, 2022 10 44
7.375% March 1, 2023 100 100
7.5% June 15, 2023 125 125
6.875% November 1, 2025 175 175
Various rates December 1, 2027 250 250
----------------------
Total 1,462 1,709
Rate-reduction bonds 592 658
Debt incurred to acquire limited
partnerships, secured by real estate,
at 6.8% to 9.0%, payable annually
through 2008 305 313
Various unsecured bonds at 4.15%
to 10% from 1998 to 2006 453 296
Various unsecured bonds at 5.9%
or at variable rates (4.3% to 5.0% at
December 31, 1998) from 2014 to 2023 254 254
Capitalized leases 76 106
----------------------
Total 3,142 3,336
----------------------
Less:
Current portion of long-term debt 330 270
Unamortized discount on long-term debt 17 21
----------------------
347 291
----------------------
Total $ 2,795 $ 3,045
- --------------------------------------------------------------
Excluding capital leases, which are described in Note 13,
maturities of long-term debt, including PE's Employees Stock
Ownership Plan, are $271 million in 1999, $96 million in 2000, $186
million in 2001, $193 million in 2002 and $241 million in 2003.
SDG&E and SoCalGas have CPUC authorization to issue an additional
$752 million in long-term debt. Although holders of variable-rate
bonds may elect to redeem them prior to scheduled maturity, for
purposes of determining the maturities listed above, it is assumed
the bonds will be held to maturity.
First-Mortgage Bonds
First-mortgage bonds are secured by a lien on substantially all
utility plant. In addition, certain non-utility subsidiary assets
are pledged as collateral for SoCalGas' first-mortgage bonds. SDG&E
and SoCalGas may issue additional first-mortgage bonds upon
compliance with the provisions of their bond indentures, which
provide for, among other things, the issuance of additional first-
mortgage bonds ($1.5 billion as of December 31, 1998).
During 1998, the company retired $247 million of first-
mortgage bonds, of which $147 million was retired prior to
scheduled maturity.
Certain first-mortgage bonds may be called at SDG&E's or
SoCalGas' option. SoCalGas has no variable-rate bonds. SDG&E has
$188 million of bonds with variable interest-rate provisions that
are callable at various dates within one year. Of the company's
remaining callable bonds, $10 million are callable in the year
2000, $150 million in 2001, $203 million in 2002, and $624 million
in 2003. $242 million of the bonds are not callable.
Rate-Reduction Bonds
In December 1997, $658 million of rate-reduction bonds were issued
on behalf of SDG&E at an average interest rate of 6.26 percent.
These bonds were issued to facilitate the 10-percent rate reduction
mandated by California's electric-restructuring law. See Note 14
for additional information. These bonds are being repaid over 10
years by SDG&E's residential and small commercial customers via a
charge on their electricity bills. These bonds are secured by the
revenue streams collected from customers and are not secured by, or
payable from, utility assets.
Unsecured Debt
Various long-term obligations totaling $707 million are unsecured.
During 1998, SoCalGas issued $75 million of unsecured debt in
medium-term notes used to finance working capital requirements.
Unsecured bonds totaling $124 million have variable-interest-rate
provisions.
Debt of Employee Stock Ownership Plan (ESOP) and Trust
The Trust covers substantially all of the company's former PE
employees and is used to fund part of their retirement savings
program. It has an ESOP feature and holds approximately 3.1 million
shares of the company's common stock. The variable-rate ESOP debt
held by the Trust bears interest at a rate necessary to place or
remarket the notes at par. The balance of this debt was $130
million at December 31, 1998, and is included in the table above as
part of the various unsecured bonds at 4.15 percent to 10 percent.
Principal is due on November 30, 1999, and interest is payable
monthly. The company is obligated to make contributions to the
Trust sufficient to satisfy debt service requirements. As the
company makes contributions to the Trust, these contributions, plus
any dividends paid on the unallocated shares of the company's
common stock held by the Trust, will be used to repay the debt. As
dividends are increased or decreased, required contributions are
reduced or increased, respectively. Interest on ESOP debt amounted
to $6 million each in 1998, 1997 and 1996. Dividends used for debt
service amounted to $3 million each in 1998, 1997, and 1996, and
are deductible only for federal income tax purposes.
Currency Interest-Rate Swaps
SDG&E periodically enters into interest-rate swap and cap
agreements to moderate its exposure to interest-rate changes and to
lower its overall cost of borrowings. At December 31, 1998, SDG&E
had such an agreement, maturing in 2002, with underlying debt of
$45 million.
6 FACILITIES UNDER JOINT OWNERSHIP
SONGS and the Southwest Powerlink transmission line are owned
jointly with other utilities. The company's interests at December
31, 1998, are:
- -----------------------------------------------------------
(Dollars in millions) Southwest
Project SONGS Powerlink
- -----------------------------------------------------------
Percentage ownership 20 89
Regulatory assets $ 312 -
Utility plant in service - $ 217
Accumulated depreciation
and amortization - $ 104
Construction work in progress $ 18 $ 1
- -----------------------------------------------------------
The company's share of operating expenses is included in the
Statements of Consolidated Income. Each participant in the project
must provide its own financing. The amounts specified above for
SONGS include nuclear production, transmission and other
facilities. $11 million of substation equipment included in these
amounts is wholly owned by the company.
SONGS Decommissioning
Objectives, work scope and procedures for the future dismantling
and decontamination of the SONGS units must meet the requirements
of the Nuclear Regulatory Commission, the Environmental Protection
Agency, the California Public Utilities Commission and other
regulatory bodies.
The company's share of decommissioning costs for the SONGS
units is estimated to be $425 million in today's dollars and is
based on a cost study completed in 1998. Cost studies are performed
and updated periodically by outside consultants. Although electric-
industry restructuring legislation requires that stranded costs,
which include SONGS' costs, be amortized in rates by 2001, the
recovery of decommissioning costs is allowed until the time that
the costs are fully recovered.
The amount accrued each year is based on the amount allowed by
regulators and is currently being collected in rates. This amount
is considered sufficient to cover the company's share of future
decommissioning costs. Payments to the nuclear-decommissioning
trusts are expected to continue until SONGS is decommissioned,
which is not expected to occur before 2013. Unit 1, although
permanently shut down in 1992, was scheduled to be decommissioned
concurrently with Units 2 and 3. However, the company and the other
owners of SONGS have requested that the CPUC grant authority to
begin decommissioning Unit 1 on January 1, 2000.
The amounts collected in rates are invested in externally
managed trust funds. The securities held by the trust are
considered available for sale and shown on the Consolidated Balance
Sheets adjusted to market value. The fair values reflect unrealized
gains of $149 million and $89 million at December 31, 1998, and
1997, respectively.
The Financial Accounting Standards Board is reviewing the
accounting for liabilities related to closure and removal of long-
lived assets, such as nuclear power plants, including the
recognition, measurement and classification of such costs. The
Board could require, among other things, that the company's future
balance sheets include a liability for the estimated
decommissioning costs, and a related increase in the cost of the
asset.
Additional information regarding SONGS is included in Notes 13
and 14.
7 INCOME TAXES
The reconciliation of the statutory federal income tax rate to the
effective income tax rate is as follows:
- --------------------------------------------------------------
1998 1997 1996
- --------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Depreciation 6.3 7.1 6.2
State income taxes-net of
federal income tax benefit 7.4 6.7 6.2
Tax credits (12.9) (5.7) (4.8)
Equipment leasing activities (1.5) (1.1) (1.4)
Capitalized expenses not deferred 0.2 (1.4) (2.1)
Other-net (2.6) 0.5 2.2
---------------------------
Effective income tax rate 31.9% 41.1% 41.3%
- --------------------------------------------------------------
The components of income tax expense are as follows:
- --------------------------------------------------------------
(Dollars in millions) 1998 1997 1996
- --------------------------------------------------------------
Current:
Federal $278 $236 $183
State 89 63 65
---------------------------
Total current taxes 367 299 248
---------------------------
Deferred:
Federal (165) 1 52
State (58) 7 6
---------------------------
Total deferred taxes (223) 8 58
---------------------------
Deferred investment tax credits-net (6) (6) (6)
---------------------------
Total income tax expense $138 $301 $300
- --------------------------------------------------------------
Accumulated deferred income taxes at December 31 result from the
following:
- --------------------------------------------------------------
(Dollars in millions) 1998 1997
- --------------------------------------------------------------
Deferred Tax Liabilities:
Differences in financial and
tax bases of utility plant $924 $1,063
Regulatory balancing accounts 23 133
Regulatory assets 76 120
Partnership income 27 21
Other 71 53
------------------
Total deferred tax liabilities 1,121 1,390
------------------
Deferred Tax Assets:
Unamortized investment tax credits 88 89
Comprehensive Settlement (see Note 14) 95 117
Postretirement benefits 76 90
Other deferred liabilities 102 110
Restructuring costs 42 54
Other 177 204
------------------
Total deferred tax assets 580 664
------------------
Net deferred income tax liability 541 726
Current portion (net asset) 93 15
------------------
Non-current portion (net liability) $634 $741
- --------------------------------------------------------------
8 EMPLOYEE BENEFIT PLANS
The information presented below describes the plans of the company
and its principal subsidiaries. In connection with the PE/Enova
Business Combination described in Note 1, certain of these plans
have been or will be replaced or modified, and numerous
participants have been or will be transferred from the
subsidiaries' plans to those of Sempra Energy.
