EXHIBIT 13.01
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
This section includes management's analysis of operating results
from 1996 through 1998, and is intended to provide information
about the capital resources, liquidity and financial performance of
Sempra Energy and its subsidiaries (the company). This section also
focuses on the major factors expected to influence future operating
results and discusses investment and financing plans. It should be
read in conjunction with the consolidated financial statements
included in this Annual Report.
The company is a California-based Fortune 500 energy-services
company whose principal subsidiaries are San Diego Gas & Electric
(SDG&E), which provides electric and natural gas service to San
Diego County and southern Orange County, and Southern California
Gas Company (SoCalGas), the nation's largest natural gas
distribution utility, serving 4.8 million meters throughout most of
southern California and part of central California. Together, the
two utilities serve approximately 7 million meters. Sempra Energy
Trading is engaged in the wholesale trading and marketing of
natural gas, power and petroleum. Sempra Energy Solutions is
engaged in the buying and selling of natural gas for large users,
integrated energy-management services targeted at large
governmental and commercial facilities, and consumer-market
products and services. Sempra Energy Financial invests in limited
partnerships representing 1,250 affordable-housing properties
throughout the United States. Through other subsidiaries, the
company owns and operates interstate and offshore natural gas
pipelines and centralized heating and cooling for large building
complexes, and is involved in domestic and international energy-
utility operations, nonutility electric generation and other
energy-related products and services.
BUSINESS COMBINATIONS
Sempra Energy was formed to serve as a holding company for Pacific
Enterprises (the parent corporation of the Southern California Gas
Company) and Enova Corporation (the parent corporation of San Diego
Gas & Electric Company) in connection with a business combination
that became effective on June 26, 1998 (the PE/Enova Business
Combination). In January 1998, PE and Enova jointly acquired
CES/Way International, Inc. Expenses incurred in connection with
these business combinations are $85 million, aftertax, and $20
million, aftertax, for the years ended December 31, 1998 and 1997,
respectively. These costs consist primarily of employee-related
costs, and investment banking, legal, regulatory and consulting
fees.
In connection with the PE/Enova Business Combination, the
holders of common stock of PE and Enova became the holders of the
company's common stock. PE's common shareholders received 1.5038
shares of the company's common stock for each share of PE common
stock, and Enova's common shareholders received one share of the
company's common stock for each share of Enova common stock. The
preferred stock of PE remained outstanding. The combination was
approved by the shareholders of both companies on March 11, 1997,
and was a tax-free transaction. The Consolidated Financial
Statements of the company gave effect to the combination using the
pooling-of-interests method and are preserved as if the companies
were combined during all periods included therein.
CAPITAL RESOURCES AND LIQUIDITY
The company's utility operations continue to be a major source of
liquidity. In addition, working capital requirements are met
primarily through the issuance of short- and long-term debt. Cash
requirements primarily include capital investments in the utility
operations. Nonutility cash requirements include investments in
Sempra Energy Resources, Sempra Energy Utility Ventures, Sempra
Energy Solutions, Sempra Energy Trading, CES/Way International, and
other domestic and international ventures.
Additional information on sources and uses of cash during the
last three years is summarized in the following condensed statement
of consolidated cash flows:
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SOURCES AND (USES) OF CASH
Year Ended December 31
(Dollars in millions) 1998 1997 1996
- ------------------------------------------------------------
Operating Activities $1,323 $918 $1,164
-------------------------
Investing Activities:
Capital expenditures (438) (397) (413)
Acquisitions of subsidiaries (191) (206) (50)
Other (50) 1 (51)
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Total Investing Activities (679) (602) (514)
-------------------------
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)
Long-term debt-net (356) 382 (155)
Short-term debt-net (311) 92 29
-------------------------
Total Financing Activities (1,034) 68 (667)
-------------------------
Increase (decrease) in cash
and cash equivalents $(390) $384 $(17)
- ------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
The increase in cash flows from operating activities in 1998 was
primarily due to lower working-capital requirements for natural gas
operations in 1998. This was caused by higher throughput compared
to 1997, combined with natural gas costs that were lower than
amounts being collected in rates, which resulted in overcollected
regulatory balancing accounts at year-end 1998. This increase was
partially offset by expenses incurred in connection with the
business combinations. The fluctuation in cash flows from
operations was also affected by electric-industry restructuring,
including the acceleration of depreciation of electric-generating
assets, offset by recovery of stranded costs via the competition
transition charge and the 10-percent rate reduction reflected in
customers' bills in 1998.
The decrease in cash flows from operating activities in 1997
was primarily due to greater working-capital requirements for
natural gas operations in 1997. This was caused by natural gas
costs being higher than amounts collected in rates, resulting in
undercollected regulatory balancing accounts at year-end 1997. The
cash flow from electric operations for 1997 was consistent with
results from 1996.
CASH FLOWS FROM INVESTING ACTIVITIES
Cash flows from investing activities primarily represent capital
expenditures and investments in new businesses.
Capital Expenditures
Capital expenditures were $41 million higher in 1998 than in 1997
due to greater capital spending at the company's corporate center
related to facility improvements and equipment purchases, and at
SDG&E related to industry-restructuring needs and improvements to
the electric distribution system, partially offset by lower capital
spending at SoCalGas.
Capital expenditures were $16 million lower in 1997 than in
1996 due to changes in the scope and timing of several major
capital projects primarily related to information systems. SoCalGas
had lower capital spending related to the customer information
system's being completed in early 1996 and other nonrecurring
computer system expenditures in 1996. The decrease was partially
offset by higher capital expenditures related to the purchase of a
data processing facility and a plant expansion at a non-utility
subsidiary. SDG&E's capital expenditures were lower due to changes
in scope and timing of several major capital projects.
At SDG&E, payments to the nuclear-decommissioning trusts are
expected to continue until San Onofre Nuclear Generating Station
(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,
SDG&E and the other owners of SONGS have requested that the CPUC
grant authority to begin decommisioning Unit 1 on January 1, 2000.
See Note 6 of the notes to the Consolidated Financial Statements
for additional information.
The decision of the CPUC approving the PE/Enova Business
Combination required, among other things, that SDG&E divest itself
of all its fossil fueled generation facilities. In December 1998,
SDG&E entered into agreements to accomplish that. Completion is
pending regulatory approvals and is expected during the first half
of 1999. See "Electric-Generation Assets" below for further
discussion of the divestiture. Anticipated proceeds from these
plant assets, net of the assets' book value, the costs of the sales
and certain environmental cleanup costs, will be applied for
accounting purposes directly to the recovery of SDG&E's other
transition costs. On a cash basis, the proceeds will be available
for general corporate purposes. However, the divestiture of the
facilities will eventually lead to reduced cash flow from
operations.
Capital expenditures at the utilities are estimated to be $419
million in 1999. They will be financed primarily by internally
generated funds and will largely represent investment in utility
operations. The level of capital expenditures in the next few years
will depend heavily on the impact of electric-industry
restructuring and the timing and extent of expenditures to comply
with environmental requirements.
Investments
In December 1997, PE and Enova jointly acquired Sempra Energy
Trading for $225 million. In July 1998, Sempra Energy Trading
purchased a subsidiary of Consolidated Natural Gas, a wholesale
trading and commercial marketing operation, for $36 million to
expand its operation in the eastern United States.
In December 1997, Sempra Energy Resources and Reliant Energy
Power Generation formed El Dorado Energy, a joint venture to build,
own and operate a natural gas power plant in Boulder City, Nevada.
Sempra Energy Resources invested $19.7 million and $2.3 million in
El Dorado Energy in 1998 and 1997, respectively. Total cost of the
project is projected to be $263 million. In October 1998, El Dorado
Energy obtained a 15-year, $158-million, senior secured credit
facility to finance the project. This financing represents
approximately 60 percent of the estimated total project costs.
