EXHIBIT 13.01
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
INTRODUCTION
This section includes management's discussion and analysis of
operating results from 1997 through 1999, and provides 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 in San
Diego County and southern Orange County, and Southern California Gas
Company (SoCalGas), the nation's largest natural gas distribution
utility, serving 5 million meters throughout most of Southern
California and part of central California. Together, the two
utilities serve approximately 7 million meters. In addition, Sempra
Energy owns and operates other regulated and unregulated
subsidiaries. Sempra Energy Trading is engaged in the wholesale
trading and marketing of natural gas, power and petroleum. Sempra
Energy International develops, operates and invests in energy-
infrastructure systems and power-generation facilities outside the
United States. Sempra Energy Financial invests in limited
partnerships that own 1,250 affordable-housing properties throughout
the United States. Through other subsidiaries, the company owns and
operates centralized heating and cooling for large building
complexes, and is involved in nonutility electric generation,
domestic energy-utility operations and other energy-related products
and services.
STRATEGIC DIRECTION
Diversified utility companies, including the company, have
experienced and will continue to experience a significant increase
in the level of competition in the utility and energy services
markets over time. A steady move away from a regulated-monopoly,
energy-supply structure toward a more competitive structure has
affected the utility industry for nearly two decades. During the
past decade, various state and federal regulatory changes have
occurred and a significant number of states have begun to implement
legislative initiatives to permit retail customers to choose their
energy supply provider.
The company continues to refine its business strategies for the
following segments of the energy services industry: regulated
delivery services, international, wholesale trading, retail energy
services, electric generation and technology ventures.
The company plans to pursue the following initiatives to enhance its
business model and create sustainable earnings growth. SDG&E and
SoCalGas plan to focus on their core distribution businesses,
promoting competition in retail markets and efficiency in the
delivery-services business. Sempra Energy International will
continue to develop electric and gas distribution systems in Nova
Scotia, Mexico and portions of South America, while evaluating
opportunities to enhance its existing businesses with additional
investments. Sempra Energy Trading plans to continue to build and
enhance its natural gas, petroleum and electric-wholesale-trading
capability in North America, Europe and Asia. In addition, the
company and its nonutility subsidiaries plan to provide integrated
energy services to mass-market, commercial and industrial retail
customers in domestic and international markets. To support its
customer-focused activities, the company plans to continue to invest
in electric-generation assets, either through development or
acquisition. The company also has made investments and is developing
new businesses in the information-systems and communications fields.
The company believes that all of these businesses will complement
and broaden its offerings to utility customers in retail markets.
One of the company's objectives is to generate one-third of its
consolidated earnings from its unregulated businesses by the end of
2003. The company cannot provide assurance that this objective will
be achieved.
Based upon this integrated approach to the energy marketplace, the
company will seek to achieve long-term returns on shareholder
capital that exceed the returns that have been historically
available for state-regulated utility businesses. At the same time,
the company's business risks are expected to increase, resulting in
an increase in the potential volatility in revenue and income
streams.
As a complement to its business strategy, the company has developed
financial initiatives that are intended to increase the company's
financial and operating flexibility and to further position the
company for the increasingly competitive utility and energy services
markets. Accordingly, the company reduced the quarterly dividend
payable on shares of its common stock, commencing with the dividend
payable in the second quarter of 2000, to $0.25 per share ($1.00
annualized rate) from its previous level of $0.39 per share ($1.56
annualized rate). Reducing the dividend rate improves the company's
financial flexibility going forward. It also positions the company's
common stock for potential increased growth in market value by
retaining a proportionately higher level of earnings for
reinvestment in the business.
On March 6, 2000, as a result of a "Dutch Auction," the company
repurchased approximately 36 million shares of its common stock,
representing approximately 15 percent of its outstanding common
stock, at a price of $20 per share. The stock repurchase was
financed by issuing approximately $700 million in additional long-
term senior notes of the company and mandatorily redeemable trust-
preferred securities through underwritten public offerings. It
financed the remaining $35 million necessary to repurchase the
shares with the issuance by a subsidiary, Sempra Energy Holdings, of
short-term commercial paper notes, guaranteed by the company. These
transactions increased the financial leverage employed by the
company in its capital structure. The company expects to maintain a
strong investment grade credit rating on its debt and preferred
securities and, following the announcement of the tender offer for
the approximately 36 million shares and the related financing,
rating agencies reaffirmed the ratings for the company's securities
and those of its utility subsidiaries. However, these ratings are
subject to periodic review by the rating agencies and may change
from time to time.
BUSINESS-COMBINATION COSTS
Sempra Energy was formed to serve as a holding company for Pacific
Enterprises ("PE," the parent corporation of SoCalGas) and Enova
Corporation ("Enova," the parent corporation of SDG&E) in connection
with a business combination that became effective on June 26, 1998
(the PE/Enova business combination). 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. The preferred
stock of PE remained outstanding. The combination was a tax-free
transaction.
In January 1998, PE and Enova jointly acquired CES/Way
International, Inc., which was subsequently renamed Sempra Energy
Services, as described under "Investments."
On June 21, 1999, the company terminated its agreement to acquire KN
Energy, Inc.
Expenses incurred in connection with these events are $14 million,
aftertax, and $85 million, aftertax, for the years ended December
31, 1999 and 1998, respectively. The costs consist primarily of
employee-related costs, and investment banking, legal, regulatory
and consulting fees. See Note 1 of the notes to Consolidated
Financial Statements for additional information.
CAPITAL RESOURCES AND LIQUIDITY
The company's utility operations continue to be a major source of
liquidity. In addition, working capital and other requirements are
met primarily through the issuance of short-term and long-term debt.
Cash requirements at the utilities primarily consist of investments
in plant. Nonutility cash requirements include investments in Sempra
Energy Trading, Sempra Energy International and other ventures.
Additional information on sources and uses of cash during the last
three years is summarized in the following condensed statements of
consolidated cash flows:
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SOURCES AND (USES) OF CASH
Year Ended December 31 (Dollars in millions) 1999 1998 1997
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Operating Activities $1,188 $1,323 $ 918
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Investing Activities:
Net proceeds from sale of assets 466 - -
Capital expenditures (589) (438) (397)
Acquisitions of subsidiaries (639) (191) (206)
Other (27) (50) 1
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Total Investing Activities (789) (679) (602)
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Financing Activities:
Common dividends (368) (325) (301)
Sale of common stock 3 34 17
Repurchase of common stock - (1) (122)
Redemption of preferred stock - (75) -
Long-term debt - net (110) (356) 382
Short-term debt - net 139 (311) 92
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Total Financing Activities (336) (1,034) 68
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Increase (decrease) in cash
and cash equivalents $ 63 $ (390) $ 384
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CASH FLOWS FROM OPERATING ACTIVITIES
The decrease in cash flows from operating activities in 1999 was
primarily due to the completion of the recovery of SDG&E's stranded
costs and to reduced revenues - both the result of the sale of
SDG&E's fossil power plants and combustion turbines in the second
quarter of 1999 - and a return to ratepayers of the previously
overcollected regulatory balancing accounts of SoCalGas. This
decrease was partially offset by lower business-combination expenses
and lower income-tax payments in 1999. See additional discussion on
the sale of the power plants in Note 14 of the notes to Consolidated
Financial Statements for additional information.
The increase in cash flows from operating activities in 1998 was
primarily due to lower working-capital requirements for natural gas
operations. This was caused by higher throughput compared to 1997,
combined with natural gas costs that were lower than amounts being
collected in rates, resulting in overcollected regulatory balancing
accounts at year-end 1998. This increase was partially offset by
business-combination expenses. The fluctuation in cash flows from
operations was also affected by electric-industry restructuring and
increased revenue offset by the 10-percent rate reduction reflected
in customers' bills in 1998. These are discussed in Note 14 of the
notes to Consolidated Financial Statements.
CASH FLOWS FROM INVESTING ACTIVITIES
Cash flows from investing activities primarily represent capital
expenditures and investments in new businesses. For 1999, cash flows
from investing activities include proceeds from the sale of SDG&E
assets. The South Bay Power Plant was sold to the San Diego Unified
Port District for $110 million. The Encina Power Plant and 17
combustion-turbine generators were sold to Dynegy, Inc. and NRG
Energy, Inc. for $356 million. See additional discussion in Note 14
of the notes to Consolidated Financial Statements.
Capital Expenditures
Capital expenditures were $151 million higher in 1999 compared to
1998 due to investments in gas distribution facilities in Mexico, a
gas system expansion at SDG&E and additional improvements to the
electric-distribution system.
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 and improvements to the
electric-distribution system. This increase was partially offset by
lower capital spending at SoCalGas.
Capital expenditures at the utilities are estimated to be $525
million in 2000 and will be financed primarily by internally
generated funds.
Investments
In June 1999, the company and PSEG Global (PSEG) jointly acquired 90
percent of Chilquinta Energia S.A. (Energia). In January 2000, the
company and PSEG purchased an additional 9.75 percent of Chilquinta
Energia S.A., increasing their total holdings to 99.98 percent, at a
total cost of $840 million. In September 1999, the company and PSEG
completed their acquisition of 47.5 percent of Luz Del Sur S.A., a
Peruvian electric company, for $108 million. This acquisition,
combined with the 37 percent already owned through Energia,
increased the companies' total joint ownership to 84.5 percent of
Luz del Sur S.A.
In March 1998, the company 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. In June 1999, the
company contributed capital to Sodigas Pampeana S.A. and Sodigas Sur
S.A. to retire $32 million of debt. See further discussion of
international operations in "International Operations" below and in
Note 3 of the notes to Consolidated Financial Statements.
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.
As noted above, Sempra Energy 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 the latter half
of 1999, CES/Way's name was changed to Sempra Energy Services.
Sempra Energy's level of investments, excluding capital
expenditures, in the next few years may vary substantially and will
depend on the level of opportunities available in unregulated
business that are expected to provide desirable rates of return.
CASH FLOWS FROM FINANCING ACTIVITIES
Net cash used in financing activities decreased in 1999 from 1998
levels primarily due to lower long-term and short-term debt
repayments, greater long-term and short-term debt issuances and the
repurchase of preferred stock in 1998.
Net cash used in financing activities increased in 1998 from 1997
levels due to greater short-term 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.
Long-Term and Short-Term Debt
In 1999, cash was used for the repayment of $28 million of first-
mortgage bonds, $66 million of rate-reduction bonds and $82 million
in unsecured notes. The long-term debt issued in 1999 related
primarily to the purchase of Chilquinta Energia S.A. See additional
discussion in Note 3 of the notes to Consolidated Financial
Statements. The increase in short-term debt primarily represents
borrowing through Sempra Energy Holdings (SEH), the intermediate
holding company for many of the company's nonutility subsidiaries,
to partially finance acquisitions by Sempra Energy International
(SEI).
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.
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 connection with the issuance of the rate-reduction bonds, SDG&E
has $58 million of temporary investments that will be maintained
into the future to offset, for regulatory purposes, a like amount of
long-term debt since this was more cost-effective than redeeming
low-rate debt. The specific debt series being offset consists of
variable-rate IDBs. The California Public Utilities Commission
(CPUC) has approved specific ratemaking treatment that 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 $58 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 $58 million and the level
of IDBs being offset will be reduced by the same amount.
Stock Purchases and Redemptions
In February 2000, the company repurchased approximately 36 million
shares of its common stock at a price of $20.00 per share. This is
more fully described above under "Strategic Direction."
The company, through PE and Enova, repurchased $1 million and $122
million of common stock in 1998 and 1997, respectively. There were
no common stock repurchases in 1999.
On February 2, 1998, SoCalGas redeemed all outstanding shares of its
7 3/4 percent Series Preferred Stock at a cost of $25.09 per share,
or $75 million including accrued dividends.
Dividends
Dividends paid on common stock amounted to $368 million in 1999,
compared to $325 million in 1998 and $301 million in 1997. The
increases in 1999 and 1998 are 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
previously paid by PE.
On January 26, 2000, the company announced a reduction in the
quarterly dividend payable on shares of its common stock to $0.25
per share ($1.00 annualized rate) from its previous level of $0.39
per share ($1.56 annualized rate), commencing with the dividend for
the second quarter of 2000.
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
Total capitalization at December 31, 1999, was $6.4 billion. The
debt-to-capitalization ratio was 50 percent at December 31, 1999.
Activities in 1999 include an increase in debt related to the
acquisition of Chilquinta Energia S.A., offset by an increase in
common equity due to the settlement related to the 1992 quasi-
reorganization (QR) of Pacific Enterprises. See Notes 2 and 17 of
the notes to Consolidated Financial Statements for further
discussion of the QR and concerning the recent change in the debt-
to-capitalization ratio, respectively. If the stock repurchase and
the related financing had occurred at December 31, 1999, the debt-
to-capitalization ratio would have been 62 percent.
CASH AND CASH EQUIVALENTS
Cash and cash equivalents were $487 million at December 31, 1999.
