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 1998 through 2000, and provides information
about the capital resources, liquidity and financial performance of
Sempra Energy and its subsidiaries (together referred to as "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 (SET) is engaged in the wholesale trading and marketing of
natural gas, power and petroleum. Sempra Energy International (SEI)
develops, operates and invests in energy-infrastructure systems and
power-generation facilities outside the United States. Sempra Energy
Resources (SER) develops power plants and natural gas storage,
production and transportation facilities within the United States.
Sempra Energy Financial (SEF) invests in limited partnerships, which
own 1,300 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
domestic energy-utility operations and other energy-related products
and services.
The uncertainties shaping California's electric industry and business
environment significantly affect the company's operations. A flawed
electric-industry restructuring plan, electricity supply/demand
imbalances, and legislative and regulatory responses, including a
temporary rate ceiling on the cost of electricity that SDG&E can pass
on to its small-usage customers on a current basis, have materially
and adversely affected the timing of revenue collections by SDG&E and
related cash flows. These, together with concerns with California
utility regulation generally and increased electricity cost
undercollections, have significantly impaired the company's access to
the capital markets and ability to obtain financing on commercially
reasonable terms. In addition, supply/demand imbalances are affecting
the price of natural gas in California more than in the rest of the
country because of California's dependence on natural gas fired
electric generation due to air-quality considerations. These recent
developments are continuing to change rapidly. Information as of March
7, 2001, the date this report was prepared, is found herein, primarily
under "California Utility Operations" and "Factors Influencing Future
Performance" and in Note 14 of the notes to Consolidated Financial
Statements.
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. Expenses incurred in connection with the PE/Enova
business combination were $70 million, aftertax, for the year ended
December 31, 1998. No significant expenses were incurred subsequently.
On February 22, 1999, the company and KN Energy, Inc. (KN) announced
that their respective boards of directors had approved the company's
acquisition of KN. On June 21, 1999, the company terminated its
agreement to acquire KN. Expenses incurred in connection with the KN
transaction were $11 million, aftertax, all in the year ended December
31, 1999.
In January 1998, PE and Enova jointly acquired CES/Way International,
Inc. (CES/Way), which was subsequently renamed Sempra Energy Services.
Expenses incurred in connection with the CES/Way acquisition were $15
million, aftertax, all in the year ended December 31, 1998.
The costs of the transactions discussed above and similar, smaller
transactions 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 California utility operations have historically been a
major source of liquidity. However, higher electric-commodity prices
and the inability of SDG&E to bill its small-usage customers on a
current basis for the full purchase cost of electricity due to
legislative actions, have resulted in a significant decrease in cash
flow available from SDG&E's operating activities in 2000. SDG&E had
incurred costs in excess of amounts which it can bill its customers on
a current basis, or "undercollected costs," of $447 million at
December 31, 2000, and $605 million at January 31, 2001. California
recently enacted legislation authorizing the California Department of
Water Resources (DWR) to purchase electricity for resale to all
California investor-owned utility retail end-use customers (including
customers of SDG&E), that is intended to halt or substantially slow
the growth of cost undercollections by SDG&E and other California
Investor-Owned Utilities (IOUs). Consequently, SDG&E believes that its
continued accumulation of undercollected costs will depend primarily
upon the effects of this legislation and other legislative and
regulatory developments. For additional discussion, see "California
Utility Operations" herein and Note 14 of the notes to Consolidated
Financial Statements.
Additional working capital and other requirements for the California
utilities are met primarily through the issuance of long-term debt.
Cash requirements at the utilities primarily consist of capital
expenditures for utility plant. The company's nonutility cash
requirements include additional investments in SET, SEI, SER and other
ventures. These requirements are met through the issuance of short-
term and long-term debt by the company or its subsidiaries, as well as
from cash flow generated from growing nonutility operations. Due to
the factors described herein and in Note 14 of the notes to
Consolidated Financial Statements regarding high electricity costs,
and the company's inability to bill its small-usage customers on a
current basis for the full cost of electricity purchases, management
is unable to determine whether the sources of funding described above
are sufficient to provide for all of the capital expenditures it
otherwise would intend to make, after funding its basic liquidity
needs, as described below.
Continued purchases by the DWR for resale to SDG&E's customers of
substantially all of the electricity that would otherwise be purchased
by SDG&E (as further discussed under "California Utility Operations"
herein) or dramatic decreases in wholesale electricity prices,
favorable action by the CPUC on SDG&E's electric rate surcharge
application discussed below and SDG&E's access to the capital markets
are required to manage and finance SDG&E's cost undercollections and
provide adequate liquidity.
Other company subsidiaries have significant receivables from the other
IOUs and from the California Power Exchange (PX) and the Independent
System Operator (ISO), which are described under "California Utility
Operations." The collection of these receivables may depend on
satisfactory resolution of the financial difficulties being
experienced by those IOUs as a result of the California electric
industry problem discussed above. In addition, the company's ability
to fund its subsidiaries' capital expenditure program and liquidity
requirements is significantly affected by the company's credit ratings
and related ability to obtain financing on commercially reasonable
terms.
CASH FLOWS FROM OPERATING ACTIVITIES
The decrease in cash flows from operating activities in 2000 was
primarily due to increased net trading assets, SDG&E's refunds to
customers for surplus rate-reduction-bond proceeds, SDG&E's cost
undercollections related to high electric-commodity prices and energy
charges in excess of the 6.5 cents/kWh ceiling in accordance with AB
265 (see "California Utility Operations" below and Note 14 of the
notes to Consolidated Financial Statements) and increased accounts
receivable. These factors were partially offset by higher
overcollected regulatory balancing accounts at SoCalGas, increased
accounts payable and lower income tax payments. The increases in
accounts receivable and accounts payable were primarily due to higher
sales volumes and higher prices for natural gas and purchased power.
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 in 1999 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 the absence of 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.
CASH FLOWS FROM INVESTING ACTIVITIES
For 2000, cash flows from investing activities included capital
expenditures for utility plant and investments in South America.
For 1999, cash flows from investing activities included proceeds from
the sale of SDG&E's two fossil power plants and combustion turbines.
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.
Capital Expenditures
Capital expenditures were $170 million higher in 2000 compared to 1999
due to investments in gas distribution facilities in the eastern
United States, Canada and Mexico, expenditures for gas turbines, and
improvements to SDG&E's electric distribution system and to the
California utilities' gas systems.
Capital expenditures were $151 million higher in 1999 compared with
1998 due to investments in gas distribution facilities in Mexico, a
gas system expansion at SDG&E and improvements to SDG&E's electric
distribution system.
Capital expenditures in 2001 are expected to be comparable to those of
2000. They will include, among other things, capital expenditures for
new power plant construction by SER and utility plant improvements.
Capital expenditures for power plant construction are intended to be
financed by debt issuances. The California utilities' capital
expenditures are intended to be financed primarily by operations and
debt issuances. SDG&E's capital expenditures are dependent on SDG&E's
ability to recover its electricity costs, including the balancing
account undercollections referred to above.
SER plans expenditures of up to $1.9 billion over the next five years
related to new power plant construction.
Investments
During the three years ended December 31, 2000, the company made
various investments and entered into several joint ventures. These
include, among others, SEI's additional investment in two Argentinean
natural gas utility holding companies (Sodigas Pampeana S.A. and
Sodigas Sur S.A.) of $147 million in October 2000. In August 2000,
Sempra Energy Solutions (SES) purchased Connectiv Thermal Systems' 50-
percent interests in both Atlantic-Pacific Las Vegas and Atlantic-
Pacific Glendale for $40 million, thereby acquiring full ownership of
these companies. In September 2000, the company acquired a majority
interest in Atlantic Electric and Gas in the United Kingdom for $8
million and, in July 1998, purchased a subsidiary of Consolidated
Natural Gas for $36 million.
In June 1999, SEI and PSEG Global (PSEG) jointly purchased 90 percent
of Chilquinta Energia S.A. (Energia) at a total cost of $840 million.
With the January 2000 joint purchase of an additional 9.75 percent,
the companies jointly and equally hold 99.98 percent of Energia. In
September 1999, the company and PSEG completed their acquisition of
47.5 percent of Luz del Sur S.A.A. SEI's share of the transaction was
$108 million. This acquisition, combined with the interest already
owned through Energia, increased the companies' total joint and equal
ownership to 84.5 percent of Luz del Sur S.A.A.
Sempra Energy's level of investments in the next few years may vary
substantially and will depend on the availability of financing and
business opportunities that are expected to provide desirable rates of
return.
See further discussion of international operations in "International
Operations" below and further discussion of investing activities in
Note 3 of the notes to Consolidated Financial Statements.
CASH FLOWS FROM FINANCING ACTIVITIES
Net cash was provided by financing activities in 2000 compared to
being used in 1999, due to the issuance of long-term and short-term
debt in 2000 (excluding that related to the repurchase of common
stock), and lower common stock dividends.
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.
Long-Term and Short-Term Debt
In 2000, the company issued $500 million of long-term notes and $200
million of mandatorily redeemable trust preferred securities to
finance the repurchase of 36.1 million shares of its outstanding
common stock. The company issued an additional $300 million of long-
term notes during 2000 to reduce short-term debt. The increase in
short-term debt primarily represents borrowings through Sempra Energy
Global Enterprises (Global), a holding company for many of the
company's subsidiaries, to finance the construction of gas
distribution systems by SEI; and borrowings by SET to finance
increased trading activities. Repayments on long-term debt in 2000
included $10 million of first-mortgage bonds, $65 million of rate-
reduction bonds and $51 million of unsecured debt. In addition, during
December 2000, $60 million of variable-rate industrial development
bonds were put back by the holders and subsequently remarketed in
February 2001 at a 7.0 percent fixed interest rate. Between January 24
and February 5, 2001, the company drew down substantially all ($1.3
billion) of its available credit facilities.
In 1999, repayments on long-term debt included $28 million of first-
mortgage bonds, $66 million of rate-reduction bonds and $82 million of
unsecured notes. The long-term debt issued in 1999 related primarily
to the purchase of Energia. See additional discussion in Note 3 of the
notes to Consolidated Financial Statements. The increase in short-term
debt primarily represents borrowing through Global to finance a
portion of SEI's acquisitions.
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.
Stock Purchases and Redemptions
As noted above, the company repurchased 36.1 million shares of its
common stock at a price of $20.00 per share in 2000. In March 2000,
the company's board of directors authorized the optional expenditure
of up to $100 million to repurchase additional shares of common stock
from time to time in the open market or in privately negotiated
transactions. Through December 31, 2000, the company acquired 162,000
shares under this authorization (all in July 2000). In 1998 the
company repurchased $1 million of common stock. There were no common
stock repurchases in 1999.
On February 2, 1998, SoCalGas redeemed all outstanding shares of its
7.75% 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 $244 million in 2000,
compared to $368 million in 1999 and $325 million in 1998. The
decrease in 2000 is due to a reduction in the quarterly dividend to
$0.25 per share ($1.00 annualized rate) from its previous level of
$0.39 per share ($1.56 annualized rate) and the previously mentioned
stock repurchase. The increase in 1999 was 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.