Pension and Other Postretirement Benefits
The company sponsors several qualified and nonqualified pension
plans and other postretirement benefit plans for its employees. The
following tables provide a reconciliation of the changes in the
plans' benefit obligations and fair value of assets over the two
years, and a statement of the funded status as of each year end:
- -------------------------------------------------------------------------------------
Other
Pension Benefits Postretirement Benefits
----------------------------------------------
(Dollars in millions) 1998 1997 1998 1997
- -------------------------------------------------------------------------------------
Weighted-Average Assumptions
as of December 31:
Discount rate 6.75% 7.07% 6.75% 7.02%
Expected return on plan assets 8.50% 8.13% 8.50% 7.87%
Rate of compensation increase 5.00% 5.00% 5.00% 5.00%
Cost trend of covered
health-care charges - - 8.00%(1) 7.00%(2)
Change in Benefit Obligation:
Net benefit obligation at January 1 $2,117 $1,981 $ 531 $ 442
Service cost 55 53 13 15
Interest cost 148 144 36 35
Plan participants' contributions - - 1 1
Plan amendments 18 - - -
Actuarial (gain) loss (44) 54 - 57
Special termination benefits 63 13 3 2
Gross benefits paid (277) (128) (21) (21)
----------------------------------------------
Net benefit obligation at December 31 2,080 2,117 563 531
----------------------------------------------
Change in Plan Assets:
Fair value of plan assets at January 1 2,653 2,373 363 286
Actual return on plan assets 407 406 64 59
Employer contributions 13 2 36 38
Plan participants' contributions - - 1 1
Gross benefits paid (277) (128) (21) (21)
----------------------------------------------
Fair value of plan assets at December 31 2,796 2,653 443 363
----------------------------------------------
Funded status at December 31 716 536 (120) (168)
Unrecognized net actuarial gain (926) (733) (107) (66)
Unrecognized prior service cost 73 61 (13) (14)
Unrecognized net transition obligation 3 4 - -
----------------------------------------------
Net liability at December 31 (3) $ (134) $ (132) $(240) $(248)
- -------------------------------------------------------------------------------------
(1) Decreasing to ultimate trend of 6.50% in 2004.
(2) Decreasing to ultimate trend of 6.50% in 1998.
(3) Approximates amounts recognized in the Consolidated Balance Sheets at December
31.
The following table provides the components of net periodic
benefit cost for the plans:
- -------------------------------------------------------------------------------------
Other
Pension Benefits Postretirement Benefits
-----------------------------------------------------
(Dollars in millions) 1998 1997 1996 1998 1997 1996
- -------------------------------------------------------------------------------------
Service cost $55 $53 $58 $13 $15 $18
Interest cost 148 144 141 36 35 36
Expected return on assets (196) (178) (161) (24) (22) (19)
Amortization of:
Transition obligation 1 1 1 2 2 2
Prior service cost 6 5 5 (1) (1) (1)
Actuarial (gain) loss (23) (18) (4) - 1 1
Special termination benefit 63 13 - 3 2 -
Settlement credit (30) - - - - -
Regulatory adjustment - - (12) 9 12 12
-----------------------------------------------------
Total net periodic benefit cost $24 $20 $28 $38 $44 $49
- -------------------------------------------------------------------------------------
Assumed health care cost trend rates have a significant effect on
the amounts reported for the health care plans. A 1% change in assumed
health care cost trend rates would have the following effects:
- ------------------------------------------------------------------
(Dollars in millions) 1% Increase 1% Decrease
- ------------------------------------------------------------------
Effect on total of service
and interest cost components of
net periodic postretirement
health care benefit cost $11 $(10)
Effect on the health care component
of the accumulated postretirement
benefit obligation $72 $(65)
- ------------------------------------------------------------------
The projected benefit obligation and accumulated benefit obligation
were $55 million and $45 million, respectively, as of December 31, 1998,
and $53 million and $44 million, as of December 31, 1997. There were no
pension plans with accumulated benefit obligations in excess of plan
assets for 1998 or 1997.
Other postretirement benefits include medical benefits for retirees
and their spouses (and Medicare Part B reimbursement for certain
retirees) and retiree life insurance.
Savings Plans
Sempra Energy and its subsidiaries offer savings plans, administered by
plan trustees, to all eligible employees. Eligibility to participate in
the various employer plans ranges from one month to one year of completed
service. Employees may contribute, subject to plan provisions, from 1
percent to 15 percent of their regular earnings. Employer contributions,
after one year of completed service, are made in shares of company common
stock. Employer contribution methods vary by plan, but generally the
contribution is equal to 50 percent of the first 6 percent of eligible
base salary contributed by employees. During 1998, the SDG&E plan
contribution was age-based for represented employees. The employee's
contributions, at the direction of the employees, are primarily invested
in company stock, mutual funds or guaranteed investment contracts.
Employer contributions for the Sempra and SoCalGas plans are partially
funded by the Pacific Enterprises Employee Stock Ownership Plan and
Trust. Annual expense for the savings plans was $14 million in 1998, $11
million in 1997 and $10 million in 1996.
Employee Stock Ownership Plan
The Pacific Enterprises Employee Stock Ownership Plan and Trust (Trust)
covers substantially all employees of PE and SoCalGas and is used to
partially fund their retirement savings plan programs. All contributions
to the Trust are made by the company, and there are no contributions made
by the participants. As the company makes contributions to the ESOP, the
ESOP debt service is paid and shares are released in proportion to the
total expected debt service.
Compensation expense is charged and equity is credited for the
market value of the shares released. Income-tax deductions are allowed
based on the cost of the shares. Dividends on unallocated shares are used
to pay debt service and are charged against liabilities. The Trust held
3.1 million and 3.3 million shares of company common stock, with fair
values of $77.9 million and $80.3 million, at December 31, 1998, and
1997, respectively.
9 STOCK-BASED COMPENSATION
Sempra Energy has stock-based compensation plans that align employee and
shareholder objectives related to the long-term growth of the company.
The company's long-term incentive stock compensation plan provides for
aggregate awards of Sempra Energy non-qualified stock options, incentive
stock options, restricted stock, stock appreciation rights, performance
awards, stock payments or dividend equivalents.
In 1995, Statement of Financial Accounting Standards (SFAS) No. 123,
"Accounting for Stock-Based compensation," was issued. It encourages a
fair-value-based method of accounting for stock-based compensation. As
permitted by SFAS No. 123, the company adopted its disclosure-only
requirements and continues to account for stock-based compensation in
accordance with the provisions of accounting Principles Board Opinion No.
25, "Accounting for Stock Issued to Employees."
In 1998, 102,640 shares of Sempra Energy common stock were awarded
to officers. Under the predecessor plan, in each of the last 10 years,
Enova awarded between 49,000 and 75,000 shares to key executives. These
awards are subject to forfeiture over four years if certain corporate
goals are not met. Holders of this stock have voting rights and receive
dividends prior to the time the restrictions lapse if, and to the extent,
dividends are paid on Sempra Energy common stock. Compensation expense
for the issuance of these restricted shares was approximately $2 million
in 1998, $1 million in 1997 and $1 million in 1996.
In 1998, Sempra Energy granted 3,425,800 stock options. The option
price is equal to the market price of common stock at the date of grant.
The grants, which vest over a four-year period, include options with and
without performance-based features. The stock options expire in ten years
from the date of grant. All options granted prior to 1997 became
immediately exercisable upon approval by PE's shareholders of the
business combination with Enova. The options were originally scheduled to
vest annually over a service period ranging from three to five years.
Sempra Energy's plans allow for the granting of dividend equivalents
based upon performance goals. This feature provides grantees, upon
exercise of the option, with the opportunity to receive all or a portion
of the cash dividends that would have been paid on the shares if the
shares had been outstanding since the grant date. Dividend equivalents
are payable only if corporate goals are met and, for grants prior to July
1, 1998, if the exercise price exceeds the market value of the shares
purchased. The percentage of dividends paid as dividend equivalents will
depend upon the extent to which the performance goals are met.