This cash is available for investment in domestic and international
projects consistent with the company's strategic direction, the
retirement of debt, the repurchase of common stock, the payment of
dividends and other corporate purposes.
The company anticipates that operating cash required in 2000 for
capital expenditures, common stock dividends and debt payments will
be provided by cash generated from operating activities and existing
cash balances. Cash needed for the tender offer was obtained through
the issuance of $500 million of long-term notes and $200 million of
mandatorily redeemable trust-preferred securities. The dividend
reduction, combined with fewer shares outstanding (due to the
company's tender offer), will result in additional cash flow in
2000. This increased cash flow will be partially offset by higher
debt-service costs.
In addition to cash from ongoing operations, the company has
multiyear credit agreements that permit term borrowings of up to
$1.4 billion, of which $182 million is outstanding at December 31,
1999. For further discussion, see Note 4 of the notes to
Consolidated Financial Statements.
Management believes that the sources of funding described above are
sufficient to meet short-term and long-term liquidity needs.
RESULTS OF OPERATIONS
1999 Compared to 1998
Net income for 1999 increased to $394 million, or $1.66 per share of
common stock (diluted), from $294 million, or $1.24 per share of
common stock (diluted), for 1998.
The increase is primarily due to higher earnings at the California
utilities (due to lower business-combination costs), Sempra Energy
Trading, Sempra Energy Financial and Sempra Energy International.
See additional discussion in "California Utility Operations," "Other
Operations" and "International Operations."
For the fourth quarter of 1999, net income increased to $105
million, or $0.44 per share of common stock (diluted), from $85
million, or $0.36 per share of common stock (diluted), for the
fourth quarter of 1998. The increase is primarily due to higher
earnings at Sempra Energy Trading and Sempra Energy International.
In 1999, book value per share increased to $12.58 from $12.29 in
1998, primarily due to the settlement of QR issues previously
discussed.
1998 Compared to 1997
Net income for 1998 decreased to $294 million, or $1.24 per share of
common stock (diluted), from $432 million, or $1.82 per share of
common stock (diluted), for 1997.
The decrease in net income is primarily due to the business-
combination costs and a lower base margin established at SoCalGas in
its Performance-Based Regulation (PBR) decision which became
effective on August 1, 1997, as further described in Note 14 of the
notes to Consolidated Financial Statements. Business-combination
expenses were $85 million ($0.36 per share) and $20 million ($0.08
per share), aftertax, for 1998 and 1997, respectively.
For the fourth quarter of 1998, net income decreased from the fourth
quarter of 1997, due to awards for PBR and demand-side management
programs in 1997, electric seasonality effects compared to 1997, and
the factors that affected the annual comparison.
In 1998, book value per share decreased to $12.29 from $12.56, due
to common dividends' exceeding net income, which was lower than
normal due to the business-combination expenses.
California 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 received approval from
the CPUC for Performance-Based Ratemaking (PBR). Under PBR, income
potential is tied to achieving or exceeding specific performance and
productivity measures, rather than to expanding utility plant 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), which obtains power from qualifying facilities,
from nuclear units and, lastly, from the lowest-bidding suppliers.
The PX serves as a wholesale power pool, allowing all energy
producers to participate competitively. An Independent System
Operator (ISO) schedules power transactions and access to the
transmission system.
The natural gas industry experienced an initial phase of
restructuring during the 1980s by deregulating natural gas sales to
noncore customers. The CPUC is studying the issue of restructuring
for sales to core customers.
See additional discussion of electric-industry and natural gas-
industry restructuring below in "Industry Restructuring" and in Note
14 of the notes to Consolidated Financial Statements.
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Gas Sales, Transportation & Exchange Transportation
Gas Sales & Exchange Total
(Dollars in millions,
volumes in billion cubic feet)
Throughput Revenue Throughput Revenue Throughput Revenue
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1999:
Residential 313 $2,091 3 $10 316 $2,101
Commercial and Industrial 105 560 338 258 443 818
Utility Electric Generation* 18 7 218 83 236 90
Wholesale 23 11 23 11
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436 $2,658 582 $362 1,018 3,020
Balancing accounts and other (96)
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Total $2,924
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
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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
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*The portion representing SDG&E's sales to its electric generation operations
includes margin only.
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ELECTRIC DISTRIBUTION
1999 1998 1997
(Dollars in millions, Volumes Revenue Volumes Revenue Volumes Revenue
volumes in millions of Kwhrs)
Residential 6,327 $ 663 6,282 $ 637 6,125 $ 684
Commercial 6,284 592 6,821 643 6,940 680
Industrial 2,034 154 3,097 233 3,607 268
Direct access 3,212 118 964 44 - -
Street and highway lighting 73 7 85 8 76 7
Off-system sales 383 10 706 15 4,919 116
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18,313 1,544 17,955 1,580 21,667 1,755
Balancing accounts and other 274 285 14
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Total 18,313 $1,818 17,955 $1,865 21,667 $1,769
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1999 Compared to 1998
Utility natural gas revenues increased 5 percent in 1999 primarily
due to lower overcollections in 1999 (see discussion of balancing
accounts under "Accounting Standards" herein and in Note 2 of the
notes to Consolidated Financial Statements) and higher utility
electric-generation (UEG) revenues, partially offset by a decrease
in residential and commercial and industrial revenues. The increase
in UEG revenues was primarily due to the 1999 sale of SDG&E's fossil
fuel generating plants, since revenue now includes the selling price
of the natural gas instead of just the margin, because the sales are
now to unrelated parties. The decrease in residential and commercial
and industrial revenues is due to lower natural gas rates.
Electric revenues decreased 3 percent in 1999 compared to 1998,
primarily due to the decrease in base electric rates from the
completion of stranded cost recovery (described in Note 14 of the
notes to Consolidated Financial Statements).
The company's cost of natural gas distributed increased 22 percent
in 1999, largely due to an increase in the average price of natural
gas purchased.
As discussed in Note 14 of the notes to Consolidated Financial
Statements, PX/ISO power revenues have been netted against
purchased-power expense, including purchases from the PX/ISO. The
PX/ISO began operations on March 31, 1998.
Depreciation and amortization expense decreased 4 percent in 1999,
primarily due to the midyear completion of the accelerated recovery
of generation assets.
Operating expenses decreased 9 percent in 1999, primarily due to the
lower business-combination costs (none in 1999 compared to $117
million in 1998).
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 price 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 Competitive
Transition Cost (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 ISO. These
increases 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 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.
The company's cost of natural gas distributed decreased 18 percent
in 1998, largely due to a decrease in the average price of natural
gas purchased, partially offset by increases in sales volume.
Depreciation and amortization expense increased 49 percent in 1998,
primarily due to the accelerated recovery of stranded costs via the
CTC. The earnings impact of the increase is offset by CTC revenue as
discussed above.
Operating expenses increased 16 percent in 1998, primarily due to
the higher business-combination costs ($117 million in 1998,
compared to $11 million in 1997).
INTERNATIONAL OPERATIONS
Sempra Energy International (SEI) was formed in June 1998 to
develop, operate and invest in energy-infrastructure systems and
power-generation facilities outside the United States. SEI now has
interests in natural gas and/or electric transmission and
distribution projects in Mexico, Argentina, Chile, Peru, Uruguay and
Canada, and is pursuing other projects in Latin America.
As previously discussed, SEI and PSEG announced the completion of
the joint purchase of Chilquinta Energia S.A. and the acquisition of
an additional 47.5 percent of the outstanding shares of Luz del Sur
S.A., a Peruvian electric company. See Note 3 of the notes to
Consolidated Financial Statements for a discussion of the
acquisition of Chilquinta Energia S.A. and Luz del Sur S.A.
As noted above under "Investments," PE increased its investment in
Sodigas Pampeana S.A. and Sodigas Sur S.A. in 1998 and 1999. These
natural gas 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 owns 60 percent of Distribuidora de Gas Natural de Mexicali, S.
de R.L. de C.V. (DGN-Mexicali), a Mexican company that holds 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. It will invest up to $25 million to provide service to
25,000 customers during the first five years of operation.
SEI owns 95 percent of 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, it acquired ownership of a 16-mile transmission pipeline
serving 20 industrial customers. It will invest nearly $50 million
to provide service to 50,000 customers in the first five years of
operation.
In May 1999, SEI was awarded a 30-year license to build and operate
a natural gas distribution system in the La Laguna-Durango zone in
north-central Mexico. SEI will invest over $40 million in the
project during the first five years of operation.
In August 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 provides for delivery of up to 300 million cubic feet per
day of natural gas and construction of a 23-mile pipeline from the
U.S.-Mexico border to the plant. Construction of the pipeline is
anticipated to be completed by mid-2000 at a cost of $35 million.
The pipeline will also serve as a link for a natural gas
distribution system in Tijuana, Baja California, between San Diego
and Rosarito.
Net income for international operations in 1999 was $10 million
compared to net losses of $4 million and $9 million, aftertax, for
1998 and 1997, respectively. The increase in net income for 1999 was
primarily due to income from Chilquinta Energia S.A., and lower
operating costs and increased sales (as a result of colder weather)
in Argentina.
OTHER OPERATIONS
Sempra Energy Trading (SET), a leading natural gas, petroleum and
power marketing firm headquartered in Stamford, Conn., was acquired
on December 31, 1997. In addition to the transactions described in
"Market Risk" herein, SET also enters into long-term structured
transactions, such as the one supporting the SEI agreement referred
to in "International Operations" above. For the year ended December
31, 1999, SET recorded net income of $32 million from operations and
net income of $19 million after amortization of acquisition costs.
This is compared to 1998 net income of $1 million from operations
and a net loss of $13 million after amortization of acquisition
costs. The increase in net income is primarily due to greater
penetration of all customer segments, resulting in higher volumes
traded in 1999. In addition, new European crude oil and natural gas
trading contributed significantly to SET's 1999 earnings.
Sempra Energy Financial (SEF) invests as a limited partner in
affordable-housing properties and alternative-fuel projects. SEF's
portfolio includes 1,250 properties throughout the United States,
Puerto Rico and the Virgin Islands. These investments are expected
to provide income-tax benefits (primarily from income-tax credits)
over a 10-year period. SEF recorded net income of $28 million and
$20 million in 1999 and 1998, respectively. This is expected to
decline as the various 10-year periods expire, unless SEF makes
sufficient new investments. SEF's future investment policy is
dependent on the company's future income-tax position.
OTHER INCOME, INTEREST EXPENSE AND INCOME TAXES
Other Income
Other income, which primarily consists of interest income from
short-term investments, equity earnings from unconsolidated South
American subsidiaries and interest on regulatory-balancing accounts,
increased to $75 million in 1999 from $34 million in 1998. The
increase is primarily due to equity earnings from unconsolidated
subsidiaries. Other income decreased in 1998 to $34 million from $46
million in 1997, a result of lower interest income from short-term
investments.
Interest Expense
Interest expense for 1999 increased to $229 million in 1999 from
$197 million in 1998. The increase is primarily due to interest
expense on the excess rate-reduction bond liability (see additional
discussion in "Factors Influencing Future Performance - Electric
Rates" below). Interest expense for 1998 increased slightly to $197
million from $194 million in 1997.
Income Taxes
Income-tax expense was $179 million, $138 million and $301 million
for 1999, 1998 and 1997, respectively. The effective income-tax
rates were 31 percent, 32 percent and 41 percent for the same
periods. The increase in income-tax expense for 1999 compared to
1998 is due to the increase in income before taxes, partially offset
by the charitable contribution to the San Diego Unified Port
District in connection with the sale of the South Bay generating
plant. The decrease in income-tax expense for 1998 compared to 1997
is primarily due to the decrease in income before taxes, combined
with an increase in affordable-housing tax credits.
FACTORS INFLUENCING FUTURE PERFORMANCE
Base results of the company in the near future will depend primarily
on the results of SDG&E and SoCalGas. Earnings growth and
fluctuations will depend on changes in the utility industry and
activities at SEI, SET and other businesses. Because of the
ratemaking and regulatory process, electric- and natural gas-
industry restructuring, the changing energy marketplace and these
other businesses, there are several factors that will influence
future financial performance. These factors are summarized below.
Chilquinta Energia S.A. and Luz del Sur S.A. Acquisitions
In June 1999, SEI and PSEG announced the completion of the joint
purchase of Chilquinta Energia S.A. In September 1999, SEI and PSEG
completed the acquisition of 47.5 percent of the outstanding shares
of Luz del Sur S.A. See "Business Combinations" above, Note 3 of the
notes to Consolidated Financial Statements and "International
Operations" below for a discussion of the acquisition of Chilquinta
Energia S.A. and Luz del Sur S.A.
Nova Scotia
In December 1999, Sempra Atlantic Gas (SAG), a subsidiary of SEI,
was awarded a 25-year franchise by the provincial government of Nova
Scotia to build and operate a natural gas-distribution system in
Nova Scotia. SAG plans to invest $700 million to $800 million over
the next seven years to build the system, which will make natural
gas available to 78 percent of the 350,000 households in Nova
Scotia. Construction of the system is expected to begin in mid-2000,
and delivery of natural gas is expected to begin by the end of 2000.