In September 1997, Sempra Energy Utility Ventures formed a
joint venture with Bangor Hydro to build, own and operate a $40
million natural gas distribution system in Bangor, Maine. The
project is under construction and is expected to be operational in
the fourth quarter of 1999. In December 1997, Sempra Energy Utility
Ventures entered into a partnership with Frontier Utilities of
North Carolina to build and operate a $55 million natural gas
distribution system in North Carolina. Gas delivery began in
December 1998. Subsequent to December 31, 1998, Sempra Energy
Utilities Ventures acquired 100 percent ownership of the system.
In May 1997, Sempra Energy Solutions, together with Conectiv
Thermal Systems, Inc., formed two joint ventures to provide
integrated energy management services to commercial and industrial
customers. Specific projects of these joint ventures are described
in Note 3 of the notes to Consolidated Financial Statements.
As noted above, Sempra Energy Solutions acquired CES/Way
International, Inc. (CES/Way) in 1998. CES/Way provides energy-
efficiency services, including energy audits, engineering design,
project management, construction, financing and contract
maintenance.
In March 1998, the company increased its existing investment
in two Argentine natural gas utility holding companies from 12.5
percent to 21.5 percent by purchasing an additional interest for
$40 million.
Fluctuations in Sempra Energy's level of investments in the
next few years will depend primarily on the activities of its
subsidiaries other than SoCalGas and SDG&E.
CASH FLOWS FROM FINANCING ACTIVITIES
Net cash used in financing activities increased in 1998 due to
greater short- and long-term debt repayments and the redemption of
preferred stock in 1998, and the issuance of rate-reduction bonds
in 1997, partially offset by the repurchase of common stock in
1997.
Net cash was provided by financing activities in 1997 compared
to net cash being used in 1996 due to the issuance of rate
reduction bonds and lower repayments of long-term debt in 1997, and
the redemption of preferred stock in 1996, partially offset by the
redemption of common stock in 1997.
Long-Term Debt
In December 1997, $658 million of Rate Reduction Bonds were issued
on SDG&E's behalf at an average interest rate of 6.26 percent. A
portion of the bond proceeds was used to retire variable-rate,
taxable Industrial Development Bonds (IDBs). Additional information
concerning the Rate Reduction Bonds is provided below under
"Electric Industry Restructuring." In 1998, cash was used for the
repayment of $247 million of first-mortgage bonds, and $66 million
of rate-reduction bonds. Short-term debt repayments included
repayment of $94 million of debt issued to finance SoCalGas'
Comprehensive Settlement as discussed in Note 14 of the notes to
Consolidated Financial Statements.
In 1997, cash was used for the repayment of $96 million of
debt issued to finance the Comprehensive Settlement and repayment
of $252 million of SoCalGas' first-mortgage bonds. This was
partially offset by the issuance of $120 million in medium-term
notes and short-term borrowings used to finance working capital
requirements at SoCalGas.
SDG&E has $83 million of temporary investments that will be
maintained into the future to offset, for regulatory purposes, a
like amount of long-term debt. The specific debt series being
offset consists of variable-rate IDBs. The CPUC has approved
specific ratemaking treatment which allows SDG&E to offset IDBs as
long as there is at least a like amount of temporary investments.
If and when SDG&E requires all or a portion of the $83 million of
IDBs to meet future needs for long-term debt, such as to finance
new construction, the amount of investments which are being
maintained will be reduced below $83 million and the level of IDBs
being offset will be reduced by the same amount.
Stock Purchases and Redemptions
The company, through PE and Enova, repurchased $1 million, $122
million and $24 million of common stock in 1998, 1997 and 1996,
respectively. The stock repurchase programs of PE and Enova were
suspended as a result of the PE/Enova Business Combination. Sempra
Energy does not have a stock-repurchase program.
On February 2, 1998, SoCalGas redeemed all outstanding shares
of its 7 3/4% Series Preferred Stock at a cost of $25.09 per share,
or $75.3 million including accrued dividends.
Dividends
Dividends paid on common stock amounted to $325 million in 1998,
compared to approximately $300 million in 1997 and 1996. The
increase in 1998 is the result of the company's paying dividends on
its common stock at the rate previously paid by Enova, which, on an
equivalent-share basis, is higher than the rate paid by PE.
Dividends are paid quarterly to shareholders. The payment of
future dividends and the amount thereof are within the discretion
of the board of directors.
CAPITALIZATION
The debt to capitalization ratio was 50 percent at year-end 1998,
below the 54 percent ratio in 1997. The decrease was primarily due
to the repayment of debt. The debt to capitalization ratio
increased to 54 percent in 1997 from 50 percent in 1996, primarily
due to the issuance of SDG&E's Rate Reduction Bonds.
CASH AND CASH EQUIVALENTS
Cash and cash equivalents were $424 million at December 31, 1998.
This cash is available for investment in energy-related domestic
and international projects, and the retirement of debt and other
corporate purposes.
The company anticipates that cash required in 1999 for capital
expenditures and dividend and debt payments will be provided by
cash generated from operating activities and existing cash
balances.
In addition to cash from ongoing operations, the company has
multiyear credit agreements that permit term borrowings of up to
$995 million, of which $43 million is outstanding at December 31,
1998. For further discussion, see Note 4 of the notes to
Consolidated Financial Statements.
RESULTS OF OPERATIONS
1998 Compared to 1997
Net income for 1998 decreased to $294 million, or $1.24 per share
of common stock (diluted) in 1998, compared to net income of $432
million, or $1.82 per share of common stock (diluted) in 1997.
The decrease in net income is primarily due to the costs
associated with the business combinations, and a lower base margin
established at SoCalGas in its Performance Based Regulation
decision (SoCalGas PBR Decision) which became effective on August
1, 1997, as further described in Note 14 of the notes to
Consolidated Financial Statements. Expenses related to the business
combinations were $85 million ($0.36 per share) and $20 million
($0.08 per share), aftertax, for 1998 and 1997, respectively.
Also contributing to lower net income for 1998 were
significant start-up costs at Sempra Energy Solutions and at Sempra
Energy Trading as discussed under "Other Operations" below.
For the fourth quarter, net income decreased compared to the
prior fourth quarter due to PBR and Demand-Side Management awards
in the 1997 quarter, electric seasonality effects compared to 1997,
and the factors that affected the annual comparison.
Book value per share decreased to $12.29 from $12.56, due to
common dividends' exceeding the decreased net income in 1998.
1997 Compared to 1996
Net income for 1997 increased to $432 million, or $1.82 per share
of common stock (diluted), compared to net income of $427 million,
or $1.77 per share (diluted), in 1996. The increase in net income
per share is due primarily to the repurchases of common stock,
which caused the weighted average number of shares of common stock
outstanding to decrease 2 percent in 1997. The increase in net
income is primarily due to increased net income from utility
operations, partially offset by costs related to the PE/Enova
Business Combination and the start-up of unregulated operations.
Book value per share increased to $12.56 from $12.21, due to
net income's exceeding the combined effect of common dividends and
the stock repurchases.
UTILITY OPERATIONS
To understand the operations and financial results of SoCalGas and
SDG&E, it is important to understand the ratemaking procedures that
SoCalGas and SDG&E follow.
SoCalGas and SDG&E are regulated by the CPUC. It is the
responsibility of the CPUC to determine that utilities operate in
the best interests of their customers and have the opportunity to
earn a reasonable return on investment. In response to utility-
industry restructuring, SoCalGas and SDG&E have received approval
from the CPUC for PBR.