The following information is presented after conversion of PE stock
into company stock as described in Note 1.
Stock option activity is summarized in the following tables.
- -----------------------------------------------------------------
Options With Performance Features
- -----------------------------------------------------------------
Shares Average Options
Under Exercise Exercisable
Option Price at Year End
- -----------------------------------------------------------------
December 31, 1995 846,188 $16.23 -
Granted 1,030,404 17.95
--------------------------------------------
December 31, 1996 1,876,592 17.17 282,063
Granted 1,040,103 20.37
Exercised (359,288) 16.53
Cancelled (71,190) 20.37
--------------------------------------------
December 31, 1997 2,486,217 18.51 1,513,545
Granted 2,131,803 25.23
Exercised (512,059) 17.12
Cancelled (509,301) 23.00
--------------------------------------------
December 31, 1998 3,596,660 $22.06 1,387,523
- -----------------------------------------------------------------
- -----------------------------------------------------------------
Options Without Performance Features
- -----------------------------------------------------------------
Shares Average Options
Under Exercise Exercisable
Option Price at Year End
- -----------------------------------------------------------------
December 31, 1995 2,302,018 $18.14 1,200,183
Exercised (304,520) 15.00
Cancelled (125,417) 26.05
--------------------------------------------
December 31, 1996 1,872,081 18.12 1,197,687
Exercised (493,848) 14.94
Cancelled (14,737) 35.24
--------------------------------------------
December 31, 1997 1,363,496 19.08 1,363,496
Granted 1,293,997 26.33
Exercised (596,629) 15.72
Cancelled (240,632) 29.78
--------------------------------------------
December 31, 1998 1,820,232 $23.92 523,661
- -----------------------------------------------------------------
Additional information on options outstanding at December 31, 1998, is as
follows:
- -----------------------------------------------------------------
Outstanding Options
- -----------------------------------------------------------------
Range of Number Average Average
Exercise of Remaining Exercise
Prices Shares Life Price
- -----------------------------------------------------------------
$12.80-$16.12 623,362 5.55 $15.29
$16.79-$20.36 1,584,272 7.47 $19.03
$24.10-$31.00 3,209,258 9.05 $25.82
----------
5,416,892 8.19 $22.64
- -----------------------------------------------------------------
Exercisable Options
- -----------------------------------------------------------------
Range of Number Average
Exercise of Exercise
Prices Shares Price
- -----------------------------------------------------------------
$12.80-$16.12 623,362 $15.29
$16.79-$20.36 1,109,878 $18.46
$24.11-$31.00 177,944 $26.70
----------
1,911,184 $18.20
- -----------------------------------------------------------------
The fair value of each option grant (including the dividend
equivalent) was estimated on the date of grant using the modified Black-
Scholes option-pricing model. Weighted average fair values for options
granted in 1998, 1997, and 1996 were $8.20, $5.23 and $5.00,
respectively.
The assumptions that were used to determine these fair values are as
follows:
- -----------------------------------------------------------------
Year Ended December 31
1998 1997 1996
- -----------------------------------------------------------------
Stock price volatility 16% 18% 19%
Risk-free rate of return 5.6% 6.4% 6.1%
Annual dividend yield 0% 0% 0%
Expected life 6 Years 3.8 Years 4.3 Years
- -----------------------------------------------------------------
Compensation expense for the stock option grants was $11.7 million,
$16.9 million and $5.5 million in 1998, 1997 and 1996, respectively. The
differences between compensation cost included in net income and the
related cost measured by the fair-value-based method defined in SFAS No.
123 are immaterial.
10 FINANCIAL INSTRUMENTS
Fair Value
The fair values of the company's financial instruments (cash, temporary
investments, funds held in trust, notes receivable, investments in
limited partnerships, dividends payable, short- and long-term debt,
customer deposits, and preferred stock of subsidiaries) are not
materially different from the carrying amounts, except for long-term debt
and preferred stock of subsidiaries. The carrying amounts and fair values
of long-term debt are $3.1 billion and $3.2 billion, respectively, at
December 31, 1998, and $3.4 billion and $3.5 billion at December 31,
1997. The carrying amounts and fair values of subsidiaries' preferred
stock are $204 million and $182 million, respectively, at December 31,
1998, and $279 million and $258 million, respectively, at December 31,
1997. The fair values of the first-mortgage and other bonds and preferred
stock are estimated based on quoted market prices for them or for similar
issues. The fair values of long-term notes payable are based on the
present value of the future cash flows, discounted at rates available for
similar notes with comparable maturities. Included in long-term debt are
SDG&E's rate-reduction bonds. The carrying amounts and fair values of the
bonds are $592 million and $607 million, respectively, at December 31,
1998.
Off-Balance-Sheet Financial Instruments
The company's policy is to use derivative financial instruments to manage
its exposure to fluctuations in interest rates, foreign-currency exchange
rates and energy prices. Transactions involving these financial
instruments expose the company to market and credit risks which may at
times be concentrated with certain counterparties, although counterparty
nonperformance is not anticipated. Additional information on this topic
is discussed in Note 2.
Swap Agreements
The company periodically enters into interest-rate-swap and cap
agreements to moderate exposure to interest-rate changes and to lower the
overall cost of borrowing. These agreements generally remain off the
balance sheet as they involve the exchange of fixed- and variable-rate
interest payments without the exchange of the underlying principal
amounts. The related gains or losses are reflected in the consolidated
income statement as part of interest expense.
At December 31, 1998, and 1997, SDG&E had one interest-rate-swap
agreement: a floating-to-fixed-rate swap associated with $45 million of
variable-rate bonds maturing in 2002. SDG&E expects to hold this
financial instrument to its maturity. This swap agreement has effectively
fixed the interest rate on the underlying variable-rate debt at 5.4
percent. SDG&E would be exposed to interest-rate fluctuations on the
underlying debt should the counterparty to the agreement not perform.
Such nonperformance is not anticipated. This agreement, if terminated,
would result in an obligation of $3 million at December 31, 1998, and $2
million at December 31, 1997. Additional information on this topic is
included in Note 5.
Energy Derivatives
Information on derivative financial instruments of SET is provided below.
The company's regulated operations use energy derivatives for both price-
risk management and trading purposes within certain limitations imposed
by company policies and regulatory requirements. Energy derivatives are
used to mitigate risk and better manage costs. These instruments include
forward contracts, swaps, options and other contracts which have
maturities ranging from 30 days to 12 months.
SoCalGas is subject to price risk on its natural gas purchases if
its cost exceeds a 2-percent tolerance band above the benchmark price.
This is discussed further in Note 14. SoCalGas becomes subject to price
risk when positions are incurred during the buying, selling and storage
of natural gas. As a result of the Gas Cost Incentive Mechanism (GCIM),
SoCalGas enters into a certain amount of gas futures contracts in the
open market with the intent of reducing gas costs within the GCIM
tolerance band. The CPUC has approved the use of gas futures for managing
risk associated with the GCIM. For the years ended December 31, 1998,
1997, and 1996, gains and losses from natural gas futures contracts are
not material to SoCalGas' financial statements.
Sempra Energy Trading
SET derives a substantial portion of its revenue from market making and
trading activities, as a principal, in natural gas, petroleum and
electricity. It quotes bid and offer prices to end users and other market
makers. It also earns trading profits as a dealer by structuring and
executing transactions that permit its counterparties to manage their
risk profiles. In addition, it takes positions in energy markets based on
the expectation of future market conditions. These positions may be
offset with similar positions or may be offset in the exchange-traded
markets. These positions include options, forwards, futures and swaps.
These financial instruments represent contracts with counterparties
whereby payments are linked to or derived from energy-market indices or
on terms predetermined by the contract, which may or may not be
physically or financially settled by SET. For the year ended December 31,
1998, substantially all of SET's derivative transactions were held for
trading and marketing purposes.
Market risk arises from the potential for changes in the value of
financial instruments resulting from fluctuations in natural gas,
petroleum and electricity commodity-exchange prices and basis. Market
risk is also affected by changes in volatility and liquidity in markets
in which these instruments are traded.
SET adjusts the book value of these derivatives to market each month
with gains and losses recognized in earnings. These instruments are
included in other current assets on the Consolidated Balance Sheet.
Certain instruments such as swaps are entered into and closed out within
the same month and, therefore, do not have any balance-sheet impact.
Gains and losses are included in electric or natural gas revenue or
expense, whichever is appropriate, in the Consolidated Income Statements.
SET also carries an inventory of financial instruments. As trading
strategies depend on both market making and proprietary positions, given
the relationships between instruments and markets, those activities are
managed in concert in order to maximize trading profits.