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 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. The PX serves as a wholesale
power pool allowing all energy producers to participate
competitively.
Thus far, electric-industry deregulation has been confined to
generation. Transmission and distribution have remained subject to
traditional cost-of-service and performance-based-ratemaking
regulation. However, the CPUC is exploring the possibility of
opening up electric distribution to competition. During 2000, the
CPUC will consider whether any changes should be made in electric-
distribution regulation. A CPUC staff report on this issue will be
submitted to the CPUC in the second quarter of 2000. SDG&E and
SoCalGas will actively participate in this effort. See Note 14 of
the notes to Consolidated Financial Statements for additional
information.
On December 20, 1999, the Federal Energy Regulatory Commission
(FERC) issued "Order 2000" concerning the formation of Regional
Transmission Organizations (RTOs). The rule generally requires all
public utilities that own, operate or control interstate
transmission to file by October 15, 2000, a proposal for an RTO.
Public utilities that are members of an existing, FERC-approved
regional entity must file by January 15, 2001. The rule states that
RTOs will be operational by December 15, 2001, and will address many
issues to improve the transmission of energy. See additional
discussion in Note 14 of the notes to Consolidated Financial
Statements.
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 released a staff
report initiating a proceeding 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's natural gas consumers.
In August 1998, California enacted a law prohibiting the CPUC from
enacting any natural gas industry-restructuring decision for core
(residential and small-commercial) customers prior to January 1,
2000. During the implementation moratorium, the CPUC has held
hearings throughout the state and intends to give the legislature a
draft ruling before adopting a final market-structure policy. SDG&E
and SoCalGas have been actively participating in this effort and
have argued in support of competition intended to maximize benefits
to customers rather than to protect competitors.
In October 1999, the state of California enacted a law (AB 1421)
that requires that gas utilities provide "bundled basic gas service"
(including transmission, storage, distribution, purchasing, revenue-
cycle services and after-meter services) to all core customers,
unless the customer chooses to purchase gas from a nonutility
provider. The law prohibits the CPUC from unbundling distribution-
related gas services (including meter reading and billing) and
after-meter services (including leak investigation, inspecting
customer piping and appliances, pilot relighting and carbon monoxide
investigation) for most customers. The objective is to preserve both
customer safety and customer choice.
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.
In June 1999, SDG&E completed the recovery of a majority of its
stranded costs. The recovery was affected by, among other things,
the sale of SDG&E's fossil power plants and combustion turbines
during the quarter ended June 30, 1999. Costs related to the above-
market portion of qualifying facilities and other purchased-power
contracts that were in effect at December 31, 1995, and the San
Onofre Nuclear Generating Station (SONGS) will continue to be
recovered in rates. See Note 14 of the notes to Consolidated
Financial Statements for additional information.
Electric-Generation Assets
In 1998, 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 from which
utilities throughout the Western United States purchase. 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, is
expected to be operational in the second quarter of 2000.
Electric Rates
AB 1890 provided for a 10-percent reduction in rates for residential
and small-commercial customers beginning in January 1998 and 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. 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.
The sizes of the rate-reduction bond issuances were set so as to
make the IOUs neutral as to the 10-percent rate reduction, and were
based on a four-year period to recover stranded costs. Because SDG&E
recovered its stranded costs in only 18 months (due to the greater-
than-anticipated plant-sale proceeds), the bond proceeds were
greater than needed. Accordingly, SDG&E will return to its customers
over $400 million that it has collected or will collect from its
customers. The timing of the return will differ from the timing of
the collection, but the specific timing of the repayment and the
interest rate thereon are the subject of a CPUC proceeding and are
expected to be resolved in the second quarter of 2000. This refund
will not affect SDG&E's net income, except to the extent that the
interest cost associated with the refund (12.63 percent if not
reduced as a result of the CPUC proceeding) differs from the return
earned by the company on the funds. The bonds and their repayment
schedule are unaffected by this refund.
AB 1890 also includes a rate freeze for all IOU customers during the
CTC period. In connection with completion of its stranded cost
recovery (described above and in Note 14 of the notes to
Consolidated Financial Statements), SDG&E filed with the CPUC for a
mechanism to structure electric rates after the end of the rate
freeze. SDG&E received approval to reduce base rates (the
noncommodity portion of rates) to all electric customers effective
July 1, 1999. The portion of the electric rate representing the
commodity cost is simply passed through to customers and will
fluctuate with the price of electricity from the PX. Except for the
interim protection mechanism described below, customers will no
longer be protected from commodity price spikes.
In April 1999, SDG&E filed an all-party settlement (including energy
service providers, the CPUC's Office of Ratepayer Advocates and the
Utility Consumers Action Network) detailing proposed implementation
plans for lifting the rate freeze. A CPUC decision adopting the all-
party settlement was issued in May 1999 and became effective July 1,
1999. Included in the settlement is an interim customer-protection
mechanism for residential and small-commercial customers that capped
rates between July 1999 and September 1999, regardless of how high
the PX price moved during the period. The resulting undercollection
(which amounted to less than $1 million) is being recovered through
a balancing account mechanism. The interim rate-freeze period runs
until the CPUC issues its decision on the pending legal and policy
issues of ending the rate freeze. This decision is expected during
the second quarter of 2000.
Performance-Based Regulation (PBR)
To promote efficient operations and improved productivity and to
move away from reasonableness review 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 goals, as well as cost reductions, rather than by
relying solely on expanding utility plant 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.
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 ratemaking
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. See Notes 1
and 14 of the notes to Consolidated Financial Statements for
additional information.
Allowed Rate of Return
For 2000, SoCalGas is 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 1999. SDG&E is authorized to earn a
rate of return on rate base of 8.75 percent and a rate of return on
common equity of 10.6 percent, compared to 9.35 percent and 11.6
percent prior to July 1, 1999, respectively. Either utility can earn
more than the authorized rate by controlling costs below approval
levels, by experiencing increased volumes of sales not subject to
balancing accounts (both of which are subject to revenue sharing, as
described in Note 14 of the notes to Consolidated Financial
Statements) or by achieving favorable results in certain areas, such
as incentive mechanisms, that are not subject to revenue sharing.
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 decisions. The utilities intend to make the efficiency
improvements, changes in operations and cost reductions necessary to
achieve this objective and earn at least 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 prior to the inception of PBR. See
additional discussion of PBR above and in Note 14 of the notes to
Consolidated Financial Statements.
Noncore Bypass
SoCalGas is fully at risk for reductions in noncore volumes due to
bypass. However, significant bypass would require construction of
additional facilities by competing pipelines. SoCalGas has not had a
material reduction in earnings from bypass and it is continuing to
reduce its costs to remain competitive and retain its transportation
customers.
Noncore Pricing
To respond to bypass, SoCalGas has received authorization from the
CPUC for expedited review of long-term natural 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 will be 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 was
limited as a result of the Comprehensive Settlement. The settlement
addressed a number of regulatory issues and was approved by the CPUC
in July 1994. This treatment will be replaced by the PBR mechanism
as adopted in the 1999 BCAP, whereby revenue fluctuations will
impact earnings (positively or negatively). See Note 14 of the notes
to Consolidated Financial Statements for additional discussion.
Excess Interstate-Pipeline Capacity
Existing interstate-pipeline capacity into California exceeds
current demand by over 1 billion cubic feet (Bcf) per day. This
situation has reduced the market value of the capacity well below
FERC's 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 0.40 Bcf per day of capacity is marketed at
significant discounts. Under existing California regulation,
unsubscribed capacity costs associated with the remaining 0.40 Bcf
per day are recoverable in customer rates. While including the
unsubscribed pipeline cost in rates may impact SoCalGas' ability to
compete in competitive markets, SoCalGas does not believe its
inclusion will have a significant impact on volumes transported or
sold.
ENVIRONMENTAL MATTERS
The company's operations are subject to federal, state and local
environmental laws and regulations governing such things as
hazardous wastes, air and water quality, land use, solid-waste
disposal, and the protection of wildlife.
Most of the potential situations in which the company is faced with
environmental issues occur at SoCalGas or SDG&E. For these
utilities, capital costs to comply with environmental requirements
are generally recovered through the depreciation components of
customer rates. The utilities' customers also generally are
responsible for 90 percent of the noncapital costs associated with
hazardous substances and the normal operating costs associated with
safeguarding air and water quality, disposing properly of solid
waste, and protecting endangered species and other wildlife.
Therefore, the likelihood of the company's financial position or
results of operations being adversely affected in a significant
amount is remote.
The environmental issues currently facing the company or resolved
during the latest three-year period include investigation and
remediation of SoCalGas' and SDG&E's manufactured-gas sites (14
completed as of December 31, 1999, and 31 to be completed), asbestos
and other cleanup at SDG&E's former fossil-fueled power plants (all
sold in 1999 and actual or estimated cleanup costs included in the
transactions), cleanup of third-party waste-disposal sites used by
the company, which has been identified as a Potentially Responsible
Party (investigations and remediations are continuing), and
mitigation of damage to the marine environment caused by the
cooling-water discharge from the San Onofre Nuclear Generating
Station (SONGS) Units 2 and 3 (the requirements for enhanced fish
protection, a 150-acre artificial reef and restoration of 150 acres
of coastal wetlands are in process).
MARKET RISK
The company's policy is to use derivative financial instruments to
reduce its 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 exposes 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 (SET) 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 California utilities 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, 1999, the notional amount of swap transactions
associated with the regulated operations totaled $45 million. See
Note 10 of the notes to Consolidated Financial Statements for
further information regarding these swap transactions.
The company's California utilities 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 California utilities is
subject to certain limitations imposed by 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 California utilities.
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 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, purpose
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, 1999, 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 have used a combination of fixed-rate and floating-rate
debt. Subject to regulatory constraints, interest rate swaps 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 has hedged this foreign
currency cash exposure through a swap transaction entered into with
a major international bank.
The VaR on the company's fixed-rate long-term debt is estimated at
approximately $194 million as of December 31, 1999, assuming a one-
year holding period.
Energy-Price Risk
Market risk related to physical commodities is based upon potential
fluctuations in natural gas, petroleum and electricity 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 one-day holding period. As of December 31, 1999, the
diversified VaR of SET's portfolio was $2.6 million.
SDG&E and SoCalGas
SDG&E and SoCalGas may, at times, be exposed to limited market risk
in their natural gas purchase, sale and storage activities as a
result of activities under SDG&E's gas PBR or SoCalGas' Gas Cost
Incentive Mechanism. They manage their risk within the parameters of
the company's market-risk-management and trading framework. As of
December 31, 1999, the total VaR of the utilities' 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.
Foreign-Currency-Rate Risk
Foreign-currency-rate risk exists by nature of the company's global
operations. The company has investments in entities whose functional
currency is not the U.S. dollar, which exposes the company to
foreign exchange movements, primarily in Latin American currencies.
When appropriate, the company may attempt to limit its exposure to
changing foreign exchange rates through both operational and
financial market actions. These actions may include entering into
forward, option and swap contracts to hedge existing exposures, firm
commitments and anticipated transactions. As of December 31, 1999,
the company had not entered into any such actions.
YEAR 2000 ISSUES
There were only a few, very minor Year 2000 interruptions to the
company's automated systems and applications, suppliers and
customers. The company incurred expenses of $48 million (including
$7.6 million in 1999) for its Year 2000 readiness effort and expects
to incur no additional costs.
NEW ACCOUNTING STANDARDS
In June 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards (SFAS) No. 133
"Accounting for Derivative Instruments and Hedging Activities." In
June 1999, the effective date of this statement was deferred for one
year. As amended, SFAS 133, which is effective for the company on
January 1, 2001, 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 contains statements that are not historical fact
and constitute forward-looking statements within the meaning of the
Private Securities Litigation Reform Act of 1995. The words
"estimates," "believes," "expects," "anticipates," "plans,"
"intends," "may" and "should" or similar expressions, or discussions
of strategy or of plans are intended to identify forward-looking
statements that involve risks, uncertainties and assumptions. Future
results may differ materially from those expressed in these forward-
looking statements.