PBR replaces the general rate case (GRC) procedure and certain
other regulatory proceedings. Under ratemaking procedures in effect
prior to PBR, SoCalGas and SDG&E typically filed a GRC with the
CPUC every three years. In a GRC, the CPUC establishes a base
margin, which is the amount of revenue to be collected from
customers to recover authorized operating expenses (other than the
cost of fuel, natural gas and purchased power), depreciation, taxes
and return on rate base.
Under PBR, regulators allow income potential to be tied to
achieving or exceeding specific performance and productivity
measures, rather than relying solely on expanding utility rate base
in a market where a utility already has a highly developed
infrastructure. See additional discussion of PBR in Note 14 of the
notes to Consolidated Financial Statements.
In September 1996, California enacted a law restructuring
California's electric-utility industry. The legislation adopted the
December 1995 CPUC policy decision restructuring the industry to
stimulate competition and reduce rates. Beginning on March 31,
1998, customers were able to buy their electricity through the
California Power Exchange (PX) that obtains power from qualifying
facilities, nuclear units and, lastly, from the lowest-bidding
suppliers. The PX serves as a wholesale power pool, allowing all
energy producers to participate competitively.
The natural gas industry experienced an initial phase of
restructuring during the 1980s by deregulating natural gas sales to
noncore customers. In January 1998, the CPUC initiated 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.
See additional discussion of electric-industry and natural
gas-industry restructuring below in "Electric-Industry
Restructuring" and "Gas-Industry Restructuring" and in Note 14 of
the notes to Consolidated Financial Statements.
The table below summarizes the components of utility natural
gas and electric volumes and revenues by customer class for 1998,
1997 and 1996.
GAS SALES, TRANSPORTATION & EXCHANGE
(Dollars in millions, volumes in billion cubic feet)
Gas Sales Transportation & Exchange Total
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Throughput Revenue Throughput Revenue Throughput Revenue
-----------------------------------------------------------------------
1998:
Residential 304 $2,234 3 $11 307 $2,245
Commercial and Industrial 102 571 329 277 431 848
Utility Electric Generation* 57 9 139 66 196 75
Wholesale 28 7 28 7
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463 $2,814 499 $361 962 3,175
Balancing accounts and other (403)
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Total $2,772
- ---------------------------------------------------------------------------------------------
1997:
Residential 268 $1,957 3 $10 271 $1,967
Commercial and Industrial 102 617 332 273 434 890
Utility Electric Generation* 49 14 158 76 207 90
Wholesale 18 12 18 12
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419 $2,588 511 $371 930 2,959
Balancing accounts and other 5
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Total $2,964
- ---------------------------------------------------------------------------------------------
1996:
Residential 264 $1,809 3 $10 267 $1,819
Commercial and Industrial 104 573 314 257 418 830
Utility Electric Generation* 43 9 139 70 182 79
Wholesale 17 10 17 10
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411 $2,391 473 $347 884 2,738
Balancing accounts and other (28)
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Total $2,710
- ---------------------------------------------------------------------------------------------
* The portion representing SDG&E's sales for electric generation includes margin only.
ELECTRIC DISTRIBUTION
(Dollars in millions, volumes in millions of Kwhrs)
1998 1997 1996
-----------------------------------------------------------------------
Volumes Revenue Volumes Revenue Volumes Revenue
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Residential 6,282 $637 6,125 $684 5,936 $647
Commercial 6,821 643 6,940 680 6,467 625
Industrial 3,097 233 3,607 268 3,567 261
Direct access 964 44 - - - -
Street and highway lighting 85 8 76 7 75 7
Off-system sales 706 15 4,919 116 650 13
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17,955 1,580 21,667 1,755 16,695 1,553
Balancing and other 285 14 38
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Total 17,955 $1,865 21,667 $1,769 16,695 $1,591
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1998 Compared to 1997
Utility natural gas revenues decreased 6 percent in 1998 primarily
due to the lower natural gas margin established in the SoCalGas PBR
Decision, a decrease in the average cost of natural gas and a
decrease in sales to utility electric-generation customers,
partially offset by increased sales to residential customers due to
colder weather in 1998.
Electric revenues increased 5 percent in 1998 compared to
1997, primarily due to the recovery of stranded costs via the
competition transition charge (CTC), and to alternate costs
incurred (including fuel and purchased power) due to the delay from
January 1 to March 31, 1998, in the start-up of operations of the
PX and Independent System Operator (ISO). These factors were
partially offset by a decrease in retail revenue as a result of the
10-percent small customer rate reduction, which became effective in
January 1998, and by a decrease in sales to other utilities, due to
the start-up of the PX. The 10-percent rate reduction and PX are
described further under "Factors Influencing Future Performance"
and in Note 14 of the notes to Consolidated Financial Statements.
Revenues from the ISO/PX reflect sales from the company's
power plants and from long-term purchased-power contracts to the
ISO/PX commencing April 1, 1998.
The company's cost of natural gas distributed decreased 18
percent in 1998, largely due to a decrease in the average cost of
natural gas purchased, partially offset by increases in sales
volume.
Purchased power decreased 34 percent in 1998 primarily as a
result of ISO/PX purchases' replacing short-term energy sources
commencing April 1, 1998.
Depreciation and amortization expense increased 54 percent in
1998, primarily due to the recovery of stranded costs via the CTC.
The earnings impact of the increase is offset by CTC revenue (see
above).
Operating expenses increased 16 percent in 1998, primarily due
to the higher business-combination costs ($142 million in 1998,
compared to $30 million in 1997) and additional operating expenses
due to start-up operations in 1998, including the acquisitions of
Sempra Energy Trading and CES/Way.
1997 Compared to 1996
Utility natural gas revenues increased 9 percent in 1997 primarily
due to an increase in the average unit cost of natural gas, which
is recoverable in rates. To a lesser extent, the increase was due
to increased throughput to utility electric-generation customers
due to increased demand for electricity. The increase was partially
offset by an increase in customer purchases of natural gas directly
from other suppliers.
Utility electric revenues increased 11 percent in 1997,
primarily due to an increase in sales for resale to other utilities
and increased retail sales volume due to weather.
Utility cost of natural gas distributed increased 22 percent
in 1997, largely due to an increase in the average cost of natural
gas purchased and increases in sales volume.
Purchased power increased 42 percent in 1997, primarily due to
increased volume, which resulted from lower nuclear-generation
availability due to refuelings at SONGS and increased use of
purchased power due to decreased purchased-power prices.
Operating expenses increased 15 percent in 1997, primarily due
to the startup of unregulated operations, partially offset by lower
utility operating expenses. The extent of this offset was lessened
by reduced costs in 1996 from favorable litigation settlements.
FACTORS INFLUENCING FUTURE PERFORMANCE
Performance of the company in the near future will depend primarily
on the results of SDG&E and SoCalGas. Because of the ratemaking and
regulatory process, electric- and natural gas-industry
restructuring, and the changing energy marketplace, there are
several factors that will influence future financial performance.
These factors are summarized below.
KN Energy Acquisition
On February 22, 1999, the company announced a definitive agreement
to acquire KN Energy, Inc., subject to approval by the shareholders
of both companies and by various regulatory agencies. See Note 16
of the notes to Consolidated Financial Statements for additional
information.
Electric-Industry Restructuring
As discussed above, in September 1996, California enacted a law
restructuring California's electric-utility industry (AB 1890).
Consumers now have 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 PX that
serves as a wholesale power pool allowing all energy producers to
participate competitively. The local utility continues to provide
distribution service regardless of which source the consumer
chooses. See Note 14 of the notes to Consolidated Financial
Statements for additional information.
Transition Costs
AB 1890 allows utilities, within certain limits, the opportunity to
recover their stranded costs incurred for certain above-market
CPUC-approved facilities, contracts and obligations through the
establishment of the CTC.