SET's credit risk from financial instruments as of December 31,
1998, is represented by the positive fair value of financial instruments
after consideration of master netting agreements and collateral. Credit
risk disclosures, however, relate to the net accounting losses that would
be recognized if all counterparties completely failed to perform their
obligations. Options written do not expose SET to credit risk. Exchange-
traded futures and options are not deemed to have significant credit
exposure as the exchanges guarantee that every contract will be properly
settled on a daily basis.
The following table approximates the counterparty credit quality and
exposure of SET expressed in terms of net replacement value (in millions
of dollars):
- -----------------------------------------------------------------
Futures,
forward and
swap Purchased
Counterparty credit quality: contracts options Total
- -----------------------------------------------------------------
AAA $32 $1 $33
AA 41 14 55
A 129 19 148
BBB 290 26 316
Below investment grade 69 2 71
Exchanges 30 8 38
- -----------------------------------------------------------------
$591 $70 $661
- -----------------------------------------------------------------
Financial instruments with maturities or repricing characteristics
of 180 days or less, including cash and cash equivalents, are considered
to be short-term and, therefore, the carrying values of these financial
instruments approximate their fair values. SET's commodities owned,
trading assets and trading liabilities are carried at fair value. The
average fair values during the year, based on quarterly observation, for
trading assets and trading liabilities which are considered financial
instruments with off-balance-sheet risk approximate $952 million and $890
million, respectively. The fair values are net of the amounts offset
pursuant to rights of setoff based on qualifying master netting
arrangements with counterparties, and do not include the effects of
collateral held or pledged.
As of December 31, 1998, and 1997, SET's trading assets and trading
liabilities approximate the following:
- -----------------------------------------------------------------
December 31,
(Dollars in millions) 1998 1997
- -----------------------------------------------------------------
Trading Assets
Unrealized gains on swaps and forwards $756 $497
Due from commodity clearing organization
and clearing brokers 75 41
OTC commodity options purchased 45 33
Due from trading counterparties 30 16
---------------------
Total $906 $587
- -----------------------------------------------------------------
Trading Liabilities
Unrealized losses on swaps and forwards $740 $487
Due to trading counterparties 35 41
OTC commodity options written 30 29
---------------------
Total $805 $557
- -----------------------------------------------------------------
Notional amounts do not necessarily represent the amounts exchanged
by parties to the financial instruments and do not measure SET's exposure
to credit or market risks. The notional or contractual amounts are used
to summarize the volume of financial instruments, but do not reflect the
extent to which positions may offset one another. Accordingly, SET is
exposed to much smaller amounts potentially subject to risk. The notional
amounts of SET's financial instruments are:
- -----------------------------------------------------------------
(Dollars in millions) Total
- -----------------------------------------------------------------
Forwards and commodity swaps $5,916
Futures and exchange options 2,915
Options purchased 1,320
Options written 1,298
--------------
Total $11,449
- -----------------------------------------------------------------
11 PREFERRED STOCK OF SUBSIDIARIES
- -----------------------------------------------------------------
Pacific Enterprises Call December 31,
(Dollars in millions except call price) Price 1998 1997
- -----------------------------------------------------------------
Cumulative preferred
without par value:
$4.75 Dividend, 200,000 shares
authorized and outstanding $100.00 $20 $20
$4.50 Dividend, 300,000 shares
authorized and outstanding $100.00 30 30
$4.40 Dividend, 100,000 shares
authorized and outstanding $101.50 10 10
$4.36 Dividend, 200,000 shares
authorized and outstanding $101.00 20 20
$4.75 Dividend, 253 shares
authorized and outstanding $101.00 - -
--------------
Total $80 $80
- -----------------------------------------------------------------
All or any part of every series of presently outstanding PE
preferred stock is subject to redemption at PE's option at any time upon
not less than 30 days' notice, at the applicable redemption price for
each series, together with the accrued and accumulated dividends to the
date of redemption. All series have one vote per share and cumulative
preferences as to dividends. No shares of Unclassified or Class A
preferred stock are outstanding.
- -----------------------------------------------------------------
SoCalGas December 31,
(Dollars in millions) 1998 1997
- -----------------------------------------------------------------
Not subject to mandatory redemption:
$25 par value, authorized 1,000,000 shares
6% Series, 28,664 shares outstanding $1 $1
6% Series A, 783,032 shares outstanding 19 19
Without par value, authorized 10,000,000 shares
7.75% Series - 75
--------------
$20 $95
- -----------------------------------------------------------------
None of SoCalGas' series of preferred stock is callable. All series
have one vote per share and cumulative preferences as to dividends. On
February 2, 1998, SoCalGas redeemed all outstanding shares of 7.75%
Series Preferred Stock at a price per share of $25 plus $0.09 of
dividends accruing to the date of redemption. The total cost to SoCalGas
was approximately $75.3 million.
- -----------------------------------------------------------------
SDG&E Call December 31,
(Dollars in millions except call price) Price 1998 1997
- -----------------------------------------------------------------
Not subject to mandatory redemption
$20 par value, authorized
1,375,000 shares:
5% Series, 375,000
shares outstanding $24.00 $8 $8
4.50% Series, 300,000
shares outstanding $21.20 6 6
4.40% Series, 325,000
shares outstanding $21.00 7 7
4.60% Series, 373,770
shares outstanding $20.25 7 7
Without par value:
$1.70 Series, 1,400,000
shares outstanding $25.85 35 35
$1.82 Series, 640,000
shares outstanding $26.00 16 16
--------------
Total not subject to
mandatory redemption $79 $79
--------------
Subject to mandatory redemption
Without par value:
$1.7625 Series, 1,000,000
shares outstanding $25.00 $25 $25
- -----------------------------------------------------------------
All series of SDG&E's preferred stock have cumulative preferences as
to dividends. The $20 par value preferred stock has two votes per share
on matters being voted upon by shareholders of SDG&E and a liquidation
value at par, whereas the no-par-value preferred stock is nonvoting and
has a liquidation value of $25 per share. SDG&E is authorized to issue
10,000,000 shares of no-par-value stock (both subject to and not subject
to mandatory redemption). All series are currently callable except for
the $1.70 and $1.7625 series (callable in 2003). The $1.7625 series has a
sinking fund requirement to redeem 50,000 shares per year from 2003 to
2007; the remaining 750,000 shares must be redeemed in 2008.
12 SHAREHOLDERS EQUITY AND EARNINGS PER SHARE
The company's outstanding stock options represent the only forms of
potential common stock at December 31, 1998, 1997 and 1996. The
reconciliation between basic and diluted EPS is as follows:
- -----------------------------------------------------------------
Income Shares Earnings
(in millions) (in thousands) Per Share
- -----------------------------------------------------------------
1998:
Basic $294 236,423 $1.24
Effect of dilutive
stock options 701
- -----------------------------------------------------------------
Diluted $294 237,124 $1.24
- -----------------------------------------------------------------
1997:
Basic $432 236,662 $1.83
Effect of dilutive
stock options 587
- -----------------------------------------------------------------
Diluted $432 237,249 $1.82
- -----------------------------------------------------------------
1996:
Basic $427 240,825 $1.77
Effect of dilutive
stock options 332
- -----------------------------------------------------------------
Diluted $427 241,157 $1.77
- -----------------------------------------------------------------
The company is authorized to issue 750,000,000 shares of no par
value common stock and 50,000,000 shares of Preferred Stock. At December
31, 1998, there were 240,026,439 shares of common stock outstanding,
compared to 235,598,111 shares outstanding at December 31, 1997. No
shares of Preferred Stock were issued and outstanding.
13 COMMITMENTS AND CONTINGENCIES
Natural Gas Contracts
The company buys natural gas under several short-term and long-term
contracts. Short-term purchases are based on monthly spot-market prices.
SoCalGas has commitments for firm pipeline capacity under contracts with
pipeline companies that expire at various dates through the year 2006.
These agreements provide for payments of an annual reservation charge.
SoCalGas recovers such fixed charges in rates.
SDG&E has long-term capacity contracts with interstate pipelines
which expire on various dates between 2007 and 2023. SDG&E has long-term
natural gas supply contracts (included in the table below) with four
Canadian suppliers that expire between 2001 and 2004. SDG&E has been
involved in negotiations and litigation with the suppliers concerning the
contracts' terms and prices. SDG&E has settled with three of the
suppliers. One of the three is delivering natural gas under the terms of
the settlement agreement; the other two have ceased deliveries. The
fourth supplier has ceased deliveries pending legal resolution. A U.S.