The payment of future dividends and the amount thereof are within the
discretion of the company's board of directors. The California Public
Utilities Commission's (CPUC) regulation of the California utilities'
capital structure limits to $924 million the portion of the company's
December 31, 2000, retained earnings that is available for dividends.
Capitalization
Total capitalization at December 31, 2000, was $7.1 billion. The debt-
to-capitalization ratio was 59 percent at December 31, 2000.
Significant changes in capitalization during 2000 include the increase
in long-term debt and the issuance of mandatorily redeemable trust
preferred securities to repurchase common stock.
Cash and Cash Equivalents
Cash and cash equivalents were $637 million at December 31, 2000. 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. However, as discussed above,
funds available for these purposes may be limited by SDG&E's ability
to recover from its customers on a current basis the full amount of
the high electricity prices.
If the impacts of the high electricity costs on a current basis and
the company's inability to bill customers for these costs are
favorably resolved, the company anticipates that operating cash
required in 2001 for common stock dividends and debt payments will be
provided by cash generated from operating activities and existing cash
balances. Cash required for capital expenditures will be provided by
cash generated both from operating activities and from long-term and
short-term debt issuances.
In addition to cash generated from ongoing operations, the company has
credit agreements that permit short-term borrowings of up to $2.2
billion, of which $566 million is outstanding at December 31, 2000,
and/or support its commercial paper. These agreements expire at
various dates through 2002. Because of the ramifications of the high
electric costs (as discussed in Notes 4 and 14 of the notes to
Consolidated Financial Statements), between January 24 and February 5,
2001, the company drew down substantially all ($1.3 billion) of its
available credit facilities.
In December 2000, Sempra Energy and certain affiliates filed shelf
registrations for public offerings of up to $2.3 billion of certain
securities guaranteed by Sempra Energy. As yet, no debt securities
have been issued under these registration statements. For additional
information see Notes 5 and 14 of the notes to Consolidated Financial
Statements.
RESULTS OF OPERATIONS
Seasonality
SDG&E's electric sales volume generally is higher in the summer due to
air-conditioning demands. Both California utilities' natural gas sales
volumes generally are higher in the winter due to heating demands,
although that difference is lessening as the use of natural gas to
fuel electric generation increases. Sales volumes of the company's
South American affiliates are also affected by seasonality, but the
timing of its increases and decreases is opposite of those in
California since the seasons are reversed in the Southern Hemisphere.
2000 Compared to 1999
Net income for 2000 increased to $429 million, or $2.06 per share of
common stock, from $394 million, or $1.66 per share of common stock,
in 1999.
The $35 million increase in net income was primarily due to higher
earnings achieved by SET and, to a lesser extent, SEI and SER. This
increase was partially offset by lower income generated from the
California utility operations and higher interest expense. The lower
income at the California utilities resulted primarily from the $50
million pretax write off described in Note 14 of the notes to
Consolidated Financial Statements. See additional discussion in
"California Utility Operations," "International Operations," "Trading
Operations" and "Other Operations" below.
For the fourth quarter of 2000, net income was $95 million, or $0.47
per share of common stock, compared with $105 million, or $0.44 per
share of common stock, for the fourth quarter of 1999. The decrease in
earnings was primarily attributable to increased interest costs and
income taxes, partially offset by higher earnings from the company's
trading and generation operations. The increase in earnings per share
was due to the decrease in weighted average shares for the fourth
quarter of 2000 in comparison to the corresponding period in 1999,
partially offset by the lower net income.
In 2000, book value per share decreased to $12.35 from $12.58 in 1999,
due to the repurchase of 36.1 million shares of common stock in
February 2000, at a price higher than book value.
1999 Compared to 1998
Net income for 1999 increased to $394 million, or $1.66 per share of
common stock, from $294 million, or $1.24 per share of common stock,
in 1998.
The increase was primarily attributable to higher net income at the
California utilities as a result of the business-combination costs in
1998, and increased earnings from SET and, to a lesser extent, from
SEF and SER.
In 1999, book value per share increased to $12.58 from $12.29 in 1998,
primarily due to the settlement of quasi-reorganization issues. See
additional discussion in Note 2 of the notes to Consolidated Financial
Statements.
CALIFORNIA UTILITY OPERATIONS
To understand the operations and financial results of SoCalGas and
SDG&E, it is important to understand the ratemaking procedures that
they 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 1996, California enacted legislation
restructuring California's investor-owned electric utility industry.
The legislation and related decisions of the CPUC were intended to
stimulate competition and reduce electric rates. The PX served as a
wholesale power pool and the ISO scheduled power transactions and
access to the transmission system.
A flawed electric-industry restructuring plan, electricity
supply/demand imbalances, and legislative and regulatory responses,
including the rate ceiling as described in "Factors Influencing Future
Performance" below, have materially and adversely affected the timing
of revenue collections by the company and related cash flows.
Additional legislation passed in early 2001, as well as future
legislation and regulatory actions concerning California's energy
crisis, could have a significant impact on SDG&E's future operations,
liquidity and financial results.
The natural gas industry experienced an initial phase of restructuring
during the 1980s by deregulating natural gas sales to noncore
customers. The CPUC currently is studying the issue of restructuring
for sales to core customers and, as mentioned above, supply/demand
imbalances are affecting the price of natural gas in California more
than in the rest of the country because of California's dependence on
natural gas fired electric generation due to air-quality
considerations.
In connection with restructuring of the electric and natural gas
industries, SDG&E and SoCalGas 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 these situations under "Factors
Influencing Future Performance" and in Note 14 of the notes to
Consolidated Financial Statements.
The tables below summarize the California utilities' natural gas and
electric volumes and revenues by customer class for the years ended
December 31, 2000, 1999 and 1998.
GAS SALES, TRANSPORTATION & EXCHANGE
(Dollars in millions,
volumes in billion cubic feet)
Transportation
Gas Sales & Exchange Total
Throughput Revenue Throughput Revenue Throughput Revenue
- -----------------------------------------------------------------------
2000:
Residential 284 $2,446 3 $13 287 $2,459
Commercial and
industrial 107 760 339 225 446 985
Utility electric
generation - - 373 130 373 130
Wholesale - - 25 18 25 18
----------------------------------------------------
391 $3,206 740 $386 1,131 3,592
Balancing accounts
and other (287)
Total $3,305
- -----------------------------------------------------------------------
1999:
Residential 313 $2,091 3 $ 10 316 $2,101
Commercial and
industrial 105 560 324 243 429 803
Utility electric
generation 18 7* 218 83 236 90
Wholesale - - 23 11 23 11
----------------------------------------------------
436 $2,658 568 $347 1,004 3,005
Balancing accounts
and other (94)
Total $2,911
- -----------------------------------------------------------------------
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
----------------------------------------------------
463 $2,814 499 $361 962 3,175
Balancing accounts
and other (423)
------
Total $2,752
- -----------------------------------------------------------------------
*This consists of the interdepartmental margin on SDG&E's sales to
its power plants prior to their sale in 1999.
ELECTRIC SALES
(Dollars in millions, volumes in million kWhs)
2000 1999 1998
Volumes Revenue Volumes Revenue Volumes Revenue
- ------------------------------------------------------------------------
Residential 6,304 $ 730 6,327 $ 663 6,282 $ 637
Commercial 6,123 747 6,284 592 6,821 643
Industrial 2,614 310 2,034 154 3,097 233
Direct access 3,308 99 3,212 118 964 44
Street and highway
lighting 74 7 73 7 85 8
Off-system sales 899 59 383 10 706 15
---------------------------------------------------
19,322 1,952 18,313 1,544 17,955 1,580
---------------------------------------------------
Balancing accounts
and other 232 274 285
---------------------------------------------------
Total 19,322 $2,184 18,313 $1,818 17,955 $1,865
- ------------------------------------------------------------------------
2000 Compared to 1999
Natural gas revenues increased from $2.9 billion in 1999 to $3.3
billion in 2000, primarily due to higher prices for natural gas in
2000 (see discussion of balancing accounts in Note 2 of the notes to
Consolidated Financial Statements) and higher utility electric
generation (UEG) revenues. The increase in UEG revenues was due to
higher demand for electricity in 2000 and the sale of SDG&E's fossil
fuel generating plants in the second quarter of 1999. Prior to the
plant sale, SDG&E's natural gas revenues from these plants consisted
of the margin from the sales. Subsequent to the plant sale, SDG&E gas
revenues consist of the price of the natural gas transportation
service since the sales now are to unrelated parties. In addition, the
generating plants receiving gas transportation from the California
utilities are operating at higher capacities than previously, as
discussed below.
Electric revenues increased from $1.8 billion in 1999 to $2.2 billion
in 2000. The increase was primarily due to higher sales to industrial
customers and the effect of higher electric commodity costs, partially
offset by the $50 million pretax charge at SDG&E for a potential
regulatory disallowance related to the acquisition of wholesale power
in the deregulated California market, and the decrease in base
electric rates (the noncommodity portion) from the completion of
stranded cost recovery. For 2000, SDG&E's electric revenues included
an undercollection of $447 million as a result of the 6.5-cent rate
cap. In January 2001, SDG&E filed with the CPUC for a temporary
electric surcharge to reduce the growing undercollection of electric
commodity costs. SDG&E is unable to predict the amount, if any, of the
request that the CPUC would grant, or when it would issue a decision.
The CPUC has deferred this proceeding pending resolution of the
broader issues related to the state-wide high costs. Additional
information concerning electric rates is described in "Factors
Influencing Future Performance" below and in Note 14 of the notes to
Consolidated Financial Statements.
The cost of natural gas distributed increased from $1.2 billion in
1999 to $1.6 billion in 2000. The increase was largely due to higher
prices for natural gas. Prices for natural gas have increased due to
the increased use of natural gas to fuel electric generation, colder
winter weather, and population growth in California. Under the current
regulatory framework, changes in core-market natural gas prices do not
affect net income, since the actual commodity cost of natural gas for
core customers is included in customer rates on a substantially
current basis.
The cost of electric fuel and purchased power increased from $0.5
billion in 1999 to $1.3 billion in 2000. The increase was primarily
due to the higher cost of electricity from the PX that has resulted
from higher demand for electricity and the shortage of power plants in
California, higher prices for natural gas used to generate electricity
(as described above), the sale of SDG&E's fossil fuel generating
plants and warmer weather in California. Additional information
concerning the recent supply/demand conditions is provided in Note 14
of the notes to Consolidated Financial Statements. Under the current
regulatory framework, changes in on-system prices normally do not
affect net income. See the discussions of balancing accounts and
electric revenues in Note 2 of the notes to Consolidated Financial
Statements.
PX/ISO power revenues have been netted against purchased-power
expense. In September 2000, as a result of high electricity costs the
CPUC authorized SDG&E to purchase up to 1,900 megawatts of power
directly from third-party suppliers under both short-term contracts
and long-term contracts. Subsequent to December 31, 2000, the state of
California authorized the DWR to purchase all of SDG&E's power
requirements not covered by its own generation or by existing
contracts. These and related events are discussed more fully in Note
14 of the notes to Consolidated Financial Statements.