Utilities are allowed a reasonable opportunity to recover
their stranded costs 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
accrued under traditional cost-of-service regulation.
Through December 31, 1998, SDG&E has recovered transition
costs of $500 million for nuclear generation and $200 million for
nonnuclear 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. During
the 1998-2001 period, recovery of transition costs is limited by a
rate cap. See Note 14 of the notes to Consolidated Financial
Statements for additional information.
Electric-Generation Assets
In November 1997, SDG&E adopted a plan to auction its power plants
and other electric-generating assets so that it could continue to
concentrate its business on the transmission and distribution of
electricity and natural gas as California opens its electric-
utility industry to competition. This plan included the divestiture
of SDG&E's fossil-fueled 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).
The March 1998 decision of the CPUC approving the PE/Enova
Business Combination required, among other things, the divestiture
by SDG&E of its fossil-fueled generation units. On December 11,
1998, SDG&E entered into agreements for the sale of its South Bay
Power Plant, Encina Power Plant and 17 combustion-turbine
generators. The sales are subject to regulatory approval and are
expected to close during the first half of 1999. See Note 14 of the
notes to Consolidated Financial Statements for additional
information.
As mentioned above, Sempra Energy Resources and Reliant Energy
Power Generation formed a joint venture to build, own and operate a
natural gas power plant (El Dorado) in Boulder City, Nevada. The
joint venture plans to sell the plant's electricity into the
wholesale market, which, in turn, sells to utilities throughout the
Western United States. The new plant will employ an advanced
combined-cycle gas-turbine technology, enabling it to become one of
the most efficient and environmentally friendly power plants in the
nation. Its proximity to existing natural gas pipelines and
electric transmission lines will allow El Dorado to actively
compete in the deregulated electric-generation market. The project,
funded equally by the company and Reliant, began in the first
quarter of 1998, with an expected operational date set for the
fourth quarter of 1999.
Electric Rates
AB 1890 provides for a 10-percent reduction in rates for
residential and small commercial customers effective in January
1998, and provided for the issuance of rate-reduction bonds by an
agency of the State of California to enable its investor-owned
utilities (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 electricity bills. In
September 1997, SDG&E and the other California IOUs received a
favorable ruling by the Internal Revenue Service on the tax
treatment of the bond transaction. The ruling states, among other
things, that the receipt of the bond proceeds does not result in
gross income to SDG&E at the time of issuance, but rather the
proceeds are taxable over the life of the bonds. The Securities and
Exchange Commission determined that these bonds should be reflected
on the utilities' balance sheets as debt, even though the bonds are
not secured by, or payable from, utility assets, but rather by the
future revenue streams collected from customers. SDG&E formed a
subsidiary, SDG&E Funding LLC, to facilitate the issuance of the
rate-reduction bonds. In exchange for the bond proceeds, SDG&E sold
to SDG&E Funding LLC all of its rights to the revenue streams.
Consequently, the revenue streams are not the property of SDG&E and
are not available to creditors of SDG&E.
AB 1890 also included a rate freeze for all customers. Until
the earlier of March 31, 2002, or when transition-cost recovery is
complete, SDG&E's average system rate will be held at 9.64 cents
per kilowatt-hour, except for the impacts 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. SDG&E's ability to
recover its transition costs is dependent on its total revenues
under the rate freeze exceeding traditional cost-of-service
revenues during the transition period by at least the amount of the
CTC less the net proceeds from the sale of electric-generating
assets. During the transition period, SDG&E will not earn awards
from special programs, such as Demand-Side Management, unless total
revenues are also adequate to cover the awards. Fuel-price
volatility is one of the more significant uncertainties in the
ability of SDG&E to recover its transition costs and program
awards.
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.
Performance-Based Regulation
As discussed above, under PBR, regulators allow future income
potential to be tied to achieving or exceeding specific performance
and productivity measures, as well as cost reductions, rather than
by relying solely on expanding utility rate base. See additional
discussion of PBR in Note 14 of the notes to Consolidated Financial
Statements.
Regulatory Accounting Standards
SoCalGas and SDG&E are accounting for the economic effects of
regulation on all of their utility operations, except for electric
generation, in accordance with Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain
Types of Regulation." Under SFAS No. 71, a regulated entity records
a regulatory asset if it is probable that, through the rate-making
process, the utility will recover the asset from customers.
Regulatory liabilities represent future reductions in revenues for
amounts due to customers. See Notes 2 and 14 of the notes to
Consolidated Financial Statements for additional information.
Affiliate Transactions
On December 16, 1997, the CPUC adopted rules establishing uniform
standards of conduct governing the manner in which California IOUs
conduct business with their affiliates. The objective of these
rules, which became effective January 1, 1998, is to ensure that
the utilities' energy affiliates do not gain an unfair advantage
over other competitors in the marketplace and that utility
customers do not subsidize affiliate 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 PE/Enova Business Combination. As
a result, the affiliate-transaction rules will not substantially
impact the company's ability to achieve anticipated synergy
savings. See Notes 1 and 14 of the notes to Consolidated Financial
Statements for additional information.
Allowed Rate of Return
For 1998, SoCalGas was authorized to earn a rate of return on rate
base of 9.49 percent and a rate of return on common equity of 11.6
percent, which is unchanged from 1997. SDG&E was authorized to earn
a rate of return on rate base of 9.35 percent and a rate of return
on common equity of 11.6 percent, unchanged from 1997. See
additional discussion in Note 14 of the notes to Consolidated
Financial Statements.
Management Control of Expenses and Investment
In the past, management has been able to control operating expenses
and investment within the amounts authorized to be collected in
rates.
It is the intent of management to control operating expenses
and investments within the amounts authorized to be collected in
rates in the PBR decision. The utilities intend to make the
efficiency improvements, changes in operations and cost reductions
necessary to achieve this objective and earn their authorized rates
of return. However, in view of the earnings-sharing mechanism and
other elements of the PBR, it is more difficult to exceed
authorized returns to the degree experienced in past years. See
additional discussion of PBR in Note 14 of the notes to
Consolidated Financial Statements.
Gas-Industry Restructuring
The natural gas industry experienced an initial phase of
restructuring during the 1980s by deregulating natural gas sales to
noncore customers. On January 21, 1998, the CPUC initiated 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 enacted a law
prohibiting the CPUC from enacting any natural gas-industry
restructuring decision for core customers prior to January 1, 2000.
The CPUC continues to study the issue.
Noncore Bypass
SoCalGas' throughput to enhanced oil recovery (EOR) customers in
the Kern County area has decreased significantly since 1992 because
of the bypass of SoCalGas' system by competing interstate
pipelines. The decrease in revenues from EOR customers has not had
a material impact on SoCalGas' earnings.
Bypass of other markets also may occur, and SoCalGas is fully
at risk for a reduction in non-EOR, noncore volumes due to bypass.
However, significant additional bypass would require construction
of additional facilities by competing pipelines. SoCalGas is
continuing to reduce its costs to maintain cost competitiveness in
order to retain transportation customers.
Noncore Pricing
To respond to bypass, SoCalGas has received authorization from the
CPUC for expedited review of long-term gas-transportation service
contracts with some noncore customers at lower-than-tariff rates.
In addition, the CPUC approved changes in the methodology that
eliminates subsidization of core-customer rates by noncore
customers. This allocation flexibility, together with negotiating
authority, has enabled SoCalGas to better compete with new
interstate pipelines for noncore customers.
Noncore Throughput
SoCalGas' earnings may be adversely impacted if natural gas
throughput to its noncore customers varies from estimates adopted
by the CPUC in establishing rates. There is a continuing risk that
an unfavorable variance in noncore volumes may result from external
factors such as weather, electric deregulation, the increased use
of hydroelectric power, competing pipeline bypass of SoCalGas'
system and a downturn in general economic conditions. In addition,
many noncore customers are especially sensitive to the price
relationship between natural gas and alternate fuels, as they are
capable of readily switching from one fuel to another, subject to
air-quality regulations. SoCalGas is at risk for the lost revenue.