Court of Appeal has upheld a U.S. District Court's invalidation of the
contracts with two of these suppliers. If the supply of Canadian natural
gas to SDG&E is not resumed to a level approximating the related
committed long-term pipeline capacity, SDG&E intends to continue using
the capacity in other ways, including the transport of replacement gas
and the release of a portion of this capacity to third parties.
At December 31, 1998, the future minimum payments under natural gas
contracts were:
- -----------------------------------------------------------------
Storage and
(Dollars in millions) Transportation Natural Gas
- -----------------------------------------------------------------
1999 $193 $288
2000 195 170
2001 197 175
2002 197 179
2003 193 181
Thereafter 587 -
----------------------------------
Total minimum payments $1,562 $993
- -----------------------------------------------------------------
Total payments under the short-term and long-term contracts were
$1.0 billion in 1998, $1.2 billion in 1997, and $1.0 billion in 1996.
All of SDG&E's gas is delivered through SoCalGas pipelines under a
short-term transportation agreement. In addition, SoCalGas provides SDG&E
six billion cubic feet of natural gas storage capacity under an agreement
expiring March 2000. These agreements are not included in the above
table.
Purchased-Power Contracts
SDG&E buys electric power under several long-term contracts. The
contracts expire on various dates between 1999 and 2025. Under
California's Electric Industry Restructuring law, which is described in
Note 14, the California investor-owned electric utilities (IOUs) are
obligated to bid their power supply, including owned generation and
purchased-power contracts, into the California Power Exchange (PX). As a
result, SDG&E's system requirements are met primarily through purchases
from the PX.
At December 31, 1998, the estimated future minimum payments under
the long-term contracts were:
- -----------------------------------------------------------------
(Dollars in millions)
- -----------------------------------------------------------------
1999 $249
2000 211
2001 174
2002 136
2003 135
Thereafter 2,001
----------
Total minimum payments $2,906
- -----------------------------------------------------------------
These payments for actual purchases represent capacity charges and
minimum energy purchases. SDG&E is required to pay additional amounts for
actual purchases of energy that exceed the minimum energy commitments.
Total payments, including actual energy payments, under the contracts
were $293 million in 1998, $421 million in 1997 and $296 million in 1996.
Payments under purchased-power contracts decreased in 1998 as a result of
the purchases from the PX, which commenced April 1, 1998.
SDG&E has entered into agreements to sell its power plants and other
electric-generating resources (excluding SONGS), and has announced a plan
to auction its long-term purchased power contracts. Additional
information on this topic is provided in Note 14.
Leases
The company has leases (primarily operating) on real and personal
property expiring at various dates from 1999 to 2030. Certain leases on
office facilities contain escalation clauses requiring annual increases
in rent ranging from 2 percent to 7 percent. The rentals payable under
these leases are determined on both fixed and percentage bases, and most
leases contain options to extend, which are exercisable by the company.
The company also has nuclear fuel, office buildings, a generating
facility and other properties that are financed by long-term capital
leases. Utility plant includes $177 million at December 31, 1998, and
$198 million at December 31, 1997, related to these leases. The
associated accumulated amortization is $114 million and $102 million,
respectively.
The minimum rental commitments payable in future years under all
noncancellable leases are:
- -----------------------------------------------------------------
Operating Capitalized
(Dollars in millions) Leases Leases
- -----------------------------------------------------------------
1999 $60 $31
2000 58 14
2001 55 14
2002 52 14
2003 51 11
Thereafter 380 9
------------------------------
Total future rental commitment $656 93
Imputed interest (6% to 9%) (17)
-----------
Net commitment $76
- -----------------------------------------------------------------
Rent expense totaled $105 million in 1998, $137 million in 1997 and
$146 million in 1996.
In connection with the quasi-reorganization described in Note 2, PE
established reserves of $102 million to fair value operating leases
related to its headquarters and other leases at December 31, 1992. The
remaining amount of these reserves was $76 million at December 31, 1998.
These leases are reflected in the above table.
Environmental Issues
The company believes that its operations are conducted in accordance with
federal, state and local environmental laws and regulations governing
hazardous wastes, air and water quality, land use, and solid waste
disposal. SoCalGas and SDG&E incur significant costs to operate their
facilities in compliance with these laws and regulations. The costs of
compliance with environmental laws and regulations generally have been
recovered in customer rates.
In 1994, the CPUC approved the Hazardous Waste Collaborative
Memorandum account allowing utilities to recover their hazardous waste
costs, including those related to Superfund sites or similar sites
requiring cleanup. Recovery of 90 percent of cleanup costs and related
third-party litigation costs and 70 percent of the related insurance-
litigation expenses is permitted. Environmental liabilities that may
arise are recorded when remedial efforts are probable and the costs can
be estimated.
The company's capital expenditures to comply with environmental laws
and regulations were $1 million in 1998, $5 million in 1997, and $9
million in 1996, and are not expected to be significant during the next
five years. These expenditures primarily include the cost of retrofitting
SDG&E's power plants to reduce air emissions. These costs will be reduced
significantly by SDG&E's sale of its non-nuclear generating facilities.
The company has been associated with various sites which may require
remediation under federal, state or local environmental laws. The company
is unable to determine fully the extent of its responsibility for
remediation of these sites until assessments are completed. Furthermore,
the number of others that also may be responsible, and their ability to
share in the cost of the cleanup, is not known. The company does not
anticipate that such costs, net of the portion recoverable in rates, will
be significant.
As discussed in Note 14, restructuring of the California electric-
utility industry will change the way utility rates are set and costs are
recovered. SDG&E asked that the collaborative account be modified, and
that electric generation-related cleanup costs be eligible for
transition-cost recovery. The final outcome of this decision is that
SDG&E's costs of compliance with environmental regulations may be fully
recoverable.
Nuclear Insurance
SDG&E and the co-owners of SONGS have purchased primary insurance of $200
million, the maximum amount available, for public-liability claims. An
additional $8.7 billion of coverage is provided by secondary financial
protection required by the Nuclear Regulatory Commission and provides for
loss sharing among utilities owning nuclear reactors if a costly accident
occurs. SDG&E could be assessed retrospective premium adjustments of up
to $32 million in the event of a nuclear incident involving any of the
licensed, commercial reactors in the United States, if the amount of the
loss exceeds $200 million. In the event the public-liability limit stated
above is insufficient, the Price-Anderson Act provides for Congress to
enact further revenue-raising measures to pay claims, which could include
an additional assessment on all licensed reactor operators.
Insurance coverage is provided for up to $2.8 billion of property
damage and decontamination liability. Coverage is also provided for the
cost of replacement power, which includes indemnity payments for up to
three years, after a waiting period of 17 weeks. Coverage is provided
primarily through mutual insurance companies owned by utilities with
nuclear facilities. If losses at any of the nuclear facilities covered by
the risk-sharing arrangements were to exceed the accumulated funds
available from these insurance programs, SDG&E could be assessed
retrospective premium adjustments of up to $6 million.
Department of Energy Decommissioning
The Energy Policy Act of 1992 established a fund for the decontamination
and decommissioning of the Department of Energy nuclear-fuel-enrichment
facilities. Utilities which have used DOE enrichment services are being
assessed a total of $2.3 billion, subject to adjustment for inflation,
over a 15-year period ending in 2006. Each utility's share is based on
its share of enrichment services purchased from the DOE through 1992.
SDG&E's annual assessment is approximately $1 million. This assessment is
recovered through SONGS revenue.
Litigation
The company is involved in various legal matters, including those arising
out of the ordinary course of business. Management believes that these
matters will not have a material adverse effect on the company's results
of operations, financial condition or liquidity.
Electric Distribution System Conversion
Under a CPUC-mandated program and through franchise agreements with
various cities, SDG&E is committed, in varying amounts, to converting
overhead distribution facilities to underground. As of December 31, 1998,
the aggregate unexpended amount of this commitment was approximately $104
million. Capital expenditures for underground conversions were $17
million in 1998, $17 million in 1997, and $15 million in 1996.
Concentration of Credit Risk
The company maintains credit policies and systems to minimize overall
credit risk. These policies include, when applicable, the use of an
evaluation of potential counterparties' financial condition and an
assignment of credit limits. These credit limits are established based on
risk and return considerations under terms customarily available in the
industry. SDG&E and SoCalGas grant credit to their utility customers,
substantially all of whom are located in their service territories, which
together cover most of Southern California and a portion of central
California.
SET monitors and controls its credit-risk exposures through various
systems which evaluate its credit risk, and through credit approvals and
limits. To manage the level of credit risk, SET deals with a majority of
counterparties with good credit standing, enters into master netting
arrangements whenever possible and, where appropriate, obtains
collateral. Master netting agreements incorporate rights of setoff that
provide for the net settlement of subject contracts with the same
counterparty in the event of default.