Depreciation and amortization expense decreased from $0.8 billion in
1999 to $0.5 billion in 2000 and operating expenses decreased from
$1.2 billion in 1999 to $1.1 billion in 2000. The decreases were
primarily due to the 1999 sale of SDG&E's fossil fuel generating
plants.
1999 Compared to 1998
Natural gas revenues increased from $2.8 billion in 1998 to $2.9
billion in 1999. The increase was primarily due to lower
overcollections in 1999 and higher UEG revenues, partially offset by a
decrease in residential, commercial and industrial revenues. The
increase in UEG revenues was primarily due to the sale of SDG&E's
fossil fuel generating plants in the second quarter of 1999, as
explained above.
Electric revenues decreased from $1.9 billion in 1998 to $1.8 billion
in 1999. The decrease was primarily due to a temporary decrease in
base electric rates following the completion of SDG&E's stranded cost
recovery as noted above and as more fully described in Note 14 of the
notes to Consolidated Financial Statements.
The company's cost of natural gas distributed increased from $1.0
billion in 1998 to $1.2 billion in 1999. The increase was largely due
to an increase in the average price of natural gas purchased.
Depreciation and amortization expense decreased from $0.9 billion in
1998 to $0.8 billion in 1999. The decrease was primarily due to the
mid-1999 completion of the accelerated recovery of generation assets.
Operating expenses decreased from $1.3 billion in 1998 to $1.2 billion
in 1999. The decrease was primarily due to the $117 million of
business-combination costs in 1998.
TRADING OPERATIONS
SET, a leading natural gas, petroleum and power marketing firm
headquartered in Stamford, Connecticut, was acquired on December 31,
1997. In addition to the transactions described below in "Market
Risk," SET also enters into long-term structured transactions, such as
the one supporting the SEI agreement referred to below in
"International Operations." For the year ended December 31, 2000, SET
recorded net income of $155 million compared to net income of $19
million in 1999. The increase in net income in 2000 compared to 1999
was primarily due to increased volatility in the U.S. natural gas and
electric power markets, and higher trading volumes. In addition,
European crude oil contributed significantly to SET's 2000 earnings.
In 1998, a net loss of $13 million was recorded. The improvement in
net income in 1999 compared to 1998 is due to greater penetration of
all customer segments, resulting in higher volumes traded.
INTERNATIONAL OPERATIONS
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 Argentina, Canada, Chile,
Mexico, Peru and Uruguay, and is pursuing other projects in Latin
America.
In February 2001, SEI announced plans to construct a $350 million,
600-megawatt power plant near Mexicali, Mexico. Construction of the
project, named Termoelectrica de Mexicali, is expected to begin in
mid-2001, with completion anticipated by mid-2003.
As noted above in "Investments," SEI increased its investment in
Sodigas Pampeana S.A. and Sodigas Sur S.A. in 2000 and 1998. These
natural gas distribution companies serve 1.3 million customers in
central and southern Argentina, respectively, and have a combined
sendout of 650 million cubic feet per day. See further discussion at
Note 3 of the notes to Consolidated Financial Statements.
In June 2000, SEI, PG&E Corporation and Proxima Gas S.A de C.V.
announced an agreement to construct a $230 million, 215-mile natural
gas pipeline which will extend from Arizona to the Rosarito Pipeline
south of Tijuana. The pipeline will have the capacity to transport 500
million cubic feet per day of natural gas. Construction of the
pipeline is anticipated to begin in early 2002. Agreements have been
signed for more than half of the capacity on the pipeline, with
natural gas expected to begin flowing by September 2002.
As previously discussed, during 1999 and 2000 SEI and PSEG jointly
purchased Energia and 84.5 percent of Luz del Sur S.A.A. See Note 3 of
the Notes to Consolidated Financial Statements for a discussion of the
acquisitions of Energia and Luz del Sur S.A.A.
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 has invested $23 million and 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 began in the
fourth quarter of 2000, with delivery of natural gas expected to begin
in the second quarter of 2001.
SEI owns 60 percent of Distribuidora de Gas Natural de Mexicali, S. de
R.L. de C.V. (DGN-Mexicali), that holds the first license awarded to a
private company to build and operate a natural gas distribution system
in Mexico. It plans to 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,
SEI's predecessor acquired ownership of a 16-mile transmission
pipeline serving 20 industrial customers. SEI plans to 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 plans to 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 through a joint
venture. As noted above, SET acted as the trading company for the
supply of natural gas. 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 was completed in mid-2000 at a cost of $38 million, and SEI
began supplying gas to the Rosarito Power Plant in July 2000. 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 2000 was $33 million
compared to net income of $2 million and a net loss of $4 million for
1999 and 1998, respectively. The increase in net income for 2000 was
primarily due to the first full year of results from Luz del Sur
S.A.A. and Energia, and improved operating results at Sodigas Pampeana
S.A. and Sodigas Sur S.A. The increase in net income for 1999 was
primarily due to income from Energia, and lower operating costs and
increased sales (as a result of colder weather) in Argentina.
OTHER OPERATIONS
SER develops power plants for the competitive market, as well as
owning natural gas storage, production and transportation assets. SER
is planning to develop 5,000 to 10,000 megawatts of generation within
the next decade in the Southwest, the Northeast, the Gulf States and
the Midwest. SER is a 50-percent partner in El Dorado Energy, a 500-
megawatt power plant located near Las Vegas, Nevada, which began
commercial operation in 2000. SER recorded net income of $33 million,
$5 million and $8 million in 2000, 1999 and 1998, respectively. The
increase in net income for 2000 is primarily due to earnings from the
El Dorado power plant.
SEF invests as a limited partner in affordable-housing properties and
alternative-fuel projects. SEF's portfolio includes 1,300 properties
throughout the United States. These investments are expected to
provide income tax benefits (primarily from income tax credits) over
10-year periods. SEF recorded net income of $28 million in both 2000
and 1999, and $20 million in 1998. SEF's future investment policy is
dependent on the company's future income tax position.
SES provides integrated energy-related products and services to
commercial, industrial, government, institutional and consumer
markets. SES recorded net losses of $23 million, $11 million and $24
million in 2000, 1999 and 1998, respectively. These losses are
primarily attributable to ongoing start-up costs.
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 subsidiaries and
interest on regulatory balancing accounts, increased to $106 million
in 2000 from $50 million in 1999. The increase was primarily due to
improved equity earnings from unconsolidated subsidiaries of SER and
SEI, and higher balancing-account interest. Other income increased in
1999 to $50 million from $15 million in 1998, primarily due to
increased equity earnings from SEI's unconsolidated subsidiaries.
Interest Expense
Interest expense for 2000 increased to $286 million in 2000 from $229
million in 1999. The increase was primarily due to interest expense
incurred on long-term debt issued in connection with the company's
common stock repurchase, as described in Notes 5 and 12 of the notes
to the Consolidated Financial Statements, and on short-term commercial
paper borrowings made in 2000. Interest expense for 1999 increased to
$229 million from $197 million in 1998. This increase was primarily
due to interest expense on the excess rate-reduction bond liability,
as discussed in "Factors Influencing Future Performance" below.
Income Taxes
Income tax expense was $270 million, $179 million and $138 million for
2000, 1999 and 1998, respectively. The effective income tax rates were
38.6 percent, 31.2 percent and 31.9 percent for the same years. The
increase in income tax expense for 2000 compared to 1999 was due to
the increase in income before taxes combined with lower charitable
contributions. (During 1999 SDG&E made a charitable contribution to
the San Diego Unified Port District in connection with the sale of the
South Bay generating plant.) The increase in income tax expense for
1999 compared to 1998 was due to the increase in income before taxes,
partially offset by the charitable contribution to the San Diego
Unified Port District. The effective income tax rates for 1998 and
1999 are not significantly different because the effect of leasing and
other activities in 1998 was comparable to that of the 1999 charitable
contribution.
FACTORS INFLUENCING FUTURE PERFORMANCE
Base results of the company in the near future will depend primarily
on the results of the California utilities, while earnings growth and
volatility will depend primarily on changes in the utility industry
and activities at SEI, SET, SER and other businesses. The factors
influencing future performance are summarized below.
Electric Industry Restructuring and Electric Rates
In 1996, California enacted legislation restructuring California's
investor-owned electric utility industry. The legislation and related
decisions of the CPUC were intended to stimulate competition and
reduce electric rates. During the transition period, utilities were
allowed to charge frozen rates that were designed to be above current
costs by amounts assumed to provide a reasonable opportunity to
recover the above-market "stranded" costs of investments in electric-
generating assets. The rate freeze was to end for each utility when it
completed recovery of its stranded costs, but no later than March 31,
2002. SDG&E completed recovery of its stranded costs in June 1999 and,
with its rates no longer frozen, SDG&E's overall rates were initially
lower, but became subject to fluctuation with the actual cost of
electricity purchases.
A number of factors, including supply/demand imbalances, resulted in
abnormally high electric-commodity costs beginning in mid-2000 and
continuing into 2001. During the second half of 2000, the average
electric-commodity cost was 15.51 cents/kWh (compared to 4.15
cents/kWh in the second half of 1999). This caused SDG&E's monthly
customer bills to be substantially higher than normal. In response,
legislation enacted in September 2000 imposed a ceiling of 6.5
cents/kWh on the cost of electricity that SDG&E may pass on to its
small-usage customers on a current basis. Customers covered under the
commodity rate ceiling generally include residential, small-commercial
and lighting customers. The ceiling, which was retroactive to June 1,
2000, extends through December 31, 2002 (December 31, 2003 if deemed
by the CPUC to be in the public interest). As a result of the ceiling,
SDG&E is not able to pass through to its small-usage customers on a
current basis the full purchase cost of electricity that it provides.
The legislation provides for the future recovery of undercollections
in a manner (not specified in the decision) intended to make SDG&E
whole for the reasonable and prudent costs of procuring electricity.
In the meantime, the amount paid for electricity in excess of the
ceiling (the undercollected costs) is accumulated in an interest-
bearing balancing account. The undercollection, included in Regulatory
Assets on the Consolidated Balance Sheets, was $447 million at
December 31, 2000, and $605 million at January 31, 2001, and is
expected to increase to $700 million in March 2001, and remain
constant thereafter, except for interest, if the DWR continues to
purchase SDG&E's power requirements, as more fully described in
"California Utility Operations" herein. The rate ceiling has
materially and adversely affected SDG&E's revenue collections and its
related cash flows and liquidity. SDG&E has fully drawn upon
substantially all of its short-term credit facilities. Its ability to
access the capital markets and obtain additional financing has been
substantially impaired by the financial distress being experienced by
other California investor-owned utilities as well as by lender
uncertainties concerning California utility regulation generally and
the rapid growth of utility cost undercollections. Continued purchases
by the DWR for resale to SDG&E's customers of substantially all of the
electricity that would otherwise be purchased by SDG&E or dramatic
decreases in wholesale electricity prices, favorable action by the
CPUC on SDG&E's electric rate surcharge application and SDG&E's access
to the capital markets are required to manage and finance SDG&E's cost
undercollections and provide adequate liquidity.