These statements are necessarily based upon various assumptions
involving judgments with respect to the future and other risks,
including, among others, local, regional, national and international
economic, competitive, political and regulatory conditions and
developments, technological developments; capital market conditions;
inflation rates; interest rates; exchange rates; energy markets,
including the timing and extent of changes in commodity prices;
weather conditions; business, regulatory or legal decisions; the
pace of deregulation of retail natural gas and electricity delivery;
the timing and success of business-development efforts; and other
uncertainties - all of which are difficult to predict and many of
which are beyond the control of the company. Readers are cautioned
not to rely unduly on any forward-looking statements and are urged
to review and consider carefully the risks, uncertainties and other
factors which affect the company's business described in this Annual
Report and other reports filed by the company from time to time with
the Securities and Exchange Commission
FIVE-YEAR SUMMARY
At December 31 or for the years ended December 31
(Dollars in millions except per-share amounts) 1999 1998 1997 1996 1995
- ----------------------------------------------------------------------------------------------
REVENUES AND OTHER INCOME:
Gas $ 2,924 $ 2,772 $ 2,964 $ 2,710 $ 2,542
Electric 1,818 1,865 1,769 1,591 1,504
Other 693 378 382 223 155
--------------------------------------------
Total $ 5,435 $ 5,015 $ 5,115 $ 4,524 $ 4,201
--------------------------------------------
Operating income $ 802 $ 629 $ 927 $ 927 $ 886
Net income $ 394 $ 294 $ 432 $ 427 $ 401
Net income per common share:
Basic $ 1.66 $ 1.24 $ 1.83 $ 1.77 $ 1.67
Diluted $ 1.66 $ 1.24 $ 1.82 $ 1.77 $ 1.67
Dividends declared per common share $ 1.56 $ 1.56 $ 1.27 $ 1.24 $ 1.22
Pretax income/revenue 10.7% 8.7% 14.5% 16.2% 16.0%
Return on common equity 13.3% 10.0% 14.7% 14.9% 14.6%
Effective income tax rate 31.2% 31.9% 41.1% 41.3% 39.7%
Dividend payout ratio:
Basic 94.0% 125.8% 69.4% 70.1% 73.1%
Diluted 94.0% 125.8% 69.8% 70.1% 73.1%
Price range of common shares 26-17 1/8 29 5/16-23 3/4 * * *
AT DECEMBER 31
Current assets $ 3,040 $ 2,458 $ 2,761 $ 1,592 $ 1,520
Total assets $11,270 $10,456 $10,756 $ 9,762 $ 9,837
Current liabilities $ 3,327 $ 2,466 $ 2,211 $ 1,572 $ 1,578
Long-term debt (excludes current portion) $ 2,902 $ 2,795 $ 3,175 $ 2,704 $ 2,721
Shareholders' equity $ 2,986 $ 2,913 $ 2,959 $ 2,930 $ 2,815
Common shares outstanding(in millions) 237.4 237.0 235.6 240.0 240.6
Book value per common share $ 12.58 $ 12.29 $ 12.56 $12.21 $11.70
Price/earnings ratio 10.5 20.5 * * *
Number of meters (in thousands):
Natural gas 5,725 5,639 5,551 5,501 5,436
Electricity 1,218 1,192 1,178 1,164 1,151
- ----------------------------------------------------------------------------------------------
*Not presented as the formation of Sempra Energy was not completed until June 26, 1998.
STATEMENT OF MANAGEMENT RESPONSIBILITY FOR CONSOLIDATED 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 on the next page. 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, as well as in executive session. 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.
Neal E. Schmale
Executive Vice President and
Chief Financial Officer
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,
1999 and 1998, 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, 1999. 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, 1999 and 1998, and the
results of their operations and their cash flows for each of the
three years in the period ended December 31, 1999, in conformity
with generally accepted accounting principles.
/S/ DELOITTE & TOUCHE LLP
San Diego, California
February 4, 2000 (February 25, 2000 as to Note 17)
STATEMENTS OF CONSOLIDATED INCOME
For the years ended December 31
(Dollars in millions except per-share amounts) 1999 1998 1997
- --------------------------------------------------------------------------------
REVENUES AND OTHER INCOME
Utility revenues:
Natural gas $2,924 $2,772 $2,964
Electric 1,818 1,865 1,769
Other operating revenues 618 344 336
Other income 75 34 46
------------------------
Total 5,435 5,015 5,115
------------------------
Expenses
Cost of natural gas distributed 1,164 954 1,168
Purchased power - net 467 260 441
Electric fuel 69 177 164
Operating expenses 1,862 1,872 1,615
Depreciation and amortization 879 929 604
Franchise payments and other taxes 181 182 178
Preferred dividends by subsidiaries 11 12 18
------------------------
Total 4,633 4,386 4,188
------------------------
Income Before Interest and Income Taxes 802 629 927
Interest 229 197 194
------------------------
Income Before Income Taxes 573 432 733
Income taxes 179 138 301
------------------------
Net Income $ 394 $ 294 $ 432
------------------------
Net Income Per Share of Common Stock (Basic) $ 1.66 $ 1.24 $ 1.83
------------------------
Net Income Per Share of Common Stock (Diluted) $ 1.66 $ 1.24 $ 1.82
------------------------
Common Dividends Declared Per Share $ 1.56 $ 1.56 $ 1.27
- --------------------------------------------------------------------------------
See notes to Consolidated Financial Statements.
CONSOLIDATED BALANCE SHEETS
At December 31 (Dollars in millions) 1999 1998
- --------------------------------------------------------------------------------
ASSETS
Current assets:
Cash and cash equivalents $ 487 $ 424
Accounts receivable - trade 428 586
Accounts and notes receivable - other 129 159
Income taxes receivable 144 -
Deferred income taxes - 93
Energy trading assets 1,539 906
Inventories 148 151
Other 165 139
-----------------
Total current assets 3,040 2,458
-----------------
Investments and other assets:
Regulatory assets 670 1,056
Nuclear-decommissioning trusts 551 494
Investments 1,164 548
Other assets 451 459
-----------------
Total investments and other assets 2,836 2,557
-----------------
Property, plant and equipment:
Property, plant and equipment 11,127 11,235
Less accumulated depreciation and amortization (5,733) (5,794)
------------------
Total property, plant and equipment - net 5,394 5,441
------------------
Total assets $11,270 $10,456
- --------------------------------------------------------------------------------
See notes to Consolidated Financial Statements.
CONSOLIDATED BALANCE SHEETS (CONTINUED)
At December 31 (Dollars in millions) 1999 1998
- --------------------------------------------------------------------------------
LIABILITIES
Current liabilities:
Short-term debt $ 182 $ 43
Accounts payable 737 702
Accrued income taxes - 27
Deferred income taxes 67 -
Energy trading liabilities 1,365 805
Dividends and interest payable 154 168
Regulatory balancing accounts - net 357 120
Long-term debt due within one year 155 330
Other 310 271
-----------------
Total current liabilities 3,327 2,466
-----------------
Long-term debt 2,902 2,795
Deferred credits and other liabilities:
Customer advances for construction 72 72
Post-retirement benefits other than pensions 204 240
Deferred income taxes 615 634
Deferred investment tax credits 106 147
Deferred credits and other liabilities 854 985
-----------------
Total deferred credits and other liabilities 1,851 2,078
-----------------
Preferred stock of subsidiaries 204 204
-----------------
Commitments and contingent liabilities (Note 13)
SHAREHOLDERS' EQUITY
Common stock 1,966 1,883
Retained earnings 1,101 1,075
Deferred compensation relating to ESOP (42) (45)
Accumulated other comprehensive income (39) -
----------------
Total shareholders' equity 2,986 2,913
----------------
Total liabilities and shareholders' equity $11,270 $10,456
- -------------------------------------------------------------------------------
See notes to Consolidated Financial Statements.
STATEMENTS OF CONSOLIDATED CASH FLOWS
For the years ended December 31 (Dollars in millions) 1999 1998 1997
- -------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 394 $ 294 $ 432
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization 879 929 604
Portion of depreciation arising from sales of
generating plants (303) - -
Application of balancing account to stranded costs (66) (86) -
Deferred income taxes and investment tax credits (43) (199) (16)
Other - net (87) (94) 62
Net change in other working capital components 414 479 (164)
-------------------------
Net cash provided by operating activities 1,188 1,323 918
-------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Net proceeds from sales of generating plants 466 - -
Expenditures for property, plant and equipment (589) (438) (397)
Acquisitions of businesses (639) (191) (206)
Other (27) (50) 1
-------------------------
Net cash used in investing activities (789) (679) (602)
-------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends (368) (325) (301)
Sale of common stock 3 34 17
Repurchase of common stock - (1) (122)
Redemption of preferred stock - (75) -
Issuances of other long-term debt 160 75 140
Issuance of rate-reduction bonds - - 658
Payments on long-term debt (270) (431) (416)
Increase (decrease) in short-term debt - net 139 (311) 92
------------------------
Net cash provided by (used in) financing activities (336) (1,034) 68
------------------------
Increase (Decrease) in Cash and Cash Equivalents 63 (390) 384
Cash and Cash Equivalents, January 1 424 814 430
------------------------
Cash and Cash Equivalents, December 31 $ 487 $ 424 $ 814
- --------------------------------------------------------------------------------
See notes to Consolidated Financial Statements.
STATEMENTS OF CONSOLIDATED CASH FLOWS (CONTINUED)
For the years ended December 31 (Dollars in millions) 1999 1998 1997
- --------------------------------------------------------------------------------
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 $188 $ 90 $(129)
Net trading assets (73) (71) -
Inventories 3 (40) (2)
Regulatory balancing accounts 303 417 48
Other current assets (26) (26) 41
Accounts payable and other current liabilities 19 109 (122)
------------------------
Net change in other working capital components $414 $479 $(164)
------------------------
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid during the year for:
Interest (net of amounts capitalized) $281 $211 $193
Income taxes (net of refunds) $168 $366 $274
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 $ 34 $ 36 $126
-----------------------
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.
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
Deferred Accumulated
For the years ended Compensation Other Total
December 31, 1999, 1998 and 1997 Comprehensive Common Retained Relating Comprehensive Shareholders'
(Dollars in millions) Income Stock Earnings to ESOP Income Equity
- -----------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1996 | $1,953 $1,026 $(49) $ - $2,930
|
Net income/comprehensive income $ 432 | 432 432
Common stock dividends declared | (301) (301)
Sale of common stock | 17 17
Repurchase of common stock | (122) (122)
Long-term incentive plan | 1 1
Common stock released from ESOP | 2 2
--------------|---------------------------------------------------------------------
Balance at December 31, 1997 | 1,849 1,157 (47) - 2,959
|
Net income/comprehensive income 294 | 294 294
Common stock dividends declared | (376) (376)
Sale of common stock | 34 34
Repurchase of common stock | (1) (1)
Long-term incentive plan | 1 1
Common stock released from ESOP | 2 2
--------------|--------------------------------------------------------------------
Balance at December 31, 1998 | 1,883 1,075 (45) - 2,913
|
Net income 394 | 394 394
Comprehensive income adjustment: |
Foreign-currency translation losses (42) | (42) (42)
Available-for-sale securities 12 | 12 12
Pension (9) | (9) (9)
------- |
Comprehensive income $ 355 |
------- |
Common stock dividends declared | (368) (368)
Quasi-reorganization |
adjustment (Note 2) | 80 80
Sale of common stock | 2 2
Long-term incentive plan | 1 1
Common stock released from ESOP | 3 3
---------|--------------------------------------------------------------------
Balance at December 31, 1999 | $1,966 $1,101 $(42) $(39) $2,986
- ---------------------------------------------------------------------------------------------------------------------
See notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1 BUSINESS COMBINATION
Sempra Energy (the company) was formed as a holding company for
Enova Corporation (Enova) and Pacific Enterprises (PE) in connection
with a business combination of Enova and PE that was completed on
June 26, 1998. As a result of the combination each outstanding share
of common stock of Enova was converted into one share of common
stock of Sempra Energy, and each outstanding share of common stock
of PE was converted into 1.5038 shares of common stock of Sempra
Energy. The preferred stock and preference stock of the combining
companies and their subsidiaries remained outstanding.
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.
2 SIGNIFICANT ACCOUNTING POLICIES
EFFECTS OF REGULATION
The accounting policies of the company's principal subsidiaries, San
Diego Gas & Electric (SDG&E) and Southern California Gas Company
(SoCalGas), conform with generally accepted accounting principles
for regulated enterprises and reflect the policies of the California
Public Utilities Commission (CPUC) and the Federal Energy Regulatory
Commission (FERC).
SDG&E and SoCalGas prepare 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 records 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 to be no longer subject to SFAS No. 71, or recovery was to be
no longer probable as a result of changes in regulation or the
utility's 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.
The application of SFAS No. 121 continues to be evaluated in
connection with industry restructuring. Information concerning
regulatory assets and liabilities is described below in "Revenues
and Regulatory Balancing Accounts" and industry restructuring is
described 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, 1999,
represent net payables of $165 million and $192 million for SoCalGas
and SDG&E, respectively. The corresponding amounts at December 31,
1998, were $129 million net payable and $9 million net receivable
for SoCalGas and SDG&E, respectively.
Prior to 1998, fluctuations in utility earnings 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. 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 was applied to
transition cost recovery, and fluctuations in certain costs and
consumption levels can now affect earnings from electric operations.
In addition, fluctuations in certain costs and consumption levels
can affect earnings from SDG&E's gas operations. Additional
information on regulatory matters is included in Note 14.