Through July 31, 1999, any favorable earnings effect of higher
revenues resulting from higher throughput to noncore customers has
been limited as a result of the Comprehensive Settlement discussed
in Note 14 of the notes to Consolidated Financial Statements.
Excess Interstate Pipeline Capacity
Existing interstate pipeline capacity into California exceeds
current demand by over one billion cubic feet (Bcf) per day. This
situation has reduced the market value of the capacity well below
the Federal Energy Regulatory Commission's (FERC) tariffs. SoCalGas
has exercised its step-down option on both the El Paso and
Transwestern systems, thereby reducing its firm interstate capacity
obligation from 2.25 Bcf per day to 1.45 Bcf per day.
FERC-approved settlements have resulted in a reduction in the
costs that SoCalGas possibly may have been required to pay for the
capacity released back to El Paso and Transwestern that cannot be
remarketed. Of the remaining 1.45 Bcf per day of capacity,
SoCalGas' core customers use 1.05 Bcf per day at the full FERC
tariff rate. The remaining 0.4 Bcf per day of capacity is marketed
at significant discounts. Under existing California regulation,
unsubscribed capacity costs associated with the remaining 0.4 Bcf
per day are recoverable in customer rates. While including the
unsubscribed pipeline cost in rates may impact SoCalGas' ability to
compete in highly contested markets, SoCalGas does not believe its
inclusion will have a significant impact on volumes transported or
sold.
ENVIRONMENTAL MATTERS
The company's operations are conducted in accordance with
applicable federal, state and local environmental laws and
regulations governing such things as hazardous wastes, air and
water quality, and the protection of wildlife.
These costs of compliance are normally recovered in customer
rates. Whereas it is anticipated that the environmental costs
associated with natural gas operations and with electric
transmission and generation operations will continue to be
recoverable in rates, the restructuring of the California electric-
utility industry, described above under "Electric Industry
Restructuring," will change the way utility rates are set and costs
associated with electric generation are recovered. Capital costs
related to environmental regulatory compliance for electric
generation are intended to be included in transition costs for
recovery through 2001. However, depending on the final outcome of
industry restructuring and the impact of competition, the costs of
future compliance with environmental regulations may not be fully
recoverable.
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 projected expenditures primarily consist of
the estimated cost of reducing air emissions by retrofitting power
plants. This estimate anticipates that SDG&E completes the planned
sale of its fossil-fueled power plants during the first half of
1999. Additional information on SDG&E's divestiture of its
electric-generating assets is discussed above under "Electric
Generation Assets" and in Note 14 of the notes to Consolidated
Financial Statements.
Hazardous Substances
In 1994, the CPUC approved the Hazardous Waste Collaborative, a
mechanism which allows SoCalGas, SDG&E and other utilities to
recover, through rates, costs associated with the cleanup of sites
contaminated with hazardous waste. In general, utilities are
allowed to recover 90 percent of their cleanup costs and any
related costs of litigation through rates. In early 1998, the CPUC
modified this mechanism to exclude these costs related to electric-
generation activities. These costs are now eligible for inclusion
in the Competition Transition Cost (CTC) recovery process described
above.
During the early 1900s, SDG&E, SoCalGas and their predecessors
manufactured gas from coal or oil, the sites of which have often
become contaminated with the hazardous residual by-products of the
process. SDG&E has identified three former manufactured-gas plant
sites. One of these sites has been remediated and a site-closure
letter has been received from the San Diego County Department of
Environmental Health. An environmental site assessment has been
conducted and the estimated cost to remediate the other two sites
is $6 million. SoCalGas has identified 42 former manufactured-gas
plant sites at which it (together with other utilities of these
sites) may have clean up obligations. As of December 31, 1998, 12
of these sites have been remediated and a certificate of closure
has been received from the California Environmental Protection
Agency for 10 of the sites. A preliminary environmental site
assessment has been conducted on 39 of the sites and it is
estimated that the cost for the remaining sites is $68 million. In
addition, other company subsidiaries have been named as potentially
responsible parties (PRPs) in relation to two landfills and three
industrial waste disposal sites, and it is estimated that the
subsidiaries' share of the costs to remediate such sites is $5
million. Ninety percent of SoCalGas' and SDG&E's costs to clean up
the gas plants and to meet their PRP obligations, a total estimated
to be $75 million, is recoverable through the Hazardous Waste
Collaborative mechanism.
As a part of its sale of the South Bay and Encina power plants
and 17 combustion turbines (described above), SDG&E retained
limited remediation obligations for contamination existing on these
sites upon the closing of the sales. SDG&E's costs to perform its
remediation obligations as a part of such sales is estimated to be
$10 million. These costs are eligible for inclusion in the CTC
recovery process.
Air and Water Quality
California's air quality standards are more restrictive than
federal standards. However, due to the sale of the electric-
generating power plants, the company's primary air-quality issue
compliance with these standards will be less significant in the
future.
In connection with the issuance of operating permits, SDG&E
and the other owners of SONGS reached agreement with the California
Coastal Commission to mitigate the environmental damage to the
marine environment attributed to the cooling-water discharge from
SONGS Units 2 and 3. This mitigation program includes an enhanced
fish-protection system, a 150-acre artificial reef and restoration
of 150 acres of coastal wetlands. In addition, the owners must
deposit $3.6 million with the state for the enhancement of marine
fish hatchery programs and pay for monitoring and oversight of the
mitigation projects. SDG&E's share of the cost is estimated to be
$23 million. The pricing structure contained in the CPUC's decision
regarding accelerated recovery of SONGS Units 2 and 3 is expected
to accommodate most of these added mitigation costs.
The environmental laws and regulations regarding natural gas
affect the operations of customers as well as the company's
regulated natural gas entities. Increasingly complex administrative
and reporting requirements of environmental agencies applicable to
commercial and industrial customers utilizing natural gas are not
generally required of those using electricity. However, anticipated
advancements in natural gas technologies are expected to enable
natural gas equipment to remain competitive with alternate energy
sources.
The transmission and distribution of natural gas require the
operation of compressor stations, which are subject to increasingly
stringent air-quality standards. Costs to comply with these
standards are recovered in rates.
INTERNATIONAL OPERATIONS
Sempra Energy International (SEI) was formed in June 1998, merging
the international operations of PE and Enova. Prior to the business
combination, PE and Enova were already partners in two natural gas
distribution projects in Mexico. In addition, PE held an interest
in two natural gas utility holding companies in Argentina.
SEI develops, operates and invests in energy-infrastructure
systems and power-generation facilities outside the United States.
SEI has interests in natural gas transmission and distribution
projects in Mexico, Argentina and Uruguay and is pursuing projects
in other parts of Latin America and in Asia.
In March 1998, PE increased its existing investment in two
Argentine natural gas utility holding companies (Sodigas Pampeana
S.A. and Sodigas Sur S.A.) by purchasing an additional 9-percent
interest for $40 million. With this purchase, PE's interest in the
holding companies was increased to 21.5 percent. The distribution
companies serve 1.2 million customers in central and southern
Argentina, respectively, and have a combined sendout of 650 million
cubic feet per day.
SEI is part of a binational consortium named Distribuidora de
Gas Natural de Mexicali, S. de R.L. de C.V. (DGN-Mexicali), a
Mexican company that won the first license awarded to a private
company to build a natural gas distribution system in Mexico. On
August 20, 1997, DGN-Mexicali began to deliver natural gas to
customers in Mexicali, Baja California. DGN-Mexicali will invest up
to $25 million to provide service to 25,000 customers during the
first five years of operation. Proxima Gas, S.A. de C.V. (Proxima),
a group of prominent Mexican businesspeople, is the project
partner. SEI owns a 60-percent interest in the Mexicali project.