Consequently, in January 2001, SDG&E filed an application with the
CPUC requesting a temporary electric-rate surcharge of 2.3 cents/kWh,
subject to refund, beginning March 1, 2001. The surcharge is intended
to provide SDG&E with continued access to financing on commercially
reasonable terms by managing the growth of SDG&E's undercollected
power costs. The CPUC has deferred this proceeding, pending resolution
of the broader issues related to the statewide high costs. In response
to the situation facing the California IOUs, the state of California
passed legislation to permit its governor to negotiate with the IOUs
to acquire their transmission assets. SDG&E has been having
discussions with representatives of the governor concerning the
possibility of such a transaction and what its terms might be. There
is no assurance that these discussions will result in a sale of the
transmission assets. SDG&E would consider entering into such a
transaction only if the sales price and conditions of the sale and of
future operating arrangements are reasonable.
See additional discussion in Note 14 of the notes to Consolidated
Financial Statements.
Natural Gas Restructuring and Gas Rates
The natural gas industry experienced an initial phase of restructuring
during the 1980s by deregulating natural gas sales to noncore
customers. In January 1998, the CPUC 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. A CPUC decision is expected in 2001.
In October 1999, the state of California enacted a law that requires
natural gas utilities to 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.
Supply/demand imbalances have increased the price of natural gas in
California more than in the rest of the country because of
California's dependence on natural gas fired electric generation due
to air-quality considerations. The average price of natural gas at the
California/Arizona (CA/AZ) border was $6.25/mmbtu in 2000, compared
with $2.33/mmbtu in 1999. On December 11, 2000, the average spot-
market price at the CA/AZ border reached a record high of
$56.91/mmbtu. Underlying the high natural gas prices are several
factors, including the increase in natural gas usage for electric
generation, colder winter weather and reduced natural gas supply
resulting from historically low storage levels, lower gas production
and a major pipeline rupture. In December 2000, SDG&E and SoCalGas
filed separately with the Federal Energy Regulatory Commission (FERC)
for a reinstitution of price caps on short-term interstate capacity to
the CA/AZ border and between the interstate pipelines and California's
local distribution companies, effective until March 31, 2001. The FERC
responded by issuing extensive data requests, but has not otherwise
acted on the requests.
A recent lawsuit, which seeks class-action certification, alleges that
Sempra Energy, SoCalGas, SDG&E and El Paso Energy Corp. acted to drive
up the price of natural gas for Californians by agreeing to stop a
pipeline project that would have brought new and cheaper natural gas
supplies into California. Sempra Energy believes the allegations are
without merit.
Electric-Generation Assets
El Dorado Energy (El Dorado), of which SER is a 50-percent partner,
began commercial operations in May 2000 at its 500-megawatt power
plant near Las Vegas, Nevada, generating energy to serve 350,000
households as discussed in "Other Operations" above. Its proximity to
existing natural gas pipelines and electric transmission lines allows
El Dorado to actively compete in the deregulated electric-generation
market.
In December 2000, SER obtained approvals from the appropriate state
agencies to construct the Elk Hills Power Project and the Mesquite
Power Plant. The Elk Hills Power Project is a 550-megawatt power plant
project near Bakersfield, California, in which SER will have a 50
percent interest. It is scheduled to begin construction in the second
quarter of 2001 and to be operating in 2002. The plant is expected to
generate energy to serve 350,000 households. The Mesquite Power Plant
is a 1,200-megawatt project located near Phoenix, Arizona, which is
scheduled to begin construction in the second quarter of 2001 and to
be operating in 2003. The plant is expected to generate energy to
serve 700,000 households.
Construction of the Termoelectrica de Mexicali power plant is expected
to begin in mid-2001, with completion anticipated by mid-2003. The
600-megawatt power plant will be located near Mexicali, Mexico.
See additional discussion of these projects in Note 3 of the notes to
Consolidated Financial Statements.
Investments and Joint Ventures
As discussed in "International Operations" above, the company has
various investments, joint ventures and projects that will impact the
company's future performance. These include, among other things, SEI's
increased investment in two Argentinean natural gas utility holding
companies (Sodigas Pampeana S.A. and Sodigas Sur S.A.), SEI's
investment in Energia and Luz del Sur S.A.A., construction of the Baja
California pipelines, SEI's investments in several natural gas
distribution systems in Mexico, the franchise awarded to SAG to build
and operate a natural gas distribution system in Nova Scotia, and the
investment in Atlantic Electric and Gas in the United Kingdom. See
additional discussion of these investments, joint ventures and
projects in Note 3 of the notes to Consolidated Financial Statements.
Performance-Based Regulation (PBR)
To promote efficient operations and improved productivity and to move
away from reasonableness reviews and potential 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
"California Utility Operations" above and in Note 14 of the notes to
Consolidated Financial Statements.
Allowed Rate of Return
For 2001, 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,
the same as in 2000 and 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,
respectively, prior to July 1, 1999. Either utility can earn more than
the authorized rate by controlling costs below approved levels or by
achieving favorable results in certain areas, such as incentive
mechanisms. In addition, earnings are affected by changes in sales
volumes, except for the majority of SoCalGas' core sales.
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.
However, that effort is now increasing. Due to the ever-increasing
financial pressures experienced by SDG&E in the current electric
industry environment, in January 2001 SDG&E launched a cash-
conservation plan, which includes sales of nonessential property,
containment of new hiring, reduction of outside contractors, and
deferral of information system and construction projects that do not
affect the core reliability of service to customers. While the company
is not planning employee layoffs at this time, all expenses and
activities not directly tied to the maintenance of essential services
and safety will continue to be scrutinized and deferred if possible.
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 environmental issues faced by the company occur at the
California utilities. Utility capital costs to comply with
environmental requirements are generally recovered through the
depreciation components of customer rates. The utilities' customers
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 manner
is remote.
The environmental issues currently facing the company or resolved
during the latest three-year period include investigation and
remediation of the California utilities' manufactured-gas sites (21
completed as of December 31, 2000, and 24 to be completed), asbestos
and other cleanup at SDG&E's former fossil fuel 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 (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 credit-worthy firms and major exchanges. The use
of these instruments exposes the company to market and credit risks
which, at times, may be concentrated with certain counterparties.
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 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 since 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. See
the "Interest-Rate Risk" section below for additional information
regarding the company's use of interest-rate swap and cap agreements.
The 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 can 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
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 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. As of December 31, 2000,
the VaR on the company's fixed-rate long-term debt and SET's portfolio
were $314 million and $7.3 million, respectively, as more fully
discussed below.
The following discussion of the company's primary market-risk
exposures as of December 31, 2000, includes 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.
At December 31, 2000, the notional amount of interest-rate swap
transactions associated with the regulated operations totaled $45
million. See Note 10 of the notes to Consolidated Financial Statements
for further information regarding this swap transaction.
The VaR on the company's fixed-rate long-term debt is estimated at
approximately $314 million as of December 31, 2000, 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, and operating
and regulatory environments of each affiliate.
Sempra Energy Trading
SET 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 the risk
incurred in a one-day holding period. As of December 31, 2000, the
diversified VaR of SET's portfolio was $7.3 million, compared to $2.6
million at December 31, 1999. The increased VaR results from the
increased volatility and activity in the market in 2000 compared to
1999.
SDG&E and SoCalGas
The California utilities 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, 2000, the total VaR of the California 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 prospective
counterparties' financial condition (including credit ratings),
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.
Almost all of the California utilities' accounts receivable and
significant portions of the accounts receivable of the company's other
subsidiaries are with customers located in California and, therefore,
potentially affected by the high costs of electricity and natural gas
in California, as described above in "Factors Influencing Future
Performance" and in Note 14 of the notes to Consolidated Financial
Statements.
Foreign-Currency-Rate Risk
Foreign-currency-rate risk exists by the 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, 2000, the
company had not entered into any such arrangements.
NEW ACCOUNTING STANDARDS
Effective January 1, 2001, the company adopted Statement of Financial
Accounting Standards (SFAS) No. 133 "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS No. 138,
"Accounting for Certain Derivative Instruments and Certain Hedging
Activities." As amended, SFAS 133 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 adoption of this new standard on January 1, 2001, did not have a
material impact on the company's earnings. However, $1.1 billion in
current assets, $1.1 billion in noncurrent assets, $6 million in
current liabilities, and $238 million in noncurrent liabilities were
recorded as of January 1, 2001, in the Consolidated Balance Sheet as
fixed-priced contracts and other derivatives. Due to the regulatory
environment in which SoCalGas and SDG&E operate, regulatory assets and
liabilities were established to the extent that derivative gains and
losses are recoverable or payable through future rates. As such, $1.1
billion in current regulatory liabilities, $1.1 billion in noncurrent
regulatory liabilities, $5 million in current regulatory assets, and
$238 million in noncurrent regulatory assets were recorded as of
January 1, 2001, in the Consolidated Balance Sheet. The ongoing
effects will depend on future market conditions and the company's
hedging activities.
In December 1999, the Securities and Exchange Commission (SEC) issued
Staff Accounting Bulletin (SAB) 101 - Revenue Recognition. SABs are
not rules issued by the SEC. Rather, they represent interpretations
and practices followed by SEC staff in administering the disclosure
requirements of the federal securities laws. SAB 101 provides guidance
on the recognition, presentation and disclosure of revenue in
financial statements; it does not change the existing rules on revenue
recognition. SAB 101 sets forth the basic criteria that must be met
before revenue should be recorded. Implementation of SAB 101 was
required by the fourth quarter of 2000 and had no effect on the
company's consolidated financial statements.
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, including statements
regarding SDG&E's ability to finance undercollected costs on
reasonable terms and retain its financial strength, estimates of
future accumulated undercollected costs, and plans to obtain future
financing. The words "estimates," "believes," "expects,"
"anticipates," "plans," "intends," "may," "would" and "should" or
similar expressions, or discussions of strategy or of plans are
intended to identify forward-looking statements. Forward-looking
statements are not guarantees of performance. They involve risks,
uncertainties and assumptions. Future results may differ materially
from those expressed in these forward-looking statements.
Forward-looking statements are necessarily based upon various
assumptions involving judgments with respect to the future and other
risks, including, among others, local, regional, national and
international economic, competitive, political, legislative and
regulatory conditions; actions by the CPUC, the California
Legislature, the DWR and the FERC; the financial condition of other
investor-owned utilities; inflation rates and interest rates; energy
markets, including the timing and extent of changes in commodity
prices; weather conditions; business, regulatory and 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 SEC.