14 REGULATORY MATTERS
Electric-Industry Restructuring
In September 1996, California enacted a law restructuring its electric-
utility industry (AB 1890). The legislation adopts the December 1995 CPUC
policy decision restructuring the industry to stimulate competition and
reduce rates.
Beginning on March 31, 1998, customers were given the opportunity to
choose to continue to purchase their electricity from the local utility
under regulated tariffs, to enter into contracts with other energy-
service providers (direct access) or to buy their power from the
independent Power Exchange (PX) that serves as a wholesale power pool
allowing all energy producers to participate competitively. The PX
obtains its power from qualifying facilities, from nuclear units and,
lastly, from the lowest-bidding suppliers. The California investor-owned
electric utilities (IOUs) are obligated to sell their power supply,
including owned-generation and purchased-power contracts, to the PX. The
IOUs are also obligated to purchase from the PX the power that they
distribute. An Independent System Operator (ISO) schedules power
transactions and access to the transmission system. The local utility
continues to provide distribution service regardless of which source the
consumer chooses. An example of these changes in the electric-utility
environment is the U.S. Navy, SDG&E's largest customer. The U.S. Navy's
contract to purchase energy from SDG&E was not renewed when it expired on
September 30, 1998. Instead, the U.S. Navy elected to obtain energy
through direct access and SDG&E continues to provide the distribution
service.
Utilities are allowed a reasonable opportunity to recover their
stranded costs via a competition transition charge (CTC) to customers
through December 31, 2001. Stranded costs include sunk costs, as well as
ongoing costs the CPUC finds reasonable and necessary to maintain
generation facilities through December 31, 2001. These costs also include
other items SDG&E has recorded under traditional cost-of-service
regulation. Certain stranded costs, such as those related to reasonable
employee-related costs directly caused by restructuring, and purchased-
power contracts (including those with qualifying facilities) may be
recovered beyond December 31, 2001. To the extent that the opportunity to
recover stranded costs is reduced by the costs to accommodate the
implementation of direct access and the ISO/PX during the rate freeze,
those displaced stranded costs may be recovered after December 31, 2001.
Outside of those exceptions, stranded costs not recovered through 2001
will not be collected from customers. Such costs, if any, would be
written off as a charge against earnings. Nuclear decommissioning costs
are nonbypassable until fully recovered, but are not included as part of
transition costs. Additional information is provided in Note 10.
Through December 31, 1998, SDG&E has recovered transition costs of
$500 million for nuclear generation and $200 million for non-nuclear
generation. Excluding the costs of purchased power and other costs whose
recovery is not limited to the pre-2002 period, the balance of SDG&E's
stranded assets at December 31, 1998, is $600 million, consisting of $400
million for the power plants and $200 million of related deferred taxes
and undercollections.
In November 1997, SDG&E announced a plan to auction its power plants
and other electric-generating assets. This plan includes the divestiture
of SDG&E's fossil power plants and combustion turbines, its 20-percent
interest in SONGS and its portfolio of long-term purchased-power
contracts. The power plants, including the interest in SONGS, have a net
book value as of December 31, 1998, of $400 million ($100 million for
fossil and $300 million for SONGS) and a combined generating capacity of
2,400 megawatts. The proceeds from the sales, net of the costs of the
sales and certain environmental cleanup costs, will be applied directly
to SDG&E's transition costs. The fossil-fuel assets' auction is being
separated from the auction of SONGS and the purchased-power contracts. In
October 1998 the CPUC issued an interim decision approving the
commencement of the fossil fuel assets' auction.
On December 11, 1998, contracts were executed for the sale of
SDG&E's South Bay Power Plant, Encina Power Plant and 17 combustion-
turbine generators. The South Bay Power Plant is being sold to the San
Diego Unified Port District for $110 million. The Encina Power Plant and
the combustion-turbine generators are being sold to a special-purpose
entity owned equally by Dynegy Power Corp. and NRG Energy, Inc. for $356
million. The sales are subject to regulatory approval and are expected to
close during the first half of 1999.
During the 1998-2001 period, recovery of transition costs is limited
by the rate freeze discussed below. Management believes that rates and
the proceeds from the sale of electric-generating assets will be
sufficient to recover all of SDG&E's approved transition costs by
December 31, 2001, not including the post-2001 purchased-power contracts
payments that may be recovered after 2001. However, if 1998-2001
generation costs, principally fuel costs, are greater than anticipated,
SDG&E may be unable to recover all of its approved transition costs. This
would result in a charge against earnings at the time it ceases to be
probable that SDG&E will be able to recover all of the transition costs.
AB 1890 requires a 10-percent reduction of residential and small
commercial customers' rates, beginning in January 1998, and provides for
the issuance of rate-reduction bonds by an agency of the state of
California to enable the IOUs to achieve this rate reduction. In December
1997, $658 million of rate-reduction bonds were issued on behalf of SDG&E
at an average interest rate of 6.26 percent. These bonds are being repaid
over 10 years by SDG&E's residential and small commercial customers via a
nonbypassable charge on their electric bills. In 1997, SDG&E formed a
subsidiary, SDG&E Funding LLC, to facilitate the issuance of the bonds.
In exchange for the bond proceeds, SDG&E sold to SDG&E Funding LLC all of
its rights to certain revenue streams collected from such customers.
Consequently, the transaction is structured to cause such revenue streams
not to be the property of SDG&E nor to be available to satisfy any claims
of SDG&E's creditors.
AB 1890 includes a rate freeze for all electric customers. Until the
earlier of March 31, 2002, or when transition-cost recovery is complete,
SDG&E's system-average rate will be frozen at the June 10, 1996, levels
of 9.64 cents per kwh, except for the impact of fuel-cost changes and the
10-percent rate reduction described above. Beginning in 1998, system-
average rates were fixed at 9.43 cents per kwh, which includes the
maximum permitted increase related to fuel-cost increases and the
mandatory rate reduction.
In early 1999, SDG&E filed with the CPUC for an interim mechanism to
deal with electric rates after the rate freeze ends, noting the
possibility that the SDG&E rate freeze could end in 1999.
As discussed in Note 2, SDG&E has been accounting for the economic
effects of regulation in accordance with SFAS No. 71. The SEC indicated a
concern that California's investor-owned utilities (IOUs) may not meet
the criteria of SFAS No. 71 with respect to their electric-generation
regulatory assets. SDG&E has ceased the application of SFAS No. 71 to its
generation business, in accordance with the conclusion of the Emerging
Issues Task Force of the Financial Accounting Standards Board that the
application of SFAS 71 should be discontinued when legislation is issued
that determines that a portion of an entity's business will no longer be
subject to traditional cost-of-service regulation. The discontinuance of
SFAS No. 71 applied to the IOUs' generation business did not result in a
write-off of their net regulatory assets since the CPUC has approved the
recovery of these assets by the distribution portion of their operations,
subject to the rate freeze.
In October 1997, the FERC approved key elements of the California
IOUs' restructuring proposal. This included the transfer by the IOUs of
the operational control of their transmission facilities to the ISO,
which is under FERC jurisdiction. The FERC also approved the
establishment of the California PX to operate as an independent wholesale
power pool. The IOUs pay to the PX an upfront restructuring charge (in
four annual installments) and an administrative-usage charge for each
megawatt hour of volume transacted. SDG&E's share of the restructuring
charge is approximately $10 million, which is being recovered as a
transition cost. The IOUs have guaranteed $300 million of commercial
loans to the ISO and PX for their development and initial start-up.
SDG&E's share of the guarantee is $30 million.
Thus far, electric-industry deregulation has been confined to
generation. Transmission and distribution have remained subject to
traditional cost-of-service regulation. However, the CPUC is exploring
the possibility of opening up electric distribution to competition.
During 1999, the CPUC will be conducting a rulemaking, one objective of
which may be to develop a coordinated proposal for the state legislature
regarding how various distribution competition issues should be
addressed. SDG&E and SoCalGas will actively participate in this effort.
Gas Industry Restructuring
The natural gas industry experienced an initial phase of restructuring
during the 1980s by deregulating gas sales to noncore customers. On
January 21, 1998, the CPUC released a staff report initiating a project
to assess the current market and regulatory framework for California's
natural gas industry. The general goals of the plan are to consider
reforms to the current regulatory framework emphasizing market-oriented
policies benefiting California natural gas consumers.
On August 25, 1998, California adopted a law prohibiting the CPUC
from enacting any natural gas industry restructuring decision for
customers prior to January 1, 2000. During the implementation moratorium,
the CPUC will hold hearings throughout the state and intends to give the
California Legislature a report for its review detailing specific
recommendations for changing the natural gas market within California.