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 also earns trading
profits as a dealer by structuring and executing transactions that
permit its counterparties to manage their risk profiles, and takes
positions in energy markets based on the expectation of future
market conditions. These positions include options, forwards,
futures and swaps. SET adjusts these derivatives to market each
month with gains and losses recognized in earnings. See "Trading
Instruments" below and Note 10 for additional information.
REGULATORY ASSETS
Regulatory assets include unrecovered premium on early retirement of
debt, postretirement 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.
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.
INVENTORIES
Included in inventories at December 31, 1999, are $68 million of
utility materials and supplies ($70 million in 1998), and $80
million of natural gas and fuel oil ($81 million in 1998). 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.
PROPERTY, PLANT AND EQUIPMENT
This primarily represents the buildings, equipment and other
facilities used by SoCalGas and SDG&E 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, 1999,
are: natural gas operations $7.1 billion, electric distribution $2.5
billion, electric transmission $0.7 billion, and other electric $0.4
billion. The corresponding amounts at December 31, 1998, were
essentially the same, except that other electric decreased by $0.5
billion in 1999 in connection with electric-industry restructuring,
as described in Note 14. Accumulated depreciation and
decommissioning of natural gas and electric utility plant in service
at December 31, 1999, are $3.8 billion and $1.9 billion,
respectively, and at December 31, 1998, were $3.5 billion and $2.2
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 1999, 1998 and 1997,
respectively are: natural gas operations 4.32, 4.32, 4.31, electric
generation 8.70, 6.49, 5.60, electric distribution 4.69, 4.49, 4.39,
electric transmission 3.50, 3.31, 3.28, and other electric 8.21,
6.29, 6.02. The increases for electric generation reflect the
accelerated recovery of generation facilities and the increase in
depreciation rates resulting from the 1999 Cost of Service
proceeding. See Note 14 for additional discussion of generation
facilities and industry restructuring. The remaining cost amounts
($0.4 billion at December 31, 1999, and $0.2 billion at December 31,
1998) consist of various items of property at various other
consolidated entities, with various depreciation rates depending on
the nature of the items.
NUCLEAR-DECOMMISSIONING LIABILITY
Deferred credits and other liabilities at December 31, 1999, include
$165 million ($146 million in 1998) of accumulated decommissioning
costs associated with SDG&E's interest in San Onofre Nuclear
Generating Station (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.
FOREIGN CURRENCY TRANSLATION
The assets and liabilities of the company's foreign operations are
generally translated into U.S. dollars at current exchange rates,
and revenues and expenses are translated at average exchange rates
for the year. Resulting translation adjustments are reflected in a
component of shareholders' equity ("accumulated other comprehensive
income"). Foreign currency transaction gains and losses are included
in consolidated net income.
COMPREHENSIVE INCOME
SFAS No. 130, "Reporting Comprehensive Income," 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 marketable securities that are classified as available-
for-sale. Securities are so classified if the company uses the
securities in its cash/asset management program whereby the
securities may be sold in connection with interest rate changes and
cash requirements. At December 31, 1999, the company had one such
investment, which increased in value during 1999. That increase is
recognized in the "Statement of Consolidated Changes in
Shareholders' Equity."
QUASI-REORGANIZATION
In 1993, PE divested its merchandising operations and most 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 the quasi-
reorganization were favorably resolved in November 1999, including
unitary tax issues. Excess reserves of $80 million resulting from
the favorable resolution of these issues have been added to
shareholders' equity.
Other 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.
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.
CASH AND CASH EQUIVALENTS
Cash equivalents are highly liquid investments with original
maturities of three months or less at the date of purchase, or
investments that are readily convertible to cash.
BASIS OF PRESENTATION
Certain prior-year amounts have been reclassified to conform to the
current year's presentation.
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,"
which is effective for the company on January 1, 2001. The statement
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 INTERNATIONAL (SEI)
On June 10, 1999, SEI and PSEG Global (PSEG) purchased (on a 50/50
basis) Chilquinta Energia S.A. (Energia) for $840 million. Sempra
Energy invested $260 million for the purchase of stock and
refinanced $160 million of Energia's long-term debt outstanding. In
September 1999, Sempra Energy and PSEG completed their acquisition
of 47.5 percent of the outstanding shares of Luz del Sur S.A., a
Peruvian electric company. Sempra Energy's share of the transaction
was $108 million in cash. This acquisition, combined with the 37
percent already owned through Energia, increased the companies'
total joint ownership to 84.5 percent of Luz del Sur S.A.
SEI 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 May 1999, SEI was awarded a 30-year license to build and operate
a natural gas distribution system in the La Laguna-Durango zone in
north-central Mexico. SEI will invest over $40 million in the
project during the first five years of operation.
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, the related transportation services in the U.S.,
and construction of a 23-mile pipeline from the U.S.-Mexico border
to the plant. Construction of the pipeline is anticipated to be
completed by mid-2000 at a cost of $35 million. The pipeline will
also serve as a link for a natural gas distribution system in
Tijuana, Baja California.
In December 1999 Sempra Atlantia Gas (SAG), a subsidiary of SEI, was
awarded a 25-year franchise by the provincial government of Nova
Scotia to build and operate a natural gas distribution system in
Nova Scotia. SAG plans to invest $700 million to $800 million over
the next seven years to build the system, which will make natural
gas available to 78 percent of the 350,000 households in Nova
Scotia. Construction of the system is expected to begin in mid-2000,
and delivery of natural gas is expected to begin by the end of 2000.
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. In June 1999, the
company contributed capital to the Argentine companies to retire $32
million of debt. The distribution companies serve 1.2 million
customers in central and southern Argentina, respectively, and have
a combined throughput of 650 million cubic feet per day.
SEMPRA ENERGY TRADING
In December 1997, the company acquired Sempra Energy Trading (SET)
for $225 million. SET is a wholesale-energy trading company based in
Stamford, Conn. 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 expanded 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. As of December 31, 1999, SER has
invested $55 million in this 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. The plant is expected to be operational in the second
quarter of 2000.
SEMPRA ENERGY SERVICES
CES/Way International, a national leader in energy-service
performance contracting, was acquired in January 1998 and renamed
Sempra Energy Services in 1999. Headquartered in Houston, Sempra
Energy Services provides energy-efficiency services, including
energy audits, engineering design, project management, construction,
financing and contract maintenance.
4 SHORT-TERM BORROWINGS
PE has a $300 million multiyear credit agreement. SoCalGas has an
additional $400 million multiyear 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, 1999,
both bank lines of credit were unused. At December 31, 1998, PE had
$43 million of bank loans under the credit agreement, which was due
and paid in January 1999. SoCalGas' bank line of credit was unused.
SDG&E has $205 million of bank lines available to support commercial
paper and variable-rate, long-term debt. The credit agreements
expire at varying dates from 2000 through 2002 and bear interest at
various rates based on market rates and SDG&E's credit rating.
SDG&E's bank lines of credit were unused at both December 31, 1999,
and 1998.
In 1999, Sempra Energy Holdings (SEH), the intermediate holding
company for many of the company's nonutility subsidiaries, entered
into a $500 million credit agreement that expires in 2000.
Borrowings under the agreement bear interest at various rates based
on market rates and the credit rating of Sempra Energy. SEH's credit
agreement is available to support commercial paper. At December 31,
1999, SEH had $182 million of commercial paper outstanding.
5 LONG-TERM DEBT
- --------------------------------------------------------------------------------
December 31 (Dollars in millions) 1999 1998
- --------------------------------------------------------------------------------
LONG-TERM DEBT
First-mortgage bonds
7.625% June 15, 2002 $ 28 $ 28
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 68 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 10
Variable rates September 1, 2020 58 58
5.85% June 1, 2021 60 60
8.75% October 1, 2021 150 150
8.5% April 1, 2022 10 10
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 225 250
---------------
Total 1,434 1,462
Rate-reduction bonds 526 592
Debt incurred to acquire limited partnerships,
secured by real estate, at 6.8% to 9.0%,
payable annually through 2009 284 305
Various unsecured bonds at 5.67% to 8.75% or
at variable rates (3.1% to 3.3% at
December 31, 1999) payable from 2000 to 2028 495 577
Employee Stock Ownership Plan 130 130
Variable rate debt (9.75% at December 31, 1999)
payable 2001 and 2004 160 -
Capitalized leases 43 76
--------------
Total 3,072 3,142
--------------
Less:
Current portion of long-term debt 155 330
Unamortized discount on long-term debt 15 17
-------------
170 347
-------------
Total $2,902 $2,795
- -------------------------------------------------------------------------------
Excluding capital leases, which are described in Note 13, maturities
of long-term debt are $152 million in 2000, $320 million in 2001,
$234 million in 2002, $277 million in 2003, $175 million in 2004 and
$1.9 billion thereafter. SDG&E and SoCalGas have CPUC authorization
to issue an additional $738 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. SDG&E and SoCalGas may issue additional first-
mortgage bonds upon compliance with the provisions of their bond
indentures, which permit, among other things, the issuance of an
additional $1.4 billion of first-mortgage bonds as of December 31,
1999.
During 1999, the company retired $28 million of first-mortgage bonds
prior to scheduled maturity.
CALLABLE BONDS
At SDG&E's or SoCalGas' option, certain bonds may be called at a
premium. SoCalGas has no variable-rate bonds. SDG&E has $287 million
of variable-rate bonds that are callable at various dates within one
year. Of the company's remaining callable bonds, $55 million are
callable in the year 2000, $150 million in 2001, $204 million in
2002, $621 million in 2003, and
$8 million in 2006.
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.
The sizes of the rate-reduction bond issuances were set so as to
make the utilities neutral as to the 10-percent rate reduction, and
were based on a four-year period to recover stranded costs. Because
SDG&E recovered its stranded costs in only 18 months (due to the
greater-than-anticipated plant-sale proceeds), its bond proceeds
were greater than needed. Accordingly, SDG&E will return to its
customers over $400 million that it has collected or will collect
from its customers. The timing of the return will differ from the
timing of the collection, but the specific timing of the repayment
and the interest rate thereon are the subject of a CPUC proceeding
and are expected to be resolved in early 2000. This refund will not
affect SDG&E's net income, except to the extent that the interest
associated with the refund (12.63 percent if not reduced as a result
of the CPUC proceeding) differs from the return earned by the
company on the funds. The bonds and their repayment schedule are not
affected by this refund.
UNSECURED DEBT
Various long-term obligations totaling $495 million are unsecured.
Unsecured bonds totaling $124 million have variable-rate provisions.
DEBT OF EMPLOYEE STOCK OWNERSHIP PLAN (ESOP) AND TRUST (TRUST)
The Trust covers substantially all of Southern California Gas
Company's employees and is used to fund part of the retirement
savings plan. The Trust was assumed by Sempra Energy on October 1,
1999, and participation in the ESOP is being expanded to include
employees of SDG&E and other affiliates. In November 1999 the $130
million ESOP debt was refinanced using variable-rate (6.59% at
December 31, 1999) notes with a 15-year term. However, because the
company is required to make proportionate reductions in the debt
balance, the average life of the loan will be less than 10 years.
Interest on ESOP debt amounted to $6 million in each of 1999, 1998
and 1997. Dividends used for debt service amounted to $5 million in
1999 and 1998, and $3 million in 1997.
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, 1999, 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, 1999, are:
- --------------------------------------------------------------------------------
(Dollars in millions) Southwest
Project SONGS Powerlink
- --------------------------------------------------------------------------------
Percentage ownership 20 89
Utility plant in service $57 $217
Accumulated depreciation and amortization $25 $111
Construction work in progress $ 7 $ 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.
Certain substation equipment at SONGS 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 CPUC and other regulatory bodies.
The company's share of decommissioning costs for the SONGS units is
estimated to be $432 million in today's dollars, based on a cost
study completed in 1998. Cost studies are performed and updated
periodically by outside consultants. 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 owner of Unit
1 received the required regulatory approvals to begin
decommissioning Unit 1 in January 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 at
market value. These values reflect unrealized gains of $164 million
and $149 million at December 31, 1999, and 1998, 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 carrying value 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:
- --------------------------------------------------------------------------------
For the years ended December 31 1999 1998 1997
- --------------------------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Depreciation 7.0 7.5 6.8
State income taxes - net of federal income
tax benefit 6.6 7.4 6.7
Tax credits (14.9) (12.9) (5.7)
Charitable contribution of plant (4.4) - -
Other - net 1.9 (5.1) (1.7)
- --------------------------------------------------------------------------------
Effective income tax rate 31.2% 31.9% 41.1%
- --------------------------------------------------------------------------------
The components of income tax expense are as follows:
- --------------------------------------------------------------------------------
(Dollars in millions) 1999 1998 1997
- --------------------------------------------------------------------------------
CURRENT:
Federal $ 72 $278 $236
State 21 89 63
-----------------------
Total 93 367 299
-----------------------
DEFERRED:
Federal 79 (165) 1
State 15 (58) 7
-----------------------
Total 94 (223) 8
-----------------------
DEFERRED INVESTMENT
TAX CREDITS-NET (8) (6) (6)
----------------------
Total income tax expense $179 $138 $301
- --------------------------------------------------------------------------------
Accumulated deferred income taxes at December 31 result from the
following:
- --------------------------------------------------------------------------------
(Dollars in millions) 1999 1998
- --------------------------------------------------------------------------------
DEFERRED TAX LIABILITIES:
Differences in financial and tax bases of utility plant $ 842 $ 924
Regulatory balancing accounts 166 23
Regulatory assets 69 76
Partnership income 37 27
Other 121 71
----------------
Total deferred tax liabilities 1,235 1,121
----------------
DEFERRED TAX ASSETS:
Investment tax credits 84 88
General business tax credit carryforward 46 -
Comprehensive Settlement (see Note 14) 42 95
Postretirement benefits 69 76
Other deferred liabilities 98 102
Restructuring costs 51 42
Other 160 177
----------------
Total deferred tax assets 550 580
----------------
Net deferred income tax liability $ 685 $ 541
- --------------------------------------------------------------------------------
The net liability is recorded on the consolidated balance sheet as
follows:
- --------------------------------------------------------------------------------
(Dollars in millions) 1999 1998
- --------------------------------------------------------------------------------
Current liability (asset) $ 67 $ (93)
Non-current liability 618 634
--------------
Total $685 $541
- --------------------------------------------------------------------------------
The general business tax credit carryforwards expire in 2019.