FIVE YEAR SUMMARY
At December 31 or for the years ended December 31
(Dollars in millions except per-share amounts)
2000 1999 1998 1997 1996
- ----------------------------------------------------------------------------
REVENUES AND OTHER INCOME
California utility revenues:
Gas $ 3,305 $ 2,911 $ 2,752 $ 2,964 $ 2,710
Electric 2,184 1,818 1,865 1,769 1,591
Other operating revenues 1,548 631 364 336 195
Other income 106 50 15 39 24
----------------------------------------------------
Total $ 7,143 $ 5,410 $ 4,996 $ 5,108 $ 4,520
----------------------------------------------------
Income before interest and
income taxes $ 985 $ 802 $ 629 $ 927 $ 927
Net income $ 429 $ 394 $ 294 $ 432 $ 427
Net income per
common share:
Basic $ 2.06 $ 1.66 $ 1.24 $ 1.83 $ 1.77
Diluted $ 2.06 $ 1.66 $ 1.24 $ 1.82 $ 1.77
Dividends declared per
common share $ 1.00 $ 1.56 $ 1.56 $ 1.27 $ 1.24
Pretax income/revenue 9.9% 10.7% 8.7% 14.5% 16.2%
Return on common equity 15.7% 13.4% 10.0% 14.7% 14.9%
Effective income tax rate 38.6% 31.2% 31.9% 41.1% 41.3%
Dividend payout ratio:
Basic 48.5% 94.0% 125.8% 69.4% 70.1%
Diluted 48.5% 94.0% 125.8% 69.8% 70.1%
Price range of
common shares $24 7/8-$16 3/16 $26-$17 1/8 $29 5/16-$23 3/4 * *
AT DECEMBER 31
Current assets $ 6,425 $ 3,015 $ 2,458 $ 2,761 $ 1,592
Total assets $ 15,612 $11,124 $10,456 $10,756 $ 9,762
Current liabilities $ 7,467 $ 3,236 $ 2,466 $ 2,211 $ 1,572
Long-term debt (excludes
current portion) $ 3,268 $ 2,902 $ 2,795 $ 3,175 $ 2,704
Shareholders' equity $ 2,494 $ 2,986 $ 2,913 $ 2,959 $ 2,930
Common shares outstanding
(in millions) 201.9 237.4 237.0 235.6 240.0
Book value per
common share $ 12.35 $ 12.58 $ 12.29 $ 12.56 $ 12.21
Price/earnings ratio 11.3 10.5 20.5 * *
Number of meters (in thousands):
Natural gas 5,807 5,726 5,639 5,551 5,501
Electricity 1,238 1,218 1,192 1,178 1,164
- ----------------------------------------------------------------------------
*Not presented as the formation of Sempra Energy was not completed
until June 26, 1998.
Statement of Management's Responsibility
for Consolidated Financial Statements
The consolidated financial statements have been prepared by management
in accordance with generally accepted accounting principles. The
integrity and objectivity of these financial statements and the other
financial information in the Annual Report, including the estimates
and judgments on which they are based, are the responsibility of
management. The financial statements have been audited by Deloitte &
Touche LLP, independent auditors 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 control which it believes is
adequate to provide reasonable, but not absolute, assurance that
assets are properly safeguarded, that transactions are executed in
accordance with management's authorization and are properly recorded
and that the accounting records may be relied on for the preparation
of the consolidated financial statements, and for the prevention and
detection of fraudulent financial reporting. The concept of reasonable
assurance recognizes that the cost of a system of internal control
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
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 believes that the company's
system of internal control is adequate to provide assurance that the
accompanying financial statements present fairly the company's
financial position and results of operations.
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 of independent
directors, to assist in fulfilling its oversight responsibilities for
management's conduct of the company's financial reporting processes.
The audit committee meets regularly to discuss financial reporting,
internal controls and auditing matters with management, the company's
internal auditors and independent auditors, and recommends to the
board of directors any appropriate response to those discussions. The
audit committee recommends for approval by the full board the
appointment of the independent auditors. The independent auditors and
the internal auditors periodically meet alone with the audit committee
and have free access to the audit committee at any time.
/S/ NEAL E. SCHMALE /S/ FRANK H. AULT
Neal E. Schmale Frank H. Ault
Executive Vice President and Vice President and Controller
Chief Financial Officer
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, 2000 and
1999, and the related statements of consolidated income, cash flows
and changes in shareholders' equity for each of the three years in the
period ended December 31, 2000. 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 auditing standards
generally accepted in the United States of America. 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, 2000 and 1999, and the results of
their operations and their cash flows for each of the three years in
the period ended December 31, 2000 in conformity with accounting
principles generally accepted in the United States of America.
/S/ DELOITTE & TOUCHE LLP
San Diego, California
January 26, 2001 (February 27, 2001 as to Notes 3, 4, 5 and 14)
STATEMENTS OF CONSOLIDATED INCOME
For the years ended December 31
(Dollars in millions, except per-share amounts) 2000 1999 1998
---- ---- ----
Revenues and Other Income
California utility revenues:
Natural gas $ 3,305 $ 2,911 $ 2,752
Electric 2,184 1,818 1,865
Other operating revenues 1,548 631 364
Other income 106 50 15
---- ---- ----
Total 7,143 5,410 4,996
---- ---- ----
Expenses
Cost of natural gas distributed 1,599 1,164 954
Electric fuel and net purchased power 1,326 536 437
Operating expenses 2,464 1,837 1,853
Depreciation and amortization 563 879 929
Franchise payments and other taxes 180 181 182
Preferred dividends of subsidiaries 11 11 12
Trust preferred distributions by subsidiary 15 - -
---- ---- ----
Total 6,158 4,608 4,367
---- ---- ----
Income before interest and income taxes 985 802 629
Interest 286 229 197
---- ---- ----
Income before income taxes 699 573 432
Income taxes 270 179 138
---- ---- ----
Net income $ 429 $ 394 $ 294
---- ---- ----
Weighted-average number of shares outstanding:
Basic* 208,155 237,245 236,423
Diluted* 208,345 237,553 237,124
Net income per share of common stock (basic) $ 2.06 $ 1.66 $ 1.24
Net income per share of common stock (diluted) $ 2.06 $ 1.66 $ 1.24
Common dividends declared per share $ 1.00 $ 1.56 $ 1.56
*In thousands of shares
See notes to Consolidated Financial Statements.
CONSOLIDATED BALANCE SHEETS
At December 31
(Dollars in millions) 2000 1999
---- ----
ASSETS
Current assets:
Cash and cash equivalents $ 637 $ 487
Accounts receivable - trade 994 428
Accounts and notes receivable - other 213 124
Income taxes receivable 24 144
Energy trading assets 4,083 1,539
Inventories 145 147
Other 329 146
---- ----
Total current assets 6,425 3,015
---- ----
Investments and other assets:
Regulatory assets 1,174 549
Nuclear-decommissioning trusts 543 551
Investments 1,288 1,164
Other assets 456 451
---- ----
Total investments and other assets 3,461 2,715
---- ----
Property, plant and equipment:
Property, plant and equipment 11,889 11,127
Less accumulated depreciation and amortization (6,163) (5,733)
---- ----
Total property, plant and equipment - net 5,726 5,394
---- ----
Total assets $15,612 $ 11,124
---- ----
See notes to Consolidated Financial Statements.
At December 31
(Dollars in millions)
2000 1999
---- ----
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Short-term debt $ 568 $ 182
Accounts payable - trade 1,162 492
Accounts payable - other 117 54
Energy trading liabilities 3,619 1,365
Dividends and interest payable 124 154
Regulatory balancing accounts - net 830 346
Deferred income taxes 110 67
Current portion of long-term debt 368 155
Other 569 421
---- ----
Total current liabilities 7,467 3,236
---- ----
Long-term debt 3,268 2,902
---- ----
Deferred credits and other liabilities:
Customer advances for construction 56 72
Postretirement benefits other than pensions 152 147
Deferred income taxes 826 615
Deferred investment tax credits 101 106
Deferred credits and other liabilities 844 856
---- ----
Total deferred credits and other liabilities 1,979 1,796
---- ----
Preferred stock of subsidiaries 204 204
---- ----
Mandatorily redeemable trust preferred securities 200 -
---- ----
Commitments and contingent liabilities (Notes 3 and 13)
SHAREHOLDERS' EQUITY
Common stock 1,420 1,966
Retained earnings 1,162 1,101
Deferred compensation relating to ESOP (39) (42)
Accumulated other comprehensive income (loss) (49) (39)
---- ----
Total shareholders' equity 2,494 2,986
---- ----
Total liabilities and shareholders' equity $15,612 $11,124
---- ----
See notes to Consolidated Financial Statements.
STATEMENTS OF CONSOLIDATED CASH FLOWS
For the years ended December 31
(Dollars in millions) 2000 1999 1998
---- ---- ----
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 429 $ 394 $ 294
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 563 879 929
Portion of depreciation arising from sales of
generating plants - (303) -
Application of balancing accounts to stranded costs - (66) (86)
Deferred income taxes and investment tax credits 258 86 (229)
Equity in (income) losses of unconsolidated
subsidiaries and joint ventures (62) 5 19
Customer refunds paid (628) - -
Other - net (88) (61) (161)
Net change in other working capital components 410 254 557
---- ---- ----
Net cash provided by operating activities 882 1,188 1,323
---- ---- ----
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment (759) (589) (438)
Investments and acquisitions of subsidiaries (243) (639) (191)
Net proceeds from sales of generating plants - 466 -
Other - net 78 (27) (50)
---- ---- ----
Net cash used in investing activities (924) (789) (679)
---- ---- ----
CASH FLOWS FROM FINANCING ACTIVITIES
Common stock dividends (244) (368) (325)
Repurchase of common stock (725) - (1)
Sale of common stock 12 3 35
Issuance of trust preferred securities 200 - -
Redemption of preferred stock - - (75)
Issuances of long-term debt 813 160 75
Payment on long-term debt (238) (270) (431)
Increase (decrease) in short-term debt - net 386 139 (311)
Other (12) - (1)
---- ---- ----
Net cash provided by (used in) financing activities 192 (336) (1,034)
---- ---- ----
Increase (decrease) in cash and cash equivalents 150 63 (390)
Cash and cash equivalents, January 1 487 424 814
---- ---- ----
Cash and cash equivalents, December 31 $ 637 $ 487 $ 424
---- ---- ----
See notes to Consolidated Financial Statements.
For the years ended December 31
(Dollars in millions)
2000 1999 1998
---- ---- ----
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 $(655) $188 $ 90
Net trading assets (290) (73) (71)
Income taxes 120 (171) 22
Regulatory balancing accounts 522 303 417
Other current assets (181) (23) 12
Accounts payable 733 25 77
Other current liabilities 161 5 10
---- ---- ----
Net change in other working capital components $410 $254 $557
---- ---- ----
SUPPLEMENTAL DISCLOSURE OF
CASH FLOW INFORMATION
Interest payments, net of amounts capitalized $297 $281 $211
Income tax payments, net of refunds $104 $168 $366
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING
AND FINANCING ACTIVITIES
Liabilities assumed for real estate investments $ - $ 34 $ 36
See notes to Consolidated Financial Statements.
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
For the years ended December 31, 2000, 1999 and 1998
(Dollars in millions) Deferred Accumulated
Compensation Other Total
Comprehensive |Common Retained Relating Comprehensive Shareholders'
Income | Stock Earnings to ESOP Income (Loss) Equity
- ------------------------------------------------------------------------------------------
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 10 | 10 10
Pension (7)| (7) (7)
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
Net income $429 | 429 429
Comprehensive income adjustment: |
Foreign-currency translation |
Losses (2)| (2) (2)
Available-for-sale securities (10)| (10) (10)
Pension 2 | 2 2
Comprehensive income $419 |
Common stock dividends |
declared | (201) (201)
Sale of common stock | 11 11
Repurchase of common stock | (558) (167) (725)
Long-term incentive plan | 1 1
Common stock released |
from ESOP | 3 3
- ------------------------------------------------------------------------------------------
Balance at December 31, 2000 $1,420 $1,162 $ (39) $ (49) $2,494
==========================================================================================
See notes to Consolidated Financial Statements.