SEI also has partnered with Proxima to form Distribuidora de
Gas Natural de Chihuahua, S. de R.L. de C.V. (DGN-Chihuahua), which
distributes natural gas to the city of Chihuahua, Mexico and
surrounding areas. On July 9, 1997, DGN-Chihuahua assumed ownership
of a 16-mile transmission pipeline serving 20 industrial customers.
DGN-Chihuahua will invest nearly $50 million to provide service to
50,000 customers in the first five years of operation. SEI owns a
95-percent interest in DGN-Chihuahua.
On August 27, 1998, SEI was awarded a 10-year agreement by the
Mexican Federal Electric Commission to provide natural gas for the
Presidente Juarez 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
United States and construction of a 23-mile pipeline from the U.S.-
Mexico border to the plant. This pipeline will also serve other
customers in the region. In today's dollars, future revenues under
the contract could approach $1 billion.
In May 1998, PE was awarded a concession by the government of
Uruguay to build a natural gas and propane distribution system to
serve most of the country, excluding Montevideo. SEI is currently
in discussions with regards to the terms of the concession
agreement with the Uruguayan government.
The net losses for international operations were $4 million
and $9 million, aftertax, for 1998 and 1997, respectively.
OTHER OPERATIONS
Sempra Energy Trading (SET), a leading natural gas power marketing
firm headquartered in Stamford, Connecticut, was jointly acquired
by PE and Enova on December 31, 1997. For the year ended December
31, 1998, SET recorded aftertax income of $1 million from its
operations and a net loss of $13 million after amortization of
costs associated with the acquisition. Additional information
concerning SET is provided in Note 10 of the notes to Consolidated
Financial Statements.
Sempra Energy Solutions (Solutions), formed in 1997 as a joint
venture of PE and Enova, incorporates several existing unregulated
businesses from each of PE and Enova. It is pursuing a variety of
opportunities, including buying and selling natural gas for large
users, integrated energy-management services targeted at large
governmental and commercial facilities, and consumer-market
products and services such as earthquake shutoff valves. CES/Way
International, Inc. (CES/Way), which was acquired by Solutions in
January 1998, provides energy-efficiency services including energy
audits, engineering design, project management, construction,
financing and contract maintenance.
Solutions' operating losses were $27 million and $14 million,
aftertax, for the years ended December 31, 1998, and 1997,
respectively. The losses are primarily due to startup costs.
OTHER INCOME, INTEREST EXPENSE AND INCOME TAXES
Other Income
Other income, which primarily consists of interest income from
short-term investments and regulatory-balancing accounts, decreased
in 1998 to $44 million from $58 million in 1997. The decrease was a
result of lower interest income from short-term investments. The
increase to $58 million from $28 million in 1996 was due to higher
interest from short-term investments during much of 1997.
Interest Expense
Interest expense for 1998 increased slightly to $207 million from
$206 million in 1997. Interest expense for 1997 increased to $206
million from $200 million in 1996, as a result of a higher long-
term debt balance.
Income Taxes
Income tax expense for 1998 was $138 million, less than the $301
million for 1997. The effective income tax rate was 32 percent for
1998 and 41 percent for 1997. The decrease in income tax expense is
primarily due to the decrease in pretax income, combined with an
increase in affordable-housing tax credits.
DERIVATIVE FINANCIAL INSTRUMENTS
The company's policy is to use derivative financial instruments to
manage exposure to fluctuations in interest rates, foreign currency
exchange rates and energy prices. The company also uses and trades
derivative financial instruments in its energy trading and
marketing activities. Transactions involving these financial
instruments are with reputable firms and major exchanges. The use
of these instruments may expose the company to market and credit
risks. At times, credit risk may be concentrated with certain
counterparties, although counterparty nonperformance is not
anticipated.
Sempra Energy Trading derives a substantial portion of its
revenue from risk management and trading activities in natural gas,
petroleum and electricity. Profits are earned as SET acts as a
dealer in structuring and executing transactions that assist its
customers in managing their energy-price risk. In addition, SET
may, on a limited basis, take positions in energy markets based on
the expectation of future market conditions. These positions
include options, forwards, futures and swaps. See Note 10 of the
notes to Consolidated Financial Statements and the following
"Market Risk Management Activities" section for additional
information regarding SET's use of derivative financial
instruments.
The company's regulated operations periodically enter into
interest-rate swap and cap agreements to moderate exposure to
interest-rate changes and to lower the overall cost of borrowing.
These swap and cap agreements generally remain off the balance
sheet as they involve the exchange of fixed-rate and variable-rate
interest payments without the exchange of the underlying principal
amounts. The related gains or losses are reflected in the income
statement as part of interest expense. The company would be exposed
to interest-rate fluctuations on the underlying debt should other
parties to the agreement not perform. Such nonperformance is not
anticipated. At December 31, 1998, the notional amount of swap
transactions associated with the regulated operations totaled $45
million. See Note 5 of the notes to Consolidated Financial
Statements for further information regarding these swap
transactions.
The company's regulated operations use energy derivatives to
manage natural gas price risk associated with servicing their load
requirements. In addition, they make limited use of natural gas
derivatives for trading purposes. These instruments include forward
contracts, futures, swaps, options and other contracts, with
maturities ranging from 30 days to 12 months. In the case of both
price-risk management and trading activities, the use of derivative
financial instruments by the company's regulated operations is
subject to certain limitations imposed by established company
policy and regulatory requirements. See Note 10 of the notes to
Consolidated Financial Statements and the "Market Risk Management
Activities" section below for further information regarding the use
of energy derivatives by the company's regulated operations.
MARKET RISK MANAGEMENT ACTIVITIES
Market risk is the risk of erosion of the company's cash flows, net
income and asset values due to adverse changes in interest and
foreign-currency rates, and in prices for equity and energy. The
company has adopted corporate-wide policies governing its market-
risk management and trading activities. An Energy Risk Management
Oversight Committee, consisting of senior corporate officers,
oversees company-wide energy-price risk-management and trading
activities to ensure compliance with the company's stated energy
risk management and trading policies. In addition, all affiliates
have groups that monitor and control energy-price risk management
and trading activities independently from the groups responsible
for creating or actively managing these risks.
Along with other tools, the company uses Value at Risk (VaR)
to measure its exposure to market risk. VaR is an estimate of the
potential loss on a position or portfolio of positions over a
specified holding period, based on normal market conditions and
within a given statistical confidence level. The company has
adopted the variance/covariance methodology in its calculation of
VaR, and uses a 95 percent confidence level. Holding periods are
specific to the types of positions being measured, and are
determined based on the size of the position or portfolios, market
liquidity, tenor and other factors. Historical volatilities and
correlations between instruments and positions are used in the
calculation.
The following is a discussion of the company's primary market-
risk exposures as of December 31, 1998, including a discussion of
how these exposures are managed.
Interest-Rate Risk
The company is exposed to fluctuations in interest rates primarily
as a result of its fixed-rate long-term debt. The company has
historically funded utility operations through long-term bond
issues with fixed interest rates. With the restructuring of the
regulatory process, greater flexibility has been permitted within
the debt-management process. As a result, recent debt offerings
have been selected with short-term maturities to take advantage of
yield curves or used a combination of fixed- and floating-rate
debt. Interest-rate swaps, subject to regulatory constraints, may
be used to adjust interest-rate exposures when appropriate, based
upon market conditions.