The company has not provided for U.S. income taxes on foreign
subsidiaries' undistributed earnings ($49 million at December 31,
1999), which are expected to be reinvested indefinitely. It is not
possible to predict the amount of U.S. income taxes that might be
payable if these earnings are eventually repatriated.
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 merged with similar plans or modified, and numerous
participants have been transferred among plans of related entities.
In connection therewith, the company recorded a $66 million special
termination benefit in 1998.
PENSION AND OTHER POSTRETIREMENT BENEFITS
The company sponsors several qualified and nonqualified pension
plans and other postretirement benefit plans for its employees.
Effective March 1, 1999, the Pacific Enterprises Pension Plan merged
with the Sempra Energy Cash Balance Plan.
The following tables provide a reconciliation of the changes in the
plans' benefit obligations and the fair value of assets over the two
years, and a statement of the funded status as of each year end:
- --------------------------------------------------------------------------------
Pension Other Postretirement
Benefits Benefits
- --------------------------------------------------------------------------------
(Dollars in millions) 1999 1998 1999 1998
- --------------------------------------------------------------------------------
WEIGHTED-AVERAGE ASSUMPTIONS AS OF DECEMBER 31:
Discount rate 7.75% 6.75% 7.75% 6.75%
Expected return on plan assets 8.00% 8.50% 7.85% 8.50%
Rate of compensation increase 5.00% 5.00% 5.00% 5.00%
Cost trend of covered health-care charges - - 7.75%(1) 8.00%(1)
CHANGE IN BENEFIT OBLIGATION:
Net benefit obligation at January 1 $ 2,080 $ 2,117 $ 563 $ 531
Service cost 48 55 15 13
Interest cost 142 148 40 36
Plan participants' contributions - - 3 1
Plan amendments - 18 - -
Actuarial gains (147) (44) (44) -
Special termination benefits - 63 - 3
Gross benefits paid (161) (277) (22) (21)
-------------------------------------
Net benefit obligation at December 31 1,962 2,080 555 563
-------------------------------------
CHANGE IN PLAN ASSETS:
Fair value of plan assets at January 1 2,796 2,653 443 363
Actual return on plan assets 789 407 96 64
Employer contributions 3 13 28 36
Plan participants' contributions - - 3 1
Gross benefits paid (161) (277) (22) (21)
------------------------------------
Fair value of plan assets at December 31 3,427 2,796 548 443
------------------------------------
Funded status at December 31 1,465 716 (7) (120)
Unrecognized net actuarial gain (1,627) (926) (185) (107)
Unrecognized prior service cost 66 73 (12) (13)
Unrecognized net transition obligation 3 3 - -
------------------------------------
Net liability at December 31 $ (93) $ (134) $(204) $(240)
- -----------------------------------------------------------------------------
(1) Decreasing to ultimate trend of 6.50% in 2004.
The following table provides the components of net periodic benefit
cost (income) for the plans:
- ----------------------------------------------------------------------------------------------
Other
Pension Benefits Postretirement Benefits
- ----------------------------------------------------------------------------------------------
For the years ended December 31, 1999 1998 1997 1999 1998 1997
(Dollars in millions)
- ----------------------------------------------------------------------------------------------
Service cost $ 48 $ 55 $ 53 $ 15 $ 13 $ 15
Interest cost 142 148 144 40 36 35
Expected return on assets (206) (196) (178) (32) (24) (22)
Amortization of:
Transition obligation 1 1 1 2 2 2
Prior service cost 6 6 5 (1) (1) (1)
Actuarial (gain) loss (31) (23) (18) 2 - 1
Special termination benefit - 63 13 - 3 2
Settlement credit - (30) - - - -
Regulatory adjustment 17 - - 24 9 12
-------------------------------------------------
Total net periodic benefit cost (income) $ (23) $ 24 $ 20 $ 50 $ 38 $ 44
- ----------------------------------------------------------------------------------------------
The following table provides the amounts recognized on the Sempra
Energy balance sheet at December 31.
- ----------------------------------------------------------------------------------------------
Other Postretirement
Pension Benefits Benefits
- ----------------------------------------------------------------------------------------------
(Dollars in millions) 1999 1998 1999 1998
- ----------------------------------------------------------------------------------------------
Prepaid benefit cost $ 13 $ - $ - $ -
Accrued benefit cost (106) (125) (204) (240)
Additional minimum liability (18) (13) - -
Intangible asset 6 4 - -
Accumulated other comprehensive
income, pre-tax 12 - - -
----------------------------------------------
Net liability $ (93) $(134) $(204) $(240)
- ----------------------------------------------------------------------------------------------
Assumed health care cost trend rates have a significant effect on the
amounts reported for the health care plans. A one-percent 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 $10 $(9)
Effect on the health care component of
the accumulated postretirement
benefit obligation $76 $(69)
- ----------------------------------------------------------------------
Except for one nonqualified retirement plan, all pension plans had
plan assets in excess of accumulated benefit obligations. For that
one plan the projected benefit obligation and accumulated benefit
obligation were $67 million and $62 million, respectively, as of
December 31, 1999, and $55 million and $45 million, respectively, as
of December 31, 1998.
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
The company offers 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
one percent to 15 percent of their regular earnings. Employer
contributions, after one year of completed service, are made in
shares of company 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. The
employees' 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 employee stock ownership
plan referred to below. Contributions to the savings plans were $14
million in 1999, $14 million in 1998 and $11 million in 1997. The
fair value of company stock held by the savings plan was $391
million at December 31, 1999, and $566 million at December 31, 1998.
EMPLOYEE STOCK OWNERSHIP PLAN (ESOP)
All contributions to the Employee Stock Ownership Plan and Trust
(Trust) are made by the company; 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 2.9 million and 3.1 million
shares of Sempra Energy common stock, with fair values of $51.1
million and $77.9 million, at December 31, 1999, and 1998,
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 nonqualified 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 1999 and 1998, 85,400 shares and 102,640 shares, respectively, of
restricted company stock were awarded to officers. In 1997, Enova
awarded 75,000 shares to key executives. Each award is subject to
forfeiture after 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 company stock. Compensation expense for the issuance of
these restricted shares was approximately $1 million in 1999, $2
million in 1998 and $1 million in 1997.
In 1999 and 1998, Sempra Energy granted 3,372,400 stock options and
3,425,800 stock options, respectively. 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 dividend equivalents. 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 originally were
scheduled to vest annually over a service period
ranging from three to five years. Compensation expense (or reduction
thereof) for the stock option grants was ($13 million), $12 million
and $17 million in 1999, 1998 and 1997, respectively.
Had compensation cost for the stock-based compensation plans been
determined based on the fair value at the grant dates for awards
under those plans, consistent with the method of FASB Statement 123,
the company's net income (earnings per share) would have been $378
million ($1.59 per share), $285 million ($1.20 per share) and $439
million ($1.85 per share) for 1999, 1998 and 1997, respectively.
The plans permit the granting of dividend equivalents, which provide
grantees the opportunity to receive some or all of the cash
dividends that would have been paid on the shares since the grant
date, depending on the degree, if any, by which certain corporate
goals are met. For grants prior to July 1, 1998, payment of the
dividend equivalents is also contingent upon exercise of the options
and requires that the market value of the shares purchased exceeds
the option price.
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 DIVIDEND EQUIVALENTS
Shares Average Options
Under Exercise Exercisable
Option Price at Year End
- -------------------------------------------------------------------------------
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
Granted 1,451,100 21.00
Exercised (254,886) 17.32
Cancelled (99,677) 23.34
------------------------------------
December 31, 1999 4,693,197 $21.96 1,844,079
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
OPTIONS WITHOUT DIVIDEND EQUIVALENTS
Shares Average Options
Under Exercise Exercisable
Option Price at Year End
- -------------------------------------------------------------------------------
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
Granted 1,921,300 21.00
Exercised (12,781) 15.20
Cancelled (55,746) 23.25
------------------------------------
December 31, 1999 3,673,005 $22.43 809,056
- -------------------------------------------------------------------------------
Additional information on options outstanding at December 31, 1999,
is as follows:
- -------------------------------------------------------------------------------
OUTSTANDING OPTIONS
Number Average Average
Range of of Remaining Exercise
Exercise Prices Shares Life Price
- -------------------------------------------------------------------------------
$12.80-$16.12 502,164 4.44 $15.15
$16.79-$21.00 4,733,585 8.52 $20.45
$24.10-$31.00 3,130,453 8.06 $25.82
----------
8,366,202 8.10 $22.14
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
Exercisable Options
Number Average
Range of of Exercise
Exercise Prices Shares Price
- -------------------------------------------------------------------------------
$12.80-$16.12 502,164 $15.15
$16.79-$20.36 1,168,825 $18.89
$24.11-$31.00 982,146 $25.84
---------
2,653,135 $20.75
- -------------------------------------------------------------------------------
The fair value of each option grant (including dividend equivalents
where applicable) was estimated on the date of grant using the
modified Black-Scholes option-pricing model. Weighted average fair
values for options granted in 1999, 1998 and 1997 were $4.24, $8.20
and $5.23, respectively.
The assumptions that were used to determine these fair values are as
follows:
- -------------------------------------------------------------------------------
1999 1998 1997
- -------------------------------------------------------------------------------
Stock price volatility 19% 16% 18%
Risk-free rate of return 5.5% 5.6% 6.4%
Annual dividend yield 0%/6.11% 0%/5.27% 0%
Expected life 6 Years 6 Years 3.8 Years
- -------------------------------------------------------------------------------
The second yield percentages apply to the options that do not
include dividend equivalents.
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-term
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 $3.0 billion, respectively, at December 31,
1999, and $3.1 billion and $3.2 billion, respectively, at December
31, 1998. Included in long-term debt are SDG&E's rate-reduction
bonds. The carrying amounts and fair values of the bonds are $526
million and $511 million, respectively, at December 31, 1999, and
$592 million and $607 million, respectively, at December 31, 1998.
The carrying amounts and fair values of subsidiaries' preferred
stock are $204 million and $167 million, respectively, at December
31, 1999, and $204 million and $182 million, respectively, at
December 31, 1998. 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.
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-
rate 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, 1999, and 1998, 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 $1.3
million at December 31, 1999 ($3 million at December 31, 1998).
Additional information on this topic is included in Note 5.
ENERGY DERIVATIVES
Information on derivative financial instruments of SET is provided
below. The company uses energy derivatives for 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, 1999, 1998 and 1997, gains and losses
from natural gas futures contracts are not material to the company's
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 other market
makers as well as end users. 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, 1999, 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 also is affected by changes in volatility and liquidity
in markets in which these instruments are traded.
SET adjusts these derivatives to market each month with gains and
losses recognized in earnings. These instruments are included in the
Consolidated Balance Sheets as energy trading assets or liabilities.
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 revenue or expense,
whichever is appropriate, in the Consolidated Income Statements.
Sempra Energy guarantees many of SET's transactions.