Notes to Consolidated Financial Statements
Note 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.
Note 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 for the California utilities consist of deliveries to
customers and the changes in regulatory balancing accounts. The
amounts included in regulatory balancing accounts at December 31,
2000, represent net payables of $463 million and $367 million for
SoCalGas and SDG&E, respectively. The corresponding amounts at
December 31, 1999, were net payables of $154 million and $192 million
for SoCalGas and SDG&E, respectively.
Prior to 1998, fluctuations in California 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, previous
overcollections recorded in SDG&E's applicable balancing accounts were
applied to recovery of prior generation costs (as described in Note
14), 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 the
California utilities' 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, electricity, petroleum and petroleum products. 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.
Other subsidiaries recognize revenue on a mark-to-market basis, as
energy is delivered to customers or as installations of customer
projects progress.
Regulatory Assets
Regulatory assets include SDG&E's undercollected electric-commodity
costs accumulated due to the temporary rate ceiling imposed in mid-
2000. Regulatory assets also include unrecovered premiums on early
retirement of debt, postretirement benefit costs, deferred income
taxes recoverable in rates and other expenditures that the utilities
expect to recover in future rates. See Note 14 for additional
information on the rate ceiling, industry restructuring and other
regulatory matters.
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, 2000, were $77 million of
materials and supplies ($67 million in 1999), and $68 million of
natural gas and fuel oil ($80 million in 1999). 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, 2000, were:
natural gas operations $7.2 billion, electric distribution $2.7
billion, electric transmission $0.8 billion, and other electric $0.4
billion. The corresponding amounts at December 31, 1999, were: natural
gas operations $7.1 billion, electric distribution $2.5 billion,
electric transmission $0.7 billion, and other electric $0.4 billion.
Accumulated depreciation and decommissioning of natural gas and
electric utility plant in service at December 31, 2000, were $4.1
billion and $2.0 billion, respectively, and at December 31, 1999, were
$3.8 billion and $1.9 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 2000, 1999 and 1998, respectively
were: natural gas operations 4.29, 4.32, 4.32, electric distribution
4.67, 4.69, 4.49, electric transmission 3.21, 3.50, 3.31, and other
electric 8.33, 8.21, 6.29. See Note 14 for discussion of the sale of
generation facilities and industry restructuring. The remaining cost
amounts ($0.8 billion at December 31, 2000,and $0.4 billion at
December 31, 1999) consist of various items of property at 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, 2000, and 1999,
include $162 million and $165 million, respectively, 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
Comprehensive income includes 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 translation adjustments, minimum pension
liability adjustments and unrealized gains and losses on marketable
securities that are classified as available-for-sale. At December 31,
1999, the company had one such investment, which increased in value
during 1999. In October 2000, this investment was sold. These changes
are reflected 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 were added to shareholders' equity at that
time. Other liabilities established in connection with discontinued
operations and the quasi-reorganization will be resolved in future
years. Management believes the provisions 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.
Basis Of Presentation
Certain prior-year amounts have been reclassified to conform to the
current year's presentation.
New Accounting Standards
Effective January 1, 2001, the company adopted Statement of Financial
Accounting Standards (SFAS) No. 133 "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS No. 138,
"Accounting for Certain Derivative Instruments and Certain Hedging
Activities." As amended, SFAS 133 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 exposure.
The adoption of this new standard on January 1, 2001, did not have a
material impact on the company's earnings. However, $1.1 billion in
current assets, $1.1 billion in noncurrent assets, $6 million in
current liabilities, and $238 million in noncurrent liabilities were
recorded as of January 1, 2001, in the Consolidated Balance Sheet as
fixed-priced contracts and other derivatives. Due to the regulatory
environment in which SoCalGas and SDG&E operate, regulatory assets and
liabilities were established to the extent that derivative gains and
losses are recoverable or payable through future rates. As such, $1.1
billion in current regulatory liabilities, $1.1 billion in noncurrent
regulatory liabilities, $5 million in current regulatory assets, and
$238 million in noncurrent regulatory assets were recorded as of
January 1, 2001, in the Consolidated Balance Sheet. The ongoing
effects will depend on future market conditions and the company's
hedging activities.
In December 1999, the Securities and Exchange Commission (SEC) issued
Staff Accounting Bulletin (SAB) 101 - Revenue Recognition. SABs are
not rules issued by the SEC. Rather, they represent interpretations
and practices followed by SEC staff in administering the disclosure
requirements of the federal securities laws. SAB 101 provides guidance
on the recognition, presentation and disclosure of revenue in
financial statements; it does not change the existing rules on revenue
recognition. SAB 101 sets forth the basic criteria that must be met
before revenue should be recorded. Implementation of SAB 101 was
required by the fourth quarter of 2000 and had no effect on the
company's consolidated financial statements.
Note 3. ACQUISITIONS AND JOINT VENTURES
Sempra Energy International (SEI)
SEI is involved in several investments, joint ventures and projects.
In October 2000, SEI increased its existing investment in two
Argentinean natural gas utility holding companies (Sodigas Pampeana
S.A. and Sodigas Sur S.A.) from 21.5 percent to 43 percent by
purchasing an additional interest for $147 million. In June 2000, SEI,
PG&E Corporation and Proxima Gas S.A de C.V. announced a joint
agreement to construct a $230 million, 215-mile natural gas pipeline
which will extend from Arizona to the Rosarito Pipeline south of
Tijuana.
In June 1999, SEI and PSEG Global (PSEG) each purchased a 50-percent
interest in Chilquinta Energia S.A. (Energia). SEI invested $260
million for the purchase of stock and refinanced $160 million of
Energia's long-term debt outstanding. In September 1999, SEI and PSEG
completed their acquisition of 47.5 percent of the outstanding shares
of Luz del Sur S.A.A., a Peruvian electric company. SEI's share of the
transaction was $108 million in cash. Combined with the 37 percent
already owned through Energia, the companies' total joint ownership of
Luz del Sur S.A.A. increased to 84.5 percent. 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 invested
$23 million in 2000.
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. SEI owns
interests of 60 and 95 percent in the DGN-Mexicali and DGN-Chihuahua
projects, respectively. In addition, SEI was awarded a 30year license
to build and operate, through its subsidiary, DGN de La Laguna
Durango, a natural gas distribution system in the La Laguna-Durango
zone in north-central Mexico. Through 2000, DGN-Mexicali, DGN-
Chihuahua and DGN de La Laguna Durango have invested $18 million, $38
million and $18 million, respectively.
In August 1998, SEI was awarded a 10-year agreement by the Mexican
Federal Electric Commission to provide a complete energy-supply
package for a power plant in Rosarito, Baja California through a joint
venture. SET acted as the trading company for the supply of natural
gas. 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 Rosarito pipeline
was completed in mid-2000 at a cost of $38 million.
In February 2001, SEI announced plans to construct a $350 million,
600-megawatt power plant near Mexicali, Mexico. Construction is
expected to begin in mid-2001, with completion anticipated by mid-
2003.
Sempra Energy Trading (SET)
In April 2000, SET invested $4 million in Utility.com, the world's
first Internet utility company. In July 1998, SET purchased CNG Energy
Services Corporation, a subsidiary of Pittsburgh-based Consolidated
Natural Gas Company, for $36 million.
Sempra Energy Resources (SER)
In December 2000, SER obtained approvals from the appropriate state
agencies to construct the Elk Hills Power Project and the Mesquite
Power Plant. The Elk Hills Power Project is a $360 million, 550-
megawatt power plant near Bakersfield, California. Mesquite Power is a
$630 million, 1200-megawatt project located near Phoenix, Arizona. In
mid-2000, El Dorado Energy, a partnership between SER and Reliant
Energy Power Generation, completed construction of a $280 million,
500-megawatt merchant power plant near Las Vegas, Nevada.
Sempra Energy Solutions (SES)
In August 2000, SES purchased Connectiv Thermal Systems' 50-percent
interests in Atlantic-Pacific Las Vegas and Atlantic-Pacific Glendale
for $40 million, thereby acquiring full ownership of these companies.
In January 1998, SES completed the acquisition of CES/Way
International (renamed Sempra Energy Services in 1999).
Note 4. SHORT-TERM BORROWINGS
At December 31, 2000, SoCalGas had a $200 million credit agreement,
which was available to support commercial paper. At December 31, 2000,
and 1999, SoCalGas' lines of credit were unused. On February 9, 2001,
the agreement expired and was replaced on February 27, 2001, with a
$170 million, one-year agreement. This agreement bears interest at
various rates based on market rates and SoCalGas' credit rating.
At December 31, 2000, SDG&E had $285 million of bank lines available
to support commercial paper and variable-rate long-term debt. The
credit agreements expire at varying dates in mid-2001, but $200
million of the then outstanding borrowings may be extended at SDG&E's
option to a term maturity of an additional year. Any debt under the
lines would 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, 2000, and 1999.
At December 31, 2000, Sempra Energy Global Enterprises (Global),
formerly Sempra Energy Holdings, the intermediate holding company for
many of the company's subsidiaries, had a $1.2 billion credit
agreement that expires in September 2001 and is extendable at Global's
option for an additional year. Borrowings under the agreement bear
interest at various rates based on market rates and the credit rating
of Sempra Energy. Global's credit agreement is available to support
commercial paper and variable-rate, long-term debt. Borrowings and the
commercial paper are guaranteed by Sempra Energy. Global had $401
million and $182 million of commercial paper outstanding at December
31, 2000, and 1999, respectively.
Between January 24 and February 5, 2001, the company drew down
substantially all ($1.3 billion) of the above credit facilities.
SET has $499 million in various uncommitted lines of credit that
expire at varying dates in 2001 and bear interest at various rates
based on market rates and the credit rating of SET. At December 31,
2000, SET had $165 million in short-term borrowings outstanding.
Note 5. LONG-TERM DEBT
December 31 (Dollars in millions) 2000 1999
- ----------------------------------------------------------------------------------
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 68
5.9% September 1, 2018 93 93
6.1% and 6.4% September 1, 2018 and 2019 118 118
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 165 225
9.625% April 15, 2020 - 10
---------------
Total 1,364 1,434
Rate-reduction bonds, various rates (payable annually through 2007) 461 526
Debt incurred to acquire limited partnerships, secured by real
estate, at 6.8% to 9.0% payable annually through 2009 233 284
Notes payable, 6.95% and 7.95%, payable in 2005 and 2010 800 -
Various unsecured bonds at 5.67% to 6.38% or at variable rates (3.7%
to 4.1% at December 31, 2000) payable from 2001 to 2028 467 495
Employee Stock Ownership Plan, at variable rates
(6.80% at December 31, 2000) payable from 2001 to 2015 130 130
Variable rate debt (10.20% at December 31, 2000) payable
from 2008 to 2011 160 160
Capitalized leases 37 43
---------------
Total 3,652 3,072
---------------
Less:
Current portion of long-term debt 368 155
Unamortized discount on long-term debt 16 15
---------------
384 170
---------------
Total $3,268 $2,902
- ----------------------------------------------------------------------------------
Excluding capital leases, which are described in Note 13, maturities
of long-term debt are $368 million in 2001, $234 million in 2002, $277
million in 2003, $100 million in 2004, $94 million in 2005 and $2.5
billion thereafter. Although holders of variable-rate bonds may elect
to redeem them prior to scheduled maturity, for purposes of
determining the maturities listed above, since redeemed bonds are
remarketed and are backed by long-term lines of credit, it is assumed
the bonds will be held to maturity. SDG&E has CPUC authorization to
issue an additional $938 million in short-term or long-term debt (see
discussion under "Recent Shelf Registrations" below) and SoCalGas has
CPUC authorization to issue an additional $455 million in long-term
debt.