SDG&E and SoCalGas will actively participate in this effort.
Performance-Based Regulation (PBR)
To promote efficient operations and improved productivity and to move
away from reasonableness reviews and disallowances, the CPUC has been
directing utilities to use PBR. PBR has replaced the general rate case
and certain other regulatory proceedings for both SoCalGas and SDG&E.
Under PBR, regulators require future income potential to be tied to
achieving or exceeding specific performance and productivity measures, as
well as cost reductions, rather than relying solely on expanding utility
rate base in a market where a utility already has a highly developed
infrastructure.
SoCalGas' PBR is in effect through December 31, 2002; however, the
CPUC decision allows for the possibility that changes to the PBR
mechanism could be adopted in a decision to be issued in SoCalGas' 1999
Biennial Cost Allocation Proceeding, which is anticipated to become
effective before year end 1999. Key elements of the SoCalGas PBR include
an initial reduction in base rates, an indexing mechanism that limits
future rate increases to the inflation rate less a productivity factor, a
sharing mechanism with customers if earnings exceed the authorized rate
of return on rate base, and rate refunds to customers if service quality
deteriorates. Specifically, the key elements of SoCalGas' PBR include the
following:
- --Earnings up to 25 basis points in excess of the authorized rate of
return on rate base are retained 100 percent by shareholders. Earnings
that exceed the authorized rate of return on rate base by greater than 25
basis points are shared between customers and shareholders on a sliding
scale that begins with 75 percent of the additional earnings being given
back to customers and declining to 0 percent as earned returns approach
300 basis points above authorized amounts. There is no sharing if actual
earnings fall below the authorized rate of return. In 1999, SoCalGas is
authorized to earn a 9.49 percent return on rate base, the same as in
1998.
- --Revenue or base margin per customer is indexed based on inflation less
an estimated productivity factor of 2.1 percent in the first year (1998),
increasing 0.1 percent per year up to 2.5 percent in the fifth year
(2002). This factor includes 1 percent to approximate the projected
impact of a declining rate base.
- --The CPUC decision allows for pricing flexibility for residential and
small commercial customers, with any shortfalls in revenue being borne by
shareholders and with any increase in revenue shared between shareholders
and customers.
Under SoCalGas' PBR, annual cost of capital proceedings are replaced
by an automatic adjustment mechanism if changes in certain indices exceed
established tolerances. The mechanism is triggered if the 12-month
trailing average of actual market interest rates increases or decreases
by more than 150 basis points and is forecasted to continue to vary by at
least 150 basis points for the next year. If this occurs, there would be
an automatic adjustment of rates for the change in the cost of capital
according to a preestablished formula which applies a percentage of the
change to various capital components.
SDG&E continues to participate in a PBR process for base rates for
its electric and natural gas distribution business. In conjunction
therewith, in December 1998, a Cost of Service settlement agreement among
SDG&E, the CPUC's Office of Ratepayers' Advocates (ORA) and the Utility
Consumers' Action Network (UCAN) was approved by the CPUC, resulting in
an authorized revenue increase of $12 million (an electric-distribution
increase of $18 million and a natural gas decrease of $6 million). The
electric-distribution increase does not affect rates during the rate
freeze and, therefore, reduces the amount available for transition cost
recovery. Revised rates were effective January 1, 1999.
In January 1999, an administrative law judge's proposed decision was
issued on SDG&E's distribution PBR application. The proposed decision
recommends a revenue-per-customer indexing mechanism (similar to the
indexing mechanism in SoCalGas' PBR) rather than the rate-indexing
mechanism proposed by SDG&E. In addition, the proposed decision
recommends much tighter earnings sharing bands (similar to SoCalGas').
The performance indicators are as adopted in the settlement agreement,
including employee safety, electric reliability, customer satisfaction,
call-center responsiveness and electric-system maintenance. SDG&E would
be authorized to earn or be penalized up to a maximum of $14.5 million
annually as a result of its performance in those areas.
Comprehensive Settlement Of Natural Gas Regulatory Issues
In July 1994, the CPUC approved a comprehensive settlement for SoCalGas
(Comprehensive Settlement) of a number of regulatory issues, including
rate recovery of a significant portion of the restructuring costs
associated with certain long-term contracts with suppliers of California-
offshore and Canadian natural gas. In the past, the cost of these
supplies had been substantially in excess of SoCalGas' average delivered
cost for all natural gas supplies. The restructured contracts
substantially reduced the ongoing delivered costs of these supplies. The
Comprehensive Settlement permits SoCalGas to recover in utility rates
approximately 80 percent of the contract-restructuring costs of $391
million and accelerated amortization of related pipeline assets of
approximately $140 million, together with interest, incurred prior to
January 1, 1999. In addition to the supply issues, the Comprehensive
Settlement addressed the following other regulatory issues:
- --Noncore Customer Rates. The Comprehensive Settlement changed the
procedures for determining noncore rates to be charged by SoCalGas for
the five-year period commencing August 1, 1994. These rates are based
upon SoCalGas' recorded throughput to these customers for 1991. SoCalGas
will bear the full risk of any declines in noncore deliveries from 1991
levels. Any revenue enhancement from deliveries in excess of 1991 levels
will be limited by a crediting account mechanism that will require a
credit to customers of 87.5 percent of revenues in excess of certain
limits. These annual limits above which the credit is applicable increase
from $11 million to $19 million over the five-year period from August 1,
1994, through July 31, 1999. SoCalGas' ability to report as earnings the
results from revenues in excess of SoCalGas' authorized return from
noncore customers due to volume increases has been limited for the five
years beginning August 1, 1994, as a result of the Comprehensive
Settlement. The 1999 Biennial Cost Allocation Proceeding is intended to
adopt measures to replace this aspect of the Comprehensive Settlement
when it expires during 1999.
- --Gas Cost Incentive Mechanism (GCIM). On April 1, 1994, SoCalGas
implemented a new process for evaluating its natural gas purchases,
substantially replacing the previous process of reasonableness reviews.
Initially a three-year pilot program, in December 1998 the CPUC extended
the GCIM program indefinitely. Automatic annual extensions to the program
will continue unless the CPUC issues an order stating otherwise.
GCIM compares SoCalGas' cost of natural gas with a benchmark level,
which is the average price of 30-day firm spot supplies in the basins in
which SoCalGas purchases the natural gas. 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
equally between customers and shareholders.
The CPUC approved the use of natural gas futures for managing risk
associated with the GCIM. SoCalGas enters into natural gas futures
contracts in the open market on a limited basis to mitigate risk and
better manage natural gas costs.
In June 1997, SoCalGas requested a shareholder award of $11 million,
which was approved by the CPUC in June 1998 and is included in pretax
income in 1998. In June 1998, SoCalGas filed its annual GCIM application
with the CPUC requesting an award of $2 million for the annual period
ended March 31, 1998. This request was approved by the CPUC in December
1998 and is included in pretax income in 1998.
- --Attrition Allowances. The Comprehensive Settlement authorized SoCalGas
an annual allowance for increases in operating and maintenance expenses.
However, no attrition allowance was authorized for 1997 and beyond, based
on an agreement reached as part of the PBR application.
PE and SoCalGas recorded the impact of the Comprehensive Settlement
in 1993. Upon giving effect to liabilities previously recognized by the
companies, the costs of the Comprehensive Settlement, including the
restructuring of natural gas supply contracts, did not result in any
future charge to PE's earnings.
Biennial Cost Allocation Proceeding (BCAP)
In the second quarter of 1997, the CPUC issued a decision on SoCalGas'
1996 BCAP filing. In this decision, the CPUC considered SoCalGas'
relinquishments of interstate pipeline capacity on both the El Paso and
Transwestern pipelines. This resulted in a reduction in the pipeline
demand charges allocated to SoCalGas' customers and surcharges allocated
to firm capacity holders through pipeline rate-case settlements adopted
at the FERC. However, the CPUC and FERC are reviewing the decision.
In October 1998, SoCalGas and SDG&E filed 1999 BCAP applications
requesting that new rates become effective August 1, 1999 and remain in
effect through December 31, 2002. The proposed beginning date follows the
conclusion of the Comprehensive Settlement (discussed above), and the
proposed end date aligns with the expiration of SoCalGas' and SDG&E's
PBRs. The applications seek overall decreases in natural gas revenues of
$204 million for SoCalGas and $9 million for SDG&E.