A portion of the company's borrowings are denominated in
foreign currencies, which expose the company to market risk
associated with exchange-rate movements. The company's policy
generally is to hedge major foreign-currency cash exposures through
swap transactions. These contracts are entered into with major
international banks, thereby minimizing the risk of credit loss.
The VaR on the company's fixed rate long term debt is
estimated at approximately $312 million as of December 31, 1998,
assuming a one-year holding period. The VaR attributable to
currency exchange rates nets to zero as a result of a currency swap
that is directly matched to the company's Swiss Franc debt
obligation, its only non-dollar-denominated debt.
Energy-Price Risk
Market risk related to physical commodities is based upon potential
fluctuations in natural gas, petroleum and electricity commodity
exchange prices and basis. The company's market risk is impacted by
changes in volatility and liquidity in the markets in which these
instruments are traded. The company's regulated and unregulated
affiliates are exposed, in varying degrees, to price risk in the
natural gas, petroleum and electricity markets. The company's
policy is to manage this risk within a framework that considers the
unique markets, operating and regulatory environment of each
affiliate.
Sempra Energy Trading
Sempra Energy Trading derives a substantial portion of its revenue
from risk management and trading activities in natural gas,
petroleum and electricity. As such, SET is exposed to price
volatility in the domestic and international natural gas, petroleum
and electricity markets. SET conducts these activities within a
structured and disciplined risk management and control framework
that is based on clearly communicated policies and procedures,
position limits, active and ongoing management monitoring and
oversight, clearly defined roles and responsibilities, and daily
risk measurement and reporting.
Market risk of SET's portfolio is measured using a variety of
methods, including VaR. SET computes the VaR of its portfolio based
on a three-day holding period. As of December 31, 1998, the
diversified VaR of SET's portfolio was $5.3 million.
SDG&E
SDG&E is exposed to market risk in its natural gas purchase, sale
and storage activities whenever natural gas prices fall outside the
PBR tolerance band. SDG&E manages this risk within the parameters
of the company's market-risk management and trading framework. As
of December 31, 1998, the total VaR of SDG&E's natural gas
positions was not material.
SDG&E is exposed to market risk on its electricity purchases
and sales under the electricity rate cap. See Note 14 of the notes
to Consolidated Financial Statements and the discussion under
"Factors Influencing Future Performance" for further information
regarding the electricity rate cap.
SoCalGas
SoCalGas is exposed to market risk on its natural gas purchase,
sale and storage activities whenever natural gas prices fall
outside the Gas Cost Incentive Mechanism tolerance band. SoCalGas
manages this risk within the parameters of the company's market
risk management and trading framework. As of December 31, 1998, the
total VaR of SoCalGas' natural gas positions was not material.
Credit Risk
Credit risk relates to the risk of loss that would be incurred as a
result of nonperformance by counterparties pursuant to the terms of
their contractual obligations. The company avoids concentration of
counterparties and maintains credit policies with regard to
counterparties that management believes significantly minimize
overall credit risk. These policies include an evaluation of
potential counterparties' financial condition (including credit
rating), collateral requirements under certain circumstances, and
the use of standardized agreements that allow for the netting of
positive and negative exposures associated with a single
counterparty.
The company monitors credit risk through a credit-approval
process and the assignment and monitoring of credit limits. These
credit limits are established based on risk and return
considerations under terms customarily available in the industry.
YEAR 2000 ISSUES
Most companies are affected by the inability of many automated
systems and applications to process the year 2000 and beyond. The
Year 2000 issues are the result of computer programs and other
automated processes using two digits to identify a year, rather
than four digits. Any of the company's computer programs that
include date-sensitive software may recognize a date using "00" as
representing the year 1900, instead of the year 2000, or "01" as
1901, etc., which could lead to system malfunctions. The Year 2000
issues impact both Information Technology (IT) systems and also
non-IT systems, including systems incorporating "embedded
processors." To address this problem, in 1996, both Pacific
Enterprises and Enova Corporation established company-wide Year
2000 programs. These programs have now been consolidated into the
company's overall Year 2000 readiness effort. The company has
established a central Year 2000 Program Office, which reports to
the company's Chief Information Technology Officer and reports
periodically to the audit committee of the board of directors.
The Company's State of Readiness
Sempra Energy is identifying all IT and non-IT systems that might
not be Year 2000 ready and categorizing them in the following
areas: IT applications, computer hardware and software
infrastructure, telecommunications, embedded systems and third
parties. The company is currently evaluating its exposure in all of
these areas. These systems and applications are being tracked and
measured through four key phases: inventory, assessment,
remediation/testing, and Year 2000 readiness. Those applications
and systems, which, if not appropriately remediated, may have a
significant impact on energy delivery, revenue collection or the
safety of personnel, customers or facilities, are being assessed
and modified/replaced first. The testing effort includes functional
testing of Year 2000 dates and validating that changes have not
altered existing functionality. The company uses an independent,
internal-review process to verify that the appropriate testing has
occurred.
Inventory and assessment for all company systems were
completed by January 1999 and ongoing inventory and assessment will
be performed, as necessary, on any new applications. The project is
on schedule and the company estimates that by June 30, 1999, all
critical systems will be suitable for continued use into the year
2000 with no significant operational problems.
The company's current schedule for Year 2000 testing,
readiness and development of contingency plans is subject to change
depending upon the remediation and testing phases of the company's
compliance effort and upon developments that may arise as the
company continues to assess its computer-based systems and
operations. In addition, this schedule is dependent upon the
efforts of third parties, such as suppliers (including energy
producers) and customers. Accordingly, delays by third parties may
cause the company's schedule to change.
Costs to Address the Company's Year 2000 Issues
Sempra Energy's budget for the Year 2000 program is $48 million, of
which $38 million has been spent. As the company continues to
assess its systems and as the remediation and testing efforts
progress, cost estimates may change. The company's Year 2000
readiness effort is being funded entirely by operating cash flows.
The Risks of the Company's Year 2000 Issues
Based upon its current assessment and testing of the Year 2000
issue, the company believes the reasonably likely worst-case Year
2000 scenarios would have the following impacts upon Sempra Energy
and its operations. With respect to the company's ability to
provide energy to its domestic utility customers, the company
believes that the reasonably likely worst-case scenario is for
small, localized interruptions of natural gas or electrical service
which are restored in a timeframe that is within normal service
levels. With respect to services that are essential to Sempra
Energy's operations, such as customer service, business operations,
supplies and emergency response capabilities, the scenario is for
minor disruptions of essential services with rapid recovery and all
essential information and processes ultimately recovered.
To assist in preparing for and mitigating these possible
scenarios, Sempra Energy is a member of several industry-wide
efforts established to deal with Year 2000 problems affecting
embedded systems and equipment used by the nation's natural gas and
electric power companies. Under these efforts, participating
utilities are working together to assess specific vendors' system
problems and to test plans. These assessments will be shared by the
industry as a whole to facilitate Year 2000 problem solving.
A portion of this risk is due to the various Year 2000
schedules of critical third-party suppliers and customers. The
company is in the process of contacting its critical suppliers and
customers to survey their Year 2000 remediation programs. While
risks related to the lack of Year 2000 readiness by third parties
could materially and adversely affect the company's business,
results of operations and financial condition, the company expects
its Year 2000 readiness efforts to reduce significantly the
company's level of uncertainty about the impact of third party Year
2000 issues on both its IT systems and non-IT systems.
Company's Contingency Plans
Sempra Energy's contingency plans for interruptions related to Year
2000 issues are being incorporated in the company's existing
overall emergency preparedness plans. To the extent appropriate,
such plans will include emergency backup and recovery procedures,
remediation of existing systems parallel with installation of new
systems, replacing electronic applications with manual processes,
identification of alternate suppliers and increasing inventory
levels. The company expects these contingency plans to be completed
by June 30, 1999. Due to the speculative and uncertain nature of
contingency planning, there can be no assurances that such plans
actually will be sufficient to reduce the risk of material impacts
on the company's operations due to Year 2000 issues.