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 $2.2
billion of first-mortgage bonds as of December 31, 2000, subject to
CPUC authorization (see discussion under "Recent Shelf Registrations"
below).
During May 2000, the company called $10 million of first-mortgage
bonds prior to scheduled maturity. During December 2000, $60 million
of variable-rate first-mortgage bonds were put back by the holders and
subsequently remarketed on February 1, 2001, at a 7.0 percent fixed
interest rate.
Callable Bonds
At the company's option, certain bonds may be called at a premium,
including $227 million of variable-rate bonds that are callable at
various dates in 2001. Of the company's remaining callable bonds, $195
million are callable in 2001, $204 million in 2002 and $621 million in
2003.
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 investor-owned utilities (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
sale proceeds were greater than needed. Accordingly, during the third
quarter of 2000, SDG&E returned to its customers, via a combination of
cash refunds and billing credits, $388 million of surplus bond
proceeds in accordance with a June 8, 2000 CPUC decision. The bonds
and their repayment schedule are not affected by this refund.
Unsecured Debt
Various long-term obligations totaling $1.3 billion are unsecured at
December 31, 2000. In February 2000, the company issued $500 million
of long-term 7.95 percent notes due in 2010 to partially finance the
self-tender offer described in Note 12. In December 2000, the company
issued an additional $300 million in long-term 6.95 percent notes due
in 2005 in order to reduce short-term debt. Unsecured bonds totaling
$124 million have variable-rate provisions. In July 2000, SoCalGas
repaid $30 million of 8.75 percent medium-term notes upon maturity.
Recent Shelf Registrations
In December 2000, Sempra Energy and certain affiliates filed three
shelf registrations. Sempra Energy, Global and other affiliates
jointly filed a shelf registration for the public offering of up to
$1.0 billion of certain securities, guaranteed by Sempra Energy. SDG&E
filed a shelf registration for the public offering of up to $800
million of debt securities and requested CPUC authorization to incur
additional indebtedness. On February 8, 2001, the CPUC approved
SDG&E's financing application, but denied SDG&E authority to issue
first-mortgage bonds beyond the $138 million previously authorized.
SDG&E has requested a rehearing of this denial. PE and Sempra Energy
jointly filed a shelf registration for the public offering of up to
$500 million of debt securities of PE, guaranteed by Sempra Energy.
Any securities under these shelf registrations are offered on a
delayed or continuous basis pursuant to Rule 415 under the Securities
Act of 1933. At December 31, 2000, no debt securities were issued
under these registration statements.
Debt Of Employee Stock Ownership Plan (ESOP) and Trust (Trust)
The Trust covers substantially all of SoCalGas' 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 was
expanded to include employees of Sempra Energy and some of its
unregulated affiliates effective January 1, 2000. In November 1999,
the $130 million ESOP debt was refinanced using 15-year notes with a
variable interest rate (6.80% at December 31, 2000 and 6.59% at
December 31, 1999). The notes are repriced weekly and are subject to
buyback, at the holder's option, depending on market demand.
Consequently, the notes are classified as "current portion of long-
term debt" on the Consolidated Balance Sheets. Interest on ESOP debt
amounted to $9 million in 2000 and $6 million in both 1999 and 1998.
Dividends used for debt service amounted to $3 million in 2000 and $5
million in both 1999 and 1998.
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 borrowing. At December 31, 2000, SDG&E had such an
agreement, maturing in 2002, with underlying debt of $45 million.
Note 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, 2000,
are:
(Dollars in millions)
Southwest
Project SONGS Powerlink
- --------------------------------------------------------------------
Percentage ownership 20 88
Utility plant in service $ 63 $217
Accumulated depreciation
and amortization $ 32 $119
Construction work in progress $ 5 $ 2
- --------------------------------------------------------------------
The company's share of operating expenses is included in the
Statements of Consolidated Income. Participants in each project must
provide their 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 $449 million in current dollars, based on a cost study
completed in 1998. Cost studies are updated every three years and
approved by the CPUC. Rate recovery of decommissioning costs is
allowed until the time that the costs are fully recovered. The amount
accrued each year, which is currently being collected in rates, is
based on the amount allowed by regulators. 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 fully decommissioned, which is not expected to
occur before 2022, or until sufficient funds have been collected.
Unit 1 was permanently shut down in 1992, and physical decommissioning
began in January 2000. Several structures have been dismantled, and
preparations have been made for major work to be performed in 2001 and
beyond. That work will include dismantling, removal and disposal of
all Unit 1 equipment and facilities (both nuclear and non-nuclear
components), decontamination of the site and construction of an on-
site storage facility for Unit 1 spent fuel. These activities are
expected to be completed by 2008.
The amounts collected in rates are invested in externally managed
trust funds. The securities held by the trust are considered available
for sale and the trust is shown on the Consolidated Balance Sheets at
market value. These values reflect unrealized gains of $158 million
and $164 million at December 31, 2000, and 1999, respectively.
The Financial Accounting Standards Board (FASB) 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 FASB 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.
Note 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 2000 1999 1998
Statutory federal income tax rate 35.0% 35.0% 35.0%
Depreciation 6.7 7.0 7.5
State income taxes - net of federal income tax
benefit 6.6 6.6 7.4
Tax credits (13.0) (14.9) (12.9)
Charitable contribution of plant - (4.4) -
Other - net 3.3 1.9 (5.1)
------------------------
Effective income tax rate 38.6% 31.2% 31.9%
- -----------------------------------------------------------------------
The components of income tax expense are as follows:
(Dollars in millions) 2000 1999 1998
- -----------------------------------------------------------------------
Current:
Federal $ (8) $ 72 $278
State (5) 21 89
Foreign 25 - -
-----------------------
Total 12 93 367
-----------------------
Deferred:
Federal 207 79 (165)
State 57 15 (58)
Foreign (1) - -
Total 263 94 (223)
Deferred investment tax
credits - net (5) (8) (6)
-----------------------
Total income tax expense $270 $179 $138
-----------------------
Accumulated deferred income taxes at December 31 result from the
following:
(Dollars in millions) 2000 1999
DEFERRED TAX LIABILITIES:
Differences in financial and tax bases of utility
Plant $ 804 $ 832
Balancing accounts and other regulatory assets 521 235
Partnership income 49 37
Other 276 118
----------------
Total deferred tax liabilities 1,650 1,222
----------------
DEFERRED TAX ASSETS:
Investment tax credits 71 74
General business tax credit carryforward 113 46
Comprehensive Settlement (see Note 14) 26 42
Postretirement benefits 39 69
Other deferred liabilities 143 98
Restructuring costs 51 51
Other 271 160
----------------
Total deferred tax assets 714 540
----------------
Net deferred income tax liability $ 936 $ 682
----------------
The net liability is recorded on the Consolidated Balance Sheets at
December 31 as follows:
(Dollars in millions) 2000 1999
- -----------------------------------------------------------------------
Current liability $ 110 $ 67
Noncurrent liability 826 615
-----------------
Total $ 936 $ 682
- -----------------------------------------------------------------------
The general business tax credit carryforwards expire in 2019 and 2020.
The company has not provided for U.S. income taxes on foreign
subsidiaries' undistributed earnings ($104 million at December 31,
2000), 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.
Note 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 with
voluntary separations related to the business combination, the company
recorded a $66 million special termination benefit and a settlement
gain of $30 million in 1998.
During 2000, Sempra Energy and most of its subsidiaries participated
in another voluntary separation program. As a result, the company
recorded a $56 million special termination benefit, a curtailment
credit of $2 million, and a settlement gain of $26 million in 2000.
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 Benefits Other Postretirement Benefits
- ----------------------------------------------------------------------------------
(Dollars in millions) 2000 1999 2000 1999
- ----------------------------------------------------------------------------------
WEIGHTED-AVERAGE ASSUMPTIONS
AS OF DECEMBER 31:
Discount rate 7.25% (1) 7.75% 7.75% 7.75%
Expected return on plan assets 8.00% 8.00% 7.85% 7.85%
Rate of compensation increase 5.00% 5.00% 5.00% 5.00%
Cost trend of covered health
care charges - - 7.50% (2) 7.75% (2)
CHANGE IN BENEFIT OBLIGATION:
Net benefit obligation at January 1 $1,962 $2,080 $555 $563
Service cost 41 48 11 15
Interest cost 153 142 37 40
Plan participants' contributions - - - 3
Actuarial (gain) loss 114 (147) (37) (44)
Curtailments (7) - 5 -
Settlements 2 - - -
Special termination benefits 54 - 2 -
Gross benefits paid (292) (161) (22) (22)
- ----------------------------------------------------------------------------------
Net benefit obligation at December 31 2,027 1,962 551 555
- ----------------------------------------------------------------------------------
CHANGE IN PLAN ASSETS:
Fair value of plan assets at January 1 3,427 2,796 548 443
Actual return on plan assets (247) 789 (25) 96
Employer contributions 22 3 14 28
Plan participants' contributions - - - 3
Gross benefits paid (292) (161) (22) (22)
--------------------------------------------
Fair value of plan assets
at December 31 2,910 3,427 515 548
--------------------------------------------
Funded status at December 31 883 1,465 (36) (7)
Unrecognized net actuarial gain (945) (1,627) (106) (128)
Unrecognized prior service cost 55 66 (10) (12)
Unrecognized net transition obligation 2 3 - -
--------------------------------------------
Net recorded liability at December 31 $ (5) $(93) $(152) $(147)
- ----------------------------------------------------------------------------------
(1) Discount rate decreased from 7.75% to 7.25%, effective March 1, 2000.
(2) Decreasing to ultimate trend of 6.50% in 2004.