Cost of Capital
Under PBR, annual Cost of Capital proceedings were replaced by an
automatic adjustment mechanism if changes in certain indices exceed
established tolerances. For 1999, SoCalGas is authorized to earn a rate
of return on common equity (ROE) of 11.6 percent and a 9.49 percent
return on rate base (ROR), the same as in 1998, unless interest-rate
changes are large enough to trigger an automatic adjustment as discussed
above under "Performance-Based Regulation." For SDG&E, electric-industry
restructuring is changing the method of calculating the utility's annual
cost of capital. In May 1998, SDG&E filed with the CPUC its unbundled
Cost of Capital application for 1999 rates. The application seeks
approval to establish new, separate rates of return for SDG&E's electric-
distribution and natural gas businesses. The application proposes a 12.00
percent ROE, which would produce an overall ROR of 9.33 percent. The ORA,
UCAN and other intervenors have filed testimony recommending
significantly lower RORs. The ORA is recommending an electric ROR of 7.68
percent and a gas ROR of 8.01 percent. A CPUC decision is expected during
the second quarter of 1999. In 1998, SDG&E's electric and natural gas
distribution operations were authorized to earn an ROE of 11.6 percent
and an ROR of 9.35 percent, unchanged from 1997. In addition, the
authorized rates of return on nuclear and non-nuclear generating assets
are 7.14 percent and 6.75 percent, respectively.
Transactions Between Utilities and Affiliated Companies
On December 16, 1997, the CPUC adopted rules, effective January 1, 1998,
establishing uniform standards of conduct governing the manner in which
IOUs conduct business with their energy-related affiliates. The objective
of the affiliate-transaction rules is to ensure that these affiliates do
not gain an unfair advantage over other competitors in the marketplace
and that utility customers do not subsidize affiliate activities. The
rules establish standards relating to non-discrimination, disclosure and
information exchange, and separation of activities.
The CPUC excluded utility-to-utility transactions between SDG&E and
SoCalGas from the affiliate-transaction rules in its March 1998 decision
approving the business combination of Enova and PE (see Note 1).
15 SEGMENT INFORMATION
The company, primarily an energy-services company, has three separately
managed reportable segments comprised of SoCalGas, SDG&E and Sempra
Energy Trading (SET). The two utilities operate in essentially separate
service territories under separate regulatory frameworks and rate
structures set by the CPUC. As described in Note 1, SDG&E provides
electric and natural gas service to San Diego and southern Orange
counties. SoCalGas is a natural gas distribution utility, serving
customers throughout most of Southern California and part of central
California. SET is based in Stamford, Connecticut, and is engaged in the
nationwide wholesale trading and marketing of natural gas, power and
petroleum. The accounting policies of the segments are the same as those
described in Note 2, and segment performance is evaluated by management
based on reported net income. Intersegment transactions generally are
recorded the same as sales or transactions with third parties. Utility
transactions are primarily based on rates set by the CPUC and FERC.
- -----------------------------------------------------------------
For the year ended December 31
(Dollars in millions) 1998 1997 1996
- -----------------------------------------------------------------
Operating Revenues:
Southern California Gas $2,427 $2,641 $2,422
San Diego Gas & Electric 2,749 2,167 1,939
Sempra Energy Trading 110 - -
Intersegment revenues (59) (55) (60)
All other 254 316 195
------------------------------
Total $5,481 $5,069 $4,496
------------------------------
Interest Revenue:
Southern California Gas $4 $16 $5
San Diego Gas & Electric 40 9 7
Sempra Energy Trading 3 - -
All other interest 3 21 23
------------------------------
Total interest 50 46 35
Sundry income (loss) (6) 12 (7)
------------------------------
Total other income $44 $58 $28
------------------------------
Depreciation and Amortization:
Southern California Gas $254 $251 $248
San Diego Gas & Electric
(See Note 14) 603 324 314
Sempra Energy Trading 13 - -
All other 59 29 25
------------------------------
Total $929 $604 $587
------------------------------
Interest Expense:
Southern California Gas $80 $87 $86
San Diego Gas & Electric 116 86 91
Sempra Energy Trading 5 - -
All other 6 33 23
------------------------------
Total $207 $206 $200
------------------------------
Income Tax Expense (Benefit):
Southern California Gas $128 $178 $148
San Diego Gas & Electric 142 219 198
Sempra Energy Trading (9) - -
All other (123) (96) (46)
------------------------------
Total $138 $301 $300
------------------------------
Net Income:
Southern California Gas $158 $231 $193
San Diego Gas & Electric 185 232 216
Sempra Energy Trading (13) - -
All other (36) (31) 18
------------------------------
Total $294 $432 $427
------------------------------
- -----------------------------------------------------------------
At December 31, or for
the year then ended
(Dollars in millions) 1998 1997 1996
- -----------------------------------------------------------------
Assets:
Southern California Gas $3,834 $4,205 $4,354
San Diego Gas & Electric 4,257 4,654 4,161
Sempra Energy Trading 1,225 846 -
All other 1,253 1,181 1,257
Eliminations (113) (130) (10)
------------------------------
Total $10,456 $10,756 $9,762
------------------------------
Capital Expenditures:
Southern California Gas $128 $159 $197
San Diego Gas & Electric 227 197 209
Sempra Energy Trading - - -
All other 83 41 7
------------------------------
Total $438 $397 $413
------------------------------
Geographic Information:
Long-lived assets:
United States $5,849 $5,904 $6,647
Latin America 140 67 50
------------------------------
Total $5,989 $5,971 $6,697
------------------------------
Operating Revenues:
United States $5,474 $5,058 $4,488
Latin America 7 11 8
------------------------------
Total $5,481 $5,069 $4,496
- -----------------------------------------------------------------
16 SUBSEQUENT EVENT
On February 22, 1999, the company and KN Energy, Inc. (KN Energy)
announced that their respective boards of directors approved the
company's acquisition of KN Energy, subject to approval by the
shareholders of both companies and by various federal and state
regulatory agencies. If the transaction is approved, holders of KN Energy
common stock will receive 1.115 shares of company common stock or $25 in
cash, or some combination thereof, for each share of KN Energy common
stock. In the aggregate, the cash portion of the transaction will
constitute not more than 30 percent of the total consideration of $1.7
billion. The companies anticipate that the closing will occur in six to
eight months. The transaction will be treated as a purchase for
accounting purposes.
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareholders of
Sempra Energy
San Diego, California
We have audited the consolidated financial statements of Sempra
Energy and subsidiaries as of December 31, 1998 and 1997 and for each
of the three years in the period ended December 31, 1998, and have
issued our unqualified report thereon dated January 27, 1999, except
for Note 16 as to which the date is February 22, 1999. Our audits
also included the Supplemental Schedule of Summarized Financial
Information. This schedule of summarized financial information is the
responsibility of Sempra Energy's management. Our responsibility is
to express an opinion based on our audits. In our opinion, such
schedule of summarized financial information, when considered in
relation to the basic financial statements taken as a whole, presents
fairly in all material respects the information set forth therein.
/S/ DELOITTE & TOUCHE LLP
San Diego, California
January 27, 1999, except for Note 16 as to which the date is
February 22, 1999
Supplemental Schedule of Summarized Financial Information
Sempra Energy Holdings, Inc.
(in millions of dollars)
December 31,
1998 1997
Current Assets $1,470 $ 778
Non-current Assets 544 619
Current Liabilities 1,452 663
Non-current Liabilities 140 205
Year Ended December 31,
1998 1997 1996
Operating Revenues $ 572 $ 526 $ 301
Operating Expenses 667 585 319
Net Loss 54 17 4
Note 1: Basis of Presentation
The summarized financial information as of December 31, 1998 and
December 31, 1997 and for each of the three years in the period ended
December 31, 1998 includes certain subsidiaries of Sempra Energy that
are not subject to California utility regulation (principally Sempra
Energy Solutions, Sempra Energy Trading, CES/Way, Sempra Energy
Resources and Sempra Energy International) at the dates and for the
periods they were owned by Sempra Energy. Although not all of the
enterprises included in the summarized financial information were
owned by Holdings as of those dates or for those years, they all were
owned (directly or indirectly) by Sempra Energy or by one of its
predecessor companies (Pacific Enterprises and Enova Corporation) at
the dates and for the periods for which they are included, and they
all are currently owned (directly or indirectly) by Holdings.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
SEMPRA ENERGY
(Registrant)
Date: May 5, 1999 By: /S/F.H. AULT
---------------- ---------------------------
F. H. Ault
Vice President and Controller
EXHIBIT 23.1
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration
Statement Number 333-51309 on Form S-3 and Registration Statement
Number 333-56161 on Form S-8 of Sempra Energy of our report dated
January 27, 1999, except for Note 16 as to which the date is February
22, 1999 on the Supplemental Schedule of Summarized Financial
Information appearing in this Current Report on Form 8-K dated May 5,
1999.
/S/ DELOITTE & TOUCHE LLP
San Diego, California
May 5, 1999