NEW ACCOUNTING STANDARDS
In April 1998, the American Institute of Certified Public
Accountants issued Statement of Position 98-5 "Reporting on the
Costs of Start-up Activities". This statement is effective for
1999, but is not expected to have a significant effect on the
company's Consolidated Financial Statements.
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.
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report includes forward-looking statements within the
definition of Section 27A of the Securities Act of 1933 and Section
21E of the Securities Exchange Act of 1934. The words "estimates,"
"believes," "expects," "anticipates," "plans" and "intends,"
variations of such words, and similar expressions, are intended to
identify forward-looking statements that involve risks and
uncertainties which could cause actual results to differ materially
from those anticipated. These statements are necessarily based upon
various assumptions involving judgments with respect to the future
including, among others, local, regional, national and
international economic, competitive, political and regulatory
conditions and developments, technological developments, capital
market conditions, inflation rates, interest rates, energy markets,
weather conditions, business and regulatory or legal decisions, the
pace of deregulation of retail natural gas and electricity
industries, the timing and success of business development efforts,
and other uncertainties, all of which are difficult to predict and
many of which are beyond the control of the company. Accordingly,
while the company believes that the assumptions are reasonable,
there can be no assurance that they will approximate actual
experience, or that the expectations will be realized. Readers are
urged to carefully review and consider the risks, uncertainties and
other factors which affect the company's business described in this
annual report and other reports filed by the company from time to
time with the Securities and Exchange Commission.
STATEMENT OF MANAGEMENT RESPONSIBILITY FOR
CONSOLIDATED FINANCIAL STATEMENTS
The consolidated financial statements have been prepared by
management in accordance with generally accepted accounting
principles. The integrity and objectivity of these financial
statements and the other financial information in the Annual
Report, including the estimates and judgments on which they are
based, are the responsibility of management. The financial
statements have been audited by Deloitte & Touche LLP, independent
certified public accountants appointed by the Board of Directors.
Their report is shown below. Management has made available to
Deloitte & Touche LLP all of the company's financial records and
related data, as well as the minutes of shareholders' and
directors' meetings.
Management maintains a system of internal accounting control
which it believes is adequate to provide reasonable, but not
absolute, assurance that assets are properly safeguarded and
accounted for, that transactions are executed in accordance with
management's authorization and are properly recorded and reported,
and for the prevention and detection of fraudulent financial
reporting. The concept of reasonable assurance recognizes that the
cost of a system of internal controls should not exceed the
benefits derived and that management makes estimates and judgments
of these cost/benefit factors.
Management monitors the system of internal control for
compliance through its own review and a strong internal auditing
program which also independently assesses the effectiveness of the
internal controls. In establishing and maintaining internal
controls, the company must exercise judgment in determining whether
the benefits derived justify the costs of such controls.
Management acknowledges its responsibility to provide
financial information (both audited and unaudited) that is
representative of the company's operations, reliable on a
consistent basis, and relevant for a meaningful financial
assessment of the company. Management believes that the control
process enables it to meet this responsibility.
Management also recognizes its responsibility for fostering a
strong ethical climate so that the company's affairs are conducted
according to the highest standards of personal and corporate
conduct. This responsibility is characterized and reflected in the
company's code of corporate conduct, which is publicized throughout
the company. The company maintains a systematic program to assess
compliance with this policy.
The Board of Directors has an Audit Committee composed solely
of directors who are not officers or employees. The Committee
recommends for approval by the full Board the appointment of the
independent auditors. The Committee meets regularly with
management, with the company's internal auditors and with the
independent auditors. The independent auditors and the internal
auditors periodically meet alone with the Audit Committee and have
free access to the Audit Committee at any time.
/s/ Neal E. Schmale
Neal E. Schmale
Executive Vice President and Chief Financial Officer
/s/ Frank H. Ault
Frank H. Ault
Vice President and Controller
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
- -----------------------------------------------------------------------------------
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
-------- -------- --------
Total 4,886 4,188 3,597
-------- -------- --------
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,
----------------
(Dollars in millions) 1998 1997
- --------------------------------------------------------------------
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
------- -------
Total current assets 2,458 2,761
------- -------
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
------- -------
Property, plant and equipment:
Property, plant and equipment 11,235 10,902
Less accumulated depreciation
and amortization (5,794) (5,360)
------- -------
Total property, plant and
equipment - net 5,441 5,542
------- -------
Total assets $ 10,456 $ 10,756
======= =======
See notes to Consolidated Financial Statements.
SEMPRA ENERGY
Consolidated Balance Sheets
December 31,
-----------------
(Dollars in millions) 1998 1997
- ------------------------------------------------------------------
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
------- -------
Total current liabilities 2,466 2,211
------- -------
Long-term debt:
Long-term debt 2,795 3,045
Debt of Employee Stock Ownership Plan -- 130
------- -------
Total long-term debt 2,795 3,175
------- -------
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
------- -------
Total deferred credits and
other liabilities 2,078 2,132
------- -------
Preferred stock of subsidiaries 204 279
------- -------
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)
------- -------
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
- ------------------------------------------------------------------------------------------
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
---------- --------- ---------
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)
--------- ----------- ----------
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
- ------------------------------------------------------------------------------------------
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
- ------------------------------------------------------------------------------------
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
- ------------------------------------------------------------------------------------
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
- ------------------------------------------------------------------------------------
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
- ------------------------------------------------------------------------------------
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:
- ---------------------------------------------------------------
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.
Sempra Energy
Quarterly Financial Data (unaudited)
Quarter ended
-------------------------------------------------------
March 31 June 30 September 30 December 31
Dollars in millions except per share amounts
- ------------------------------------------------------------------------------------------------------------
1998
Revenues and other income $ 1,350 $ 1,335 $ 1,398 $ 1,442
Operating expenses 1,164 1,249 1,192 1,281
-----------------------------------------------------
Operating income $ 186 $ 86 $ 206 $ 161
-----------------------------------------------------
Net income $ 87 $ 31 $ 91 $ 85
Average common shares outstanding (diluted) 236.4 236.9 237.4 237.6
Net income per common share (diluted) $ 0.37 $ 0.13 $ 0.38 $ 0.36
1997
Revenues and other income $ 1,301 $ 1,130 $ 1,251 $ 1,445
Operating expenses 1,093 878 1,018 1,199
-----------------------------------------------------
Operating income $ 208 $ 252 $ 233 $ 246
-----------------------------------------------------
Net income $ 98 $ 112 $ 102 $ 120
Average common shares outstanding (diluted) 239.2 236.3 236.2 236.6
Net income per common share (diluted) $ 0.41 $ 0.47 $ 0.43 $ 0.51
- ------------------------------------------------------------------------------------------------------------
Quarterly Common Stock Data (unaudited)
1998 1997
--------------------------------------------------------------------------
First Second Third Fourth First Second Third Fourth
Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter
- -----------------------------------------------------------------------------------------------------------
Market price
High * * 28 29 5/16 * * * *
Low * * 23 3/4 24 9/16 * * * *
Dividends declared(1) $0.32 $0.46 $0.39 $0.39 $0.31 $0.45 $0.19 $0.32
- -----------------------------------------------------------------------------------------------------------
*Not presented as the formation of Sempra Energy was not completed until June 26, 1998.
(1) Prior to the formation of Sempra Energy on June 26, 1998, dividends declared represents the sum of
dividends declared by Pacific Enterprises and Enova Corporation, divided by the sum of the combining
companies' shares after the conversion of PE's shares into Sempra Energy shares as described in Note 1 to
the notes to Consolidated Financial Statements.