The following table provides the amounts recognized on the
Consolidated Balance Sheets at December 31:
Pension Benefits Other Postretirement Benefits
- ----------------------------------------------------------------------------------
(Dollars in millions) 2000 1999 2000 1999
- ----------------------------------------------------------------------------------
Prepaid benefit cost $ 75 $ 13 $ - $ -
Accrued benefit cost (80) (106) (152) (147)
Additional minimum liability (12) (18) - -
Intangible asset 4 6 - -
Accumulated other comprehensive
income, pretax 8 12 - -
------------------------------------------------
Net recorded liability $ (5) $(93) $(152) $(147)
- ----------------------------------------------------------------------------------
The following table provides the components of net periodic benefit
cost (income) for the plans:
Other
For the years ended December 31 Pension Benefits Postretirement Benefits
- ----------------------------------------------------------------------------------
(Dollars in millions) 2000 1999 1998 2000 1999 1998
- ----------------------------------------------------------------------------------
Service cost $ 41 $ 48 $ 55 $ 11 $ 15 $ 13
Interest cost 153 142 148 37 40 36
Expected return on assets (239) (206) (196) (37) (32) (24)
Amortization of:
Transition obligation 1 1 1 11 11 11
Prior service cost 6 6 6 (2) (1) (1)
Actuarial (gain) loss (55) (31) (23) (8) 2 -
Special termination benefits 54 - 63 2 - 3
Curtailment credit (2) - - - - -
Settlement credit (26) - (30) - - -
Regulatory adjustment 18 17 - 26 15 -
----------------------------------------------------
Total net periodic
benefit cost (income) $ (49) $ (23) $ 24 $ 40 $ 50 $ 38
- ----------------------------------------------------------------------------------
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 $ 8 $ (7)
Effect on the health care component of the
accumulated other postretirement benefit
obligation $74 $(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 $65 million and $51 million, respectively, as of
December 31, 2000, and $67 million and $62 million, respectively, as
of December 31, 1999.
Other postretirement benefits include retiree life insurance, medical
benefits for retirees and their spouses, and Medicare Part B
reimbursement for certain retirees.
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 used to purchase 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, institutional trusts or guaranteed investment
contracts. Employer contributions for the Sempra Energy and SoCalGas
plans are partially funded by the employee stock ownership plan
referred to below. Company contributions to the savings plans were $15
million in 2000, $14 million in 1999 and $14 million in 1998. The fair
value of company stock held by the savings plan was $501 million at
December 31, 2000, and $391 million at December 31, 1999.
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 applied against the
liability. The Trust held 2.8 million and 2.9 million shares of Sempra
Energy common stock, with fair values of $65.5 million and $51.1
million, at December 31, 2000, and 1999, respectively.
Note 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, 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 only its disclosure 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. There were no new
issues in 2000. 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 2000, $1 million in 1999 and $2 million in
1998.
In 2000, 1999 and 1998 Sempra Energy granted to officers and 175 key
employees 4,339,000, 3,442,400 and 3,635,800 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 one to four-
year period, include options with and without performance-based
dividend equivalents. The stock options expire in 10 years from the
date of grant. Compensation expense (or reduction thereof) for the
stock option grants (all associated with the options with dividend
equivalents) and similar awards was $14 million, ($13 million) and $12
million in 2000, 1999 and 1998, 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 SFAS No. 123, the company's
net income (earnings per share) would have been $378 million ($1.59
per share) and $285 million ($1.20 per share) for 1999 and 1998,
respectively. For 2000, the company's net income was not affected and
remained at $429 million ($2.06 per share).
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
Shares Average Options
Under Exercise Exercisable
Option Price at Year End
- -----------------------------------------------------------------------------------
OPTIONS WITH DIVIDEND EQUIVALENTS
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
Exercised (399,875) $18.91
Cancelled (264,749) $23.39
-------------
December 31, 2000 4,028,573 $22.17 2,462,574
- -----------------------------------------------------------------------------------
OPTIONS WITHOUT DIVIDEND EQUIVALENTS
December 31, 1997 1,363,496 $19.08 1,363,496
Granted 1,503,997 $26.47
Exercised (596,629) $15.72
Cancelled (240,632) $29.78
-------------
December 31, 1998 2,030,232 $24.28 523,661
Granted 1,991,300 $21.00
Exercised (12,781) $15.20
Cancelled (55,746) $23.25
-------------
December 31, 1999 3,953,005 $22.67 1,019,056
Granted 4,339,000 $19.03
Exercised (329,313) $19.10
Cancelled (397,271) $25.07
-------------
December 31, 2000 7,565,421 $20.61 1,659,244
- -----------------------------------------------------------------------------------
Additional information on options outstanding at December 31, 2000, is
as follows:
Number Average Average
Range of of Remaining Exercise
Exercise Prices Shares Life Price
- -----------------------------------------------------------------------------------
Outstanding options
$12.80-$16.12 422,959 3.40 $15.10
$16.79-$21.00 8,203,611 8.34 $19.72
$24.10-$27.92 2,967,424 6.83 $25.91
-----------
11,593,994 7.77 $21.14
-----------
Exercisable options
$12.80-$16.12 422,959 $15.10
$16.79-$21.00 1,867,161 $19.96
$24.10-$27.92 1,831,698 $25.86
------------
4,121,818 $22.08
- -----------------------------------------------------------------------------------
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 2000, 1999 and 1998 were $3.07, $4.24
and $8.20, respectively.
The assumptions that were used to determine these fair values are as
follows:
2000 1999 1998
- ----------------------------------------------------------------------------------
Stock price volatility 20% 19% 16%
Risk-free rate of return 6.8% 5.5% 5.6%
Annual dividend yield* 5.4% 6.11% 5.27%
Expected life 6 Years 6 Years 6 Years
- ----------------------------------------------------------------------------------
*The assumed yield for the options that include dividend equivalents is zero.
Note 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, mandatorily redeemable trust
preferred securities, and preferred stock of subsidiaries) are not
materially different from the carrying amounts, except for long-term
debt, mandatorily redeemable trust preferred securities and preferred
stock of subsidiaries. The carrying amounts and fair values of long-
term debt were $3.7 billion and $3.6 billion, respectively, at
December 31, 2000, and $3.1 billion and $3.0 billion, respectively, at
December 31, 1999. Included in long-term debt are SDG&E's rate-
reduction bonds. The carrying amounts and fair values of the bonds
were $461 million and $462 million, respectively, at December 31,
2000, and $526 million and $511 million, respectively, at December 31,
1999. The carrying amounts and fair values of mandatorily redeemable
trust preferred securities, at December 31, 2000, were $200 million
and $188 million, respectively. There were no issues of the
mandatorily redeemable trust preferred securities at December 31,
1999. The carrying amounts and fair values of subsidiaries' preferred
stock were $204 million and $146 million, respectively, at December
31, 2000, and $204 million and $167 million, respectively, at December
31, 1999. The fair values of the long-term debt, preferred stock and
mandatorily redeemable trust preferred securities were estimated based
on quoted market prices for them or for similar issues. In addition,
included in long-term debt were notes payable which had carrying
amounts and fair values of $237 million and $188 million,
respectively, at December 31, 2000. The fair values of these notes
payable were estimated 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
Statements of Consolidated Income as part of interest expense.
At December 31, 2000, and 1999, 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 both December 31, 2000, and December 31, 1999. Additional
information on this topic is included in Note 5.
Energy Derivatives
The company uses energy derivatives for price-risk management and
trading purposes within certain limitations imposed by company
policies and regulatory requirements. Information on derivative
financial instruments of SoCalGas and SET is provided below. Other
business units use energy derivatives 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.
Southern California Gas Company
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 its 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. At December 31,
2000, unrealized gains associated with these activities totaled $72
million. These savings will be passed on to customers during the first
quarter of 2001. At December 31, 1999, gains and/or losses from
natural gas futures contracts were 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, electricity,
petroleum and petroleum products. It quotes bid and offer prices to
other market makers and 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 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 financially settled by SET. For the
year ended December 31, 2000, substantially all of SET's derivative
transactions were held for trading and marketing purposes.
SET marks 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. Net gains and losses on these derivative
transactions are included in revenue and other income in the
Statements of Consolidated Income.
Market risk arises from the potential for changes in the value of
financial instruments resulting from fluctuations in natural gas,
electricity, petroleum and petroleum products commodity exchange
prices and basis. Market risk is also affected by changes in
volatility and liquidity in markets in which these instruments are
traded.
SET also carries an inventory of financial instruments. Since 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, 2000,
is represented by the positive fair value of financial instruments
after consideration of collateral. Credit risk disclosures, however,
relate to the net losses that would be recognized if all
counterparties completely failed to perform their obligations. Options
written do not expose SET to credit risk. Exchange-traded futures and
options are not deemed to have significant credit exposure as the
exchanges guarantee that every contract will be properly settled on a
daily basis.
The following table approximates the counterparty credit quality and
exposure expressed in terms of net replacement value (dollars in
millions):
Futures,
forward and Purchased
Counterparty credit quality: swap contracts options Total
- -----------------------------------------------------------------------------------
AAA $ 22 $ 9 $ 31
AA 344 7 351
A 1,008 221 1,229
BBB 995 124 1,119
Below investment grade 299 112 411
Exchanges 491 6 497
-----------------------------------------------
Total $3,159 $479 $3,638
- -----------------------------------------------------------------------------------
Financial instruments with maturities or repricing characteristics of
180 days or less, including cash and cash equivalents, are considered
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.
Accordingly, SET has determined that all of its financial instruments
are recorded at fair value.
Based on quarterly observations, the average fair values during 2000,
for trading assets and trading liabilities which are considered
financial instruments with off-balance-sheet risk, approximate $2.5
billion and $2.2 billion, respectively.
The carrying value of trading assets and trading liabilities
approximates the following:
December 31 (Dollars in millions) 2000 1999
- -----------------------------------------------------------------------------------
ENERGY TRADING ASSETS
Unrealized gains on swaps and forwards $2,647 $1,244
Due from trading counterparties 684 63
OTC commodity options purchased 653 108
Due from commodity clearing organization and clearing brokers 99 124
-----------------
Total $4,083 $1,539
- -----------------------------------------------------------------------------------
ENERGY TRADING LIABILITIES
Unrealized losses on swaps and forwards $2,590 $1,210
OTC commodity options written 612 73
Due to trading counterparties 417 82
-----------------
Total $3,619 $ 1,365
- -----------------------------------------------------------------------------------
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.
The notional amounts of SET's financial instruments at December 31,
2000, were:
(Dollars in millions) Total
- --------------------------------------------------------------------
Forwards and commodity swaps $45,656
Options written 13,799
Options purchased 13,496
Futures and exchange options 3,117
----------
Total $76,068
- --------------------------------------------------------------------
Note 11. PREFERRED STOCK OF SUBSIDIARIES
Pacific Enterprises
December 31 (Dollars in millions except call price) Call Price 2000 1999
- -----------------------------------------------------------------------------------
Cumulative preferred without par value:
$4.75 Dividend, 200,000 shares authorized and
outstanding $100.00 $20 $20
$4.50 Dividend, 300,000 shares authorized and
outstanding $100.00 30 30
$4.40 Dividend, 100,000 shares authorized and
outstanding $101.50 10 10
$4.36 Dividend, 200,000 shares authorized and
outstanding $101.00 20 20
$4.75 Dividend, 253 shares authorized and outstanding $101.00 - -
----------------------------
Total $80 $80
- -----------------------------------------------------------------------------------
All or any part of every series of presently outstanding PE preferred
stock is subject to redemption at PE's option at any time upon not
less than 30 days' notice, at the applicable redemption price for each
series, together with the accrued and accumulated dividends to the
date of redemption. All series have one vote per share and cumulative
preferences as to dividends. PE is authorized to issue 10,000,000
shares of Preferred Stock and 5,000,000 shares of Class A Preferred
Stock. No shares of Class A Preferred Stock are outstanding.
SoCalGas