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,
1999, 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
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 $ 24 $ 2 $ 26
AA 44 5 49
A 262 49 311
BBB 144 13 157
Below investment grade 84 32 116
Exchanges 37 1 38
--------------------------------
$595 $102 $697
- -------------------------------------------------------------------------------
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 1999 and 1998,
based on quarterly observation, for trading assets and trading
liabilities which are considered financial instruments with off-
balance-sheet risk, approximate $1,229 million and $1,033 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, 1999, and 1998, SET's energy trading assets and
trading liabilities approximate the following:
- -------------------------------------------------------------------------------
December 31 (Dollars in millions) 1999 1998
- -------------------------------------------------------------------------------
ENERGY TRADING ASSETS
Unrealized gains on swaps and forwards $1,244 $756
Due from commodity clearing organization and
clearing brokers 124 75
OTC commodity options purchased 108 45
Due from trading counterparties 63 30
---------------
Total $1,539 $906
- -------------------------------------------------------------------------------
ENERGY TRADING LIABILITIES
Unrealized losses on swaps and forwards $1,210 $740
Due to trading counterparties 82 35
OTC commodity options written 73 30
----------------
Total $1,365 $805
- -------------------------------------------------------------------------------
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. At December 31, 1999, the notional
amounts of SET's financial instruments are:
- ------------------------------------------------------------
(Dollars in millions) Total
- ------------------------------------------------------------
Forwards and commodity swaps $20,044
Futures and exchange options 1,021
Options purchased 1,790
Options written 1,784
-------
Total $24,639
- ------------------------------------------------------------
11 PREFERRED STOCK OF SUBSIDIARIES
- -------------------------------------------------------------------------------
PACIFIC ENTERPRISES
December 31 Call
(Dollars in millions except call price) Price 1999 1998
- -------------------------------------------------------------------------------
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 part of every series 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 Class A preferred stock are outstanding.
- -------------------------------------------------------------------------------
SOCALGAS
December 31 (Dollars in millions) 1999 1998
- -------------------------------------------------------------------------------
Not subject to mandatory redemption:
$25 par value, authorized 1,000,000 shares
6% Series, 28,134 and 28,664 shares
outstanding at December 31, 1999 and 1998 $ 1 $ 1
6% Series A, 783,032 shares outstanding 19 19
Without par value, authorized
10,000,000 shares 7.75% Series - -
--------------
$20 $20
- -------------------------------------------------------------------------------
None of SoCalGas' series of preferred stock is callable. All series
have one vote per share and cumulative preferences as to dividends.
- -------------------------------------------------------------------------------
SDG&E
December 31 Call
(Dollars in millions except call price) Price 1999 1998
- -------------------------------------------------------------------------------
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 type of
potential common stock at December 31, 1999, 1998 and 1997. The
reconciliation between basic and diluted EPS is as follows:
- -------------------------------------------------------------------------------
Income Shares Earnings
(in millions) (in thousands) Per Share
- -------------------------------------------------------------------------------
1999:
Basic $394 237,245 $1.66
Effect of dilutive stock options 308
-------------------------------------
Diluted $394 237,553 $1.66
- -------------------------------------------------------------------------------
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
- -------------------------------------------------------------------------------
This calculation excludes options covering 3.3 million shares for
1999 and 1998, and 0.2 million shares for 1997 for which the
exercise price was greater than the shares' market price.
The company is authorized to issue 750,000,000 shares of no-par-
value common stock and 50,000,000 shares of Preferred Stock.
Excluding shares held by the ESOP, there were 237,408,051 shares of
common stock outstanding at December 31, 1999, compared to
236,956,683 shares at December 31, 1998. 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 primarily from various Southwest
U.S. suppliers and are based on monthly spot-market prices. SoCalGas
has contracts with pipeline companies. These contracts expire at
various dates through the year 2006. In 1998, SoCalGas restructured
its long-term commodity purchase contracts with suppliers of
California offshore and Canadian gas. These new purchase contracts
expire at the end of 2003. SDG&E has long-term capacity contracts
with interstate pipelines which expire on various dates between 2007
and 2023. These agreements provide for payments of an annual
reservation charge. SoCalGas and SDG&E recover such fixed charges in
rates.
SDG&E had been involved in negotiations and litigation with four
Canadian suppliers concerning contract terms and prices related to
long-term natural gas supply contracts. In 1999, SDG&E settled with
the last of the four suppliers, terminating the contract. SDG&E
continues to purchase natural gas from one of the suppliers under
terms of the settlement agreement. SDG&E purchases natural gas on a
spot basis to fill any additional long-term pipeline capacity. SDG&E
intends to continue using the long-term pipeline capacity in other
ways as well, including the transport of replacement natural gas and
the release of a portion of this capacity to third parties.
In connection with the new natural gas franchise for Nova Scotia,
the company plans to build and operate a natural gas system
providing service to 78 percent of the 350,000 households in Nova
Scotia. Construction of the system is expected to begin in mid-2000.
See Note 3 for additional information.
At December 31, 1999, the future minimum payments under natural gas
contracts were:
- ------------------------------------------------------------------------
Storage and Natural
(Dollars in millions) Transportation Gas
- ------------------------------------------------------------------------
2000 $ 191 $425
2001 193 188
2002 195 194
2003 197 172
2004 197 -
Thereafter 511 -
-------------------
Total minimum payments $1,484 $979
- ------------------------------------------------------------------------
Total payments under the contracts were $1.3 billion in 1999 and
1998, and $1.4 billion in 1997.
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 2001. 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 2000 and 2025. Under
California's electric-industry restructuring law, which is described
in Note 14, the above-market cost of these contracts is recovered
from virtually all of SDG&E's customers. In general, the market
value of these contracts is recovered by bidding them into the
California Power Exchange (PX) and receiving revenue from the PX for
bids accepted.
At December 31, 1999, the estimated future minimum payments under
the long-term contracts were:
- -----------------------------------------------------------------
(Dollars in millions)
- -----------------------------------------------------------------
2000 $ 198
2001 180
2002 133
2003 133
2004 127
Thereafter 2,046
------
Total minimum payments $2,817
- -----------------------------------------------------------------
The payments 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 under the contracts were $251 million in 1999, $293
million in 1998 and $421 million in 1997.
LEASES
The company has leases (primarily operating) on real and personal
property expiring at various dates from 2000 to 2037. 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
and real property that are financed by long-term capital leases.
Property, plant and equipment includes $83 million at December 31,
1999, and $214 million at December 31, 1998, related to these
leases. The associated accumulated amortization is $39 million and
$127 million, respectively.
The minimum rental commitments payable in future years under all
noncancellable leases are:
- ------------------------------------------------------------------------
Operating Capitalized
(Dollars in millions) Leases Leases
- ------------------------------------------------------------------------
2000 $ 66 $ 29
2001 63 6
2002 65 6
2003 57 3
2004 51 2
Thereafter 335 4
----------------------
Total future rental commitment $637 50
Imputed interest (5% to 15%) (7)
---
Net commitment $ 43
- ------------------------------------------------------------------------
Rent expense totaled $108 million in 1999, $105 million in 1998 and
$137 million in 1997.
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 $70 million at December
31, 1999. These leases are reflected in the above table.
OTHER COMMITMENTS AND CONTINGENCIES
At December 31, 1999, commitments for capital expenditures,
including the purchase of gas turbines, were approximately $87
million.
ENVIRONMENTAL ISSUES
The company's operations are subject to federal, state and local
environmental laws and regulations governing hazardous wastes, air
and water quality, land use, solid waste disposal and the protection
of wildlife. Significant costs are incurred to operate the
facilities in compliance with these laws and regulations and these
costs 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 $1.5 million in 1999, $1 million in 1998 and $5
million in 1997, and are not expected to be significant during the
next five years due to the sale of SDG&E's fossil fuel power plants.
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.
As discussed in Note 14, restructuring of the California electric-
utility industry has changed the way utility rates are set and costs
are recovered. In 1998, the CPUC modified the Hazardous Waste
Collaborative mechanism by providing that electric generation-
related cleanup costs be eligible for transition-cost recovery. The
effect of this decision is that SDG&E's costs of compliance with
environmental regulations may not 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 $9.5 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 $36 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 12 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 $5
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.
The Nuclear Waste Policy Act of 1982 made the DOE responsible for
the disposal of nuclear fuel and other radioactive waste. However,
it is uncertain when the DOE will begin accepting nuclear fuel from
SONGS. Continued delays by the DOE can lead to increased cost of
disposal, which could be significant. If this occurs and the company
is unable to recover the increased costs from the federal government
or from its customers, the company's profitability from SONGS would
be adversely affected.
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, 1999, the aggregate unexpended amount of this
commitment was approximately $105 million. Capital expenditures for
underground conversions were $20 million in 1999, and $17 million in
1998 and 1997.
CONCENTRATION OF CREDIT RISK
The company maintains credit policies and systems to minimize
overall credit risk. These policies include, when applicable, 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
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 PX that serves as an independent 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. California's investor-
owned 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. Purchases from the PX/ISO are
included in purchased-power expenses and PX/ISO power revenues have
been netted therein on the Statements of Consolidated Income.
Revenues from the PX/ISO reflect sales to the PX/ISO commencing
April 1, 1998, at market prices of energy from SDG&E's power plants
and from long-term purchased-power contracts.
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 the utilities had
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. Outside of those exceptions, any
stranded costs not recovered through 2001 would 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 6.
In June 1999, SDG&E completed the recovery of its stranded costs,
other than the future above-market portion of qualifying facilities
and other purchased-power contracts that were in effect at December
31, 1995, and SONGS costs as described below, both of which will
continue to be collected in rates. Recovery of the other stranded
costs was affected by, among other things, the sale of SDG&E's
fossil power plants and combustion turbines during the quarter ended
June 30, 1999. The South Bay Power Plant sale to the San Diego
Unified Port District for $110 million was completed on April 23,
1999. Duke South Bay, a subsidiary of Duke Energy Power Services,
will manage the plant for the Port District. The sale of the Encina
Power Plant and 17 combustion-turbine generators to Dynegy Inc. and
NRG Energy Inc. for $356 million was completed on May 21, 1999.
SDG&E will operate and maintain both the South Bay and Encina
facilities for the new owners until April 2001 and May 2001,
respectively.
Stranded costs included the cost of SONGS as of December 31, 1995.
SDG&E retains ownership of its 20-percent interest in SONGS.
Subsequent SONGS costs are recoverable only from the sales of power
produced from SONGS, at rates previously fixed by the CPUC through
December 31, 2003, and as determined by the market thereafter. If
approved by the CPUC, SDG&E is planning to auction its interest in
SONGS. A major issue being addressed is how to handle the
decommissioning trust to ensure that adequate funding is available
at the time the plant is decommissioned.
AB 1890 required a 10-percent reduction of residential and small-
commercial customers' rates, beginning in January 1998, and provided
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.
The sizes of the rate-reduction bond issuances were set so as to
make the IOUs neutral as to the 10-percent rate reduction, and were
based on a four-year period to recover stranded costs. Because SDG&E
recovered its stranded costs in only 18 months (due to the greater-
than-anticipated plant-sale proceeds), the bond proceeds were
greater than needed. Accordingly, SDG&E will return to its customers
over $400 million that it has collected or will collect from its
customers. The timing of the return will differ from the timing of
the collection, but the specific timing of the repayment and the
interest rate thereon are the subject of a CPUC proceeding and are
expected to be resolved in early 2000. This refund will not affect
SDG&E's net income, except to the extent that the interest
associated with the refund (12.63 percent if not reduced as a result
of the CPUC proceeding) differs from the return earned by the
company on the funds to be refunded. The bonds and their repayment
schedule are unaffected by this refund.
AB 1890 also includes a rate freeze for all IOU customers. Beginning
in 1998, SDG&E's system-average rates were fixed at 9.43 cents per
kwh. The rate freeze would have stayed in place until January 1,
2002. However, in connection with completion of its stranded cost
recovery (described above), SDG&E filed with the CPUC for a
mechanism to structure electric rates after the end of the rate
freeze. SDG&E received approval to reduce base rates (the non-
commodity portion of rates) to all electric customers effective July
1, 1999. As a result base electric rates will decrease beyond the
original 10-percent rate reduction described above. The portion of
the electric rate representing the commodity cost is simply passed
through to customers and will fluctuate with the price of
electricity from the PX. Except for the interim protection mechanism
described below, customers will no longer be insulated from
commodity price fluctuations.
In April 1999, SDG&E filed an all-party settlement (including energy
service providers, the CPUC's Office of Ratepayer Advocates and the
Utility Consumers Action Network) detailing proposed implementation
plans for lifting the rate freeze. Included in the settlement is an
interim customer-protection mechanism for residential and small-
commercial customers that capped rates between July 1999 and
September 1999, regardless of how high the PX price had moved during
that period. The resulting undercollection (which amounted to less
than $1 million) is being recovered through a balancing-account
mechanism. A CPUC decision adopting the all-party settlement was
issued in May 1999 and became effective July 1, 1999. The interim
post-rate-freeze period runs until the CPUC issues its decision on
the pending legal and policy issues of ending the rate freeze. This
decision is expected during the second quarter of 2000. The decision
will address, among other things, a proposal by SDG&E that would
limit SDG&E's obligation to purchase from the PX to 80 percent of
the electricity required by its utility default customers, and to
establish an electric commodity performance-based regulation
mechanism, which would measure the company's effectiveness in
procuring electricity on behalf of its utility default commodity
customers and the administration of its above-market purchased-power
contracts.
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 in rates. 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 restructuring has been confined to
generation. Transmission and distribution have remained subject to
traditional cost-of-service regulation and performance-based
ratemaking. However, the CPUC is exploring the possibility of
opening up electric distribution to competition. During 2000, the
CPUC will consider whether any changes should be made in electric
distribution regulation. A CPUC staff report will be submitted
on this issue to the CPUC in the second quarter of 2000. SDG&E and
SoCalGas will actively participate in this effort.
On December 20, 1999, the FERC issued "Order 2000" concerning the
formation of Regional Transmission Organizations (RTOs). The rule
generally requires all public utilities that own, operate or control
interstate transmission to file by October 15, 2000, a proposal for
an RTO. Public utilities that are members of an existing, FERC-
approved regional entity, which includes SDG&E, must file by January
15, 2001. The rule states that RTOs will be operational by December
15, 2001. The FERC's order permits a number of different types of
RTOs, including nonprofit independent system operators, for-profit
transmission companies, or other approaches. The FERC also allows
flexibility so that an RTO can improve its structure, geographic
scope, market support and operations to meet market needs. It notes
that the FERC intends for RTOs to alleviate stress on the bulk power
system caused by changes in the structure of the industry; improve
efficiencies in transmission grid management through better pricing
and congestion management; improve grid reliability; remove
remaining opportunities for discriminatory transmission practices;
improve market performance; increase coordination among state
regulatory agencies; cut transaction costs; facilitate the success
of state retail access programs; and facilitate reduced regulation.
The order also specifies the required characteristics for each RTO,
including independence from market participants, and the functional
responsibilities required of each RTO. The order also provides
guidance on transmission pricing reforms. The identification of RTO
regions and formation of the RTOs will be subject to a collaborative
process. The impact of Order 2000 on SDG&E depends on the results of
this process and other implementation issues.
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's natural gas consumers.
In August 1998, California enacted a law prohibiting the CPUC from
enacting any natural gas-industry restructuring decision for core
(residential and small-commercial) customers prior to January 1,
2000. During the implementation moratorium, the CPUC held hearings
throughout the state and intends to give the legislature a draft
ruling before adopting a final market-structure policy. SDG&E and
SoCalGas have been actively participating in this effort and have
argued in support of competition intended to maximize benefits to
customers rather than to protect competitors.
In October 1999, the state of California enacted a law (AB 1421)
which requires that gas utilities provide "bundled basic gas
service" (including transmission, storage, distribution, purchasing,
revenue-cycle services and after-meter services) to all core
customers, unless the customer chooses to purchase gas from a
nonutility provider. The law prohibits the CPUC from further
unbundling of distribution-related gas services (including meter
reading and billing) and after-meter services (including leak
investigation, inspecting customer piping and appliances, pilot
relighting and carbon monoxide investigation) for most customers.
The objective is to preserve both customer safety and customer
choice.
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 plant in a market where a
utility already has a highly developed infrastructure.
The utilities' PBR mechanisms are in effect through December 31,
2002; however, the CPUC decision allows for the possibility that
changes to SoCalGas' mechanism could be adopted in its 1999 Biennial
Cost Allocation Proceeding decision, which is anticipated during the
second quarter of 2000. Each company's PBR mechanism is scheduled to
be updated at December 31, 2002, at which time it will be updated
for, among other things, changes in costs and volumes. Key elements
of the mechanisms 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
or awards if service quality exceeds set standards. Specifically,
the key elements of the mechanisms 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, SDG&E and SoCalGas were
authorized to earn 9.05 percent and 9.49 percent returns,
respectively, on their rate base. For 2000, their authorized returns
are 8.75 percent for SDG&E and 9.49 percent for SoCalGas.
*Base rates are indexed based on inflation less an estimated
productivity factor.
*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 related to
employee safety, electric reliability, customer satisfaction, and
call-center responsiveness. The SoCalGas mechanism authorizes
penalties of up to $4 million annually, or more in certain, limited
situations.
*The SoCalGas mechanism 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.
*Annual cost of capital proceedings are replaced by an automatic
adjustment mechanism if changes in certain indices exceed
established tolerances. The SoCalGas 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. The
SDG&E mechanism is triggered by a 6-month trailing average and a
100-basis-point change in interest rates. If this occurs, there
would be an automatic adjustment of rates for the change in the cost
of capital according to a formula which applies a percentage of the
change to various capital components.
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 permitted
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 revenues were governed by the Comprehensive Settlement
through July 31, 1999. This treatment is being replaced by the PBR
mechanism as adopted in the 1999 Biennial Cost Allocation Proceeding
(BCAP). The CPUC's proposed decision on the 1999 BCAP would allow
balancing account treatment for 75 percent of noncore revenues.
*The Gas Cost Incentive Mechanism (GCIM) for evaluating SoCalGas'
natural gas purchases substantially replaced the previous process of
reasonableness reviews. In December 1998 the CPUC extended the GCIM
program indefinitely.
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 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 1998 the CPUC approved GCIM-related shareholder awards to
SoCalGas totalling $13 million. In June 1999, SoCalGas filed its
annual GCIM application with the CPUC requesting an award of $8
million for the annual period ended March 31, 1999. A CPUC decision
is expected during the first quarter of 2000.
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 further charges 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 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, FERC is reviewing the
decision.
On November 4, 1999, the CPUC issued a decision on the 1996 BCAP,
shifting $88 million of pipeline surcharges from the pipeline
capacity relinquishments to noncore customers. The noncore customer
rate impact of the decision is mitigated by overcollections in the
regulatory accounts and will be reflected in the rates adopted in
the final 1999 BCAP 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 SoCalGas' Comprehensive Settlement
(discussed above), and the proposed end date aligns with the
expiration of the utilities' current PBRs. On January 11, 2000, the
CPUC issued a proposed decision adopting overall decreases in
natural gas revenues of $208 million for SoCalGas and $38 million
for SDG&E. A final CPUC decision is expected in the second quarter
of 2000.
COST OF CAPITAL
For 2000, 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 1999, 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 has changed the method of calculating the utility's
annual cost of capital. In June 1999, the CPUC adopted a 10.6
percent ROE and an 8.75 percent ROR for SDG&E's electric-
distribution and natural gas businesses. The electric-transmission
cost of capital is determined under a separate FERC proceeding.
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 nondiscrimination, 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, which
is described in Note 1.
15 SEGMENT INFORMATION
The company, primarily an energy services company, has three
separately managed reportable segments comprised of SoCalGas, SDG&E
and SET. The two utilities operate in essentially separate service
territories under separate regulatory frameworks and rate structures
set by the CPUC. 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,
Conn., and is engaged in wholesale trading and marketing of natural
gas, power and petroleum in the United States and Europe. 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 years ended December 31
(Dollars in millions) 1999 1998 1997
- -------------------------------------------------------------------------------
OPERATING REVENUES:
Southern California Gas $2,569 $2,427 $2,641
San Diego Gas & Electric 2,207 2,249 2,167
Sempra Energy Trading 450 110 -
Intersegment revenues (72) (59) (55)
All other 206 254 316
-------------------------
Total $5,360 $4,981 $5,069
-------------------------
INTEREST REVENUE:
Southern California Gas $ 16 $ 4 $ 1
San Diego Gas & Electric 40 31 4
Sempra Energy Trading 3 3 -
All other interest (26) 2 29
-------------------------
Total interest 33 40 34
Sundry income (loss) 42 (6) 12
-------------------------
Total other income $ 75 $ 34 $ 46
-------------------------
DEPRECIATION AND AMORTIZATION:
Southern California Gas $ 260 $ 254 $ 251
San Diego Gas & Electric
(See Note 14) 561 603 324
Sempra Energy Trading 23 13 -
All other 35 59 29
-------------------------
Total $ 879 $ 929 $ 604
-------------------------
INTEREST EXPENSE:
Southern California Gas $ 60 $ 80 $ 87
San Diego Gas & Electric 120 106 74
Sempra Energy Trading 15 5 -
All other 34 6 33
------------------------
Total $ 229 $ 197 $ 194
------------------------
INCOME TAX EXPENSE (BENEFIT):
Southern California Gas $ 182 $ 128 $ 178
San Diego Gas & Electric 126 142 219
Sempra Energy Trading (7) (9) -
All other (122) (123) (96)
-------------------------
Total $ 179 $ 138 $ 301
-------------------------
NET INCOME:
Southern California Gas $ 200 $ 158 $ 231
San Diego Gas & Electric 193 185 232
Sempra Energy Trading 19 (13) -
All other (18) (36) (31)
-------------------------
Total $ 394 $ 294 $ 432
-------------------------
- -------------------------------------------------------------------------------
At December 31, or for the years then ended
(Dollars in millions) 1999 1998 1997
- -------------------------------------------------------------------------------
ASSETS:
Southern California Gas $ 3,532 $ 3,834 $ 4,205
San Diego Gas & Electric 4,366 4,257 4,654
Sempra Energy Trading 1,829 1,225 846
All other 1,543 1,140 1,051
----------------------------
Total $11,270 $10,456 $10,756
----------------------------
CAPITAL EXPENDITURES:
Southern California Gas $ 146 $ 128 $ 159
San Diego Gas & Electric 245 227 197
Sempra Energy Trading 26 - -
All other 172 83 41
----------------------------
Total $ 589 $ 438 $ 397
----------------------------
GEOGRAPHIC INFORMATION:
Long-lived assets:
United States $ 5,857 $ 5,849 $ 5,904
Latin America 701 140 67
----------------------------
Total $ 6,558 $ 5,989 $ 5,971
----------------------------
OPERATING REVENUES:
United States $ 5,280 $4,974 $ 5,058
Latin America 16 7 11
Europe 62 - -
Canada 2 - -
----------------------------
Total $ 5,360 $ 4,981 $ 5,069
- -------------------------------------------------------------------------------
16 SEMPRA ENERGY HOLDINGS
On May 5, 1999, Sempra Energy and its wholly owned subsidiary,
Sempra Energy Holdings (SEH), jointly filed a shelf registration for
the public offering of common stock, preferred stock and debt
securities of Sempra Energy; debt securities of SEH; and certain
other securities to be offered on a delayed or continuous basis
pursuant to Rule 415 under the Securities Act of 1933. Any debt
securities issued by SEH would be fully guaranteed by Sempra Energy.
At December 31, 1999, no debt securities were outstanding.
Summarized financial information of SEH is provided below.
- -------------------------------------------------------------------------------
December 31 (Dollars in millions) 1999 1998
- -------------------------------------------------------------------------------
Current assets $2,271 $1,470
Noncurrent assets 1,317 544
Current liabilities 2,124 1,452
Noncurrent liabilities 502 140
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
For the Years ended December 31
(Dollars in millions) 1999 1998 1997
- -------------------------------------------------------------------------------
Operating revenues $672 $572 $526
Other income 63 14 -
Operating expenses 682 667 585
Net income (loss) 11 (54) (17)
- -------------------------------------------------------------------------------
17 SUBSEQUENT EVENT
On January 26, 2000, the company announced a tender offer to
purchase up to 36 million shares, or approximately 15 percent, of
outstanding common shares, and a reduction in its quarterly dividend
payable on shares of its common stock to $0.25 per share ($1.00
annualized rate) from its previous level of $0.39 per share ($1.56
annualized rate) commencing with the dividend payable in the second
quarter of 2000.
On February 23, 2000, the company completed the sale of $500 million
of long-term notes and $200 million of mandatorily redeemable trust
preferred securities to finance substantially all of the tender
offer.
On February 25, 2000, the tender offer was completed, with all 36
million shares sought being tendered.
QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarter ended
(Dollars in millions
except per-share amounts) March 31 June 30 September 30 December 31
- ----------------------------------------------------------------------------------------------
1999
Revenues and other income $1,191 $1,517 $1,254 $1,473
Operating expenses 971 1,380 1,006 1,276
---------------------------------------------------
Operating income $ 220 $ 137 $ 248 $ 197
---------------------------------------------------
Net income $ 99 $ 82 $ 108 $ 105
Average common shares outstanding (diluted) 237.4 237.5 237.8 237.6
Net income per common share (diluted) $ .42 $ .35 $ .45 $ .44
1998
Revenues and other income $1,348 $1,219 $1,143 $1,305
Operating expenses 1,164 1,135 940 1,147
---------------------------------------------------
Operating income $ 184 $ 84 $ 203 $ 158
---------------------------------------------------
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
- ----------------------------------------------------------------------------------------------
QUARTERLY COMMON STOCK DATA (UNAUDITED)
1999 1998
- ----------------------------------------------------------------------------------------------
First Second Third Fourth First Second Third Fourth
Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter
- ----------------------------------------------------------------------------------------------
Market price
High $26 $24 7/8 $23 3/16 $21 3/4 * * $28 7/8 $29 5/16
Low 19 1/8 18 1/2 20 7/16 17 1/8 * * 23 3/4 24 9/16
Dividends
declared(1) $0.39 $0.39 $0.39 $0.39 $0.32 $0.46 $0.39 $0.39
- ----------------------------------------------------------------------------------------------
*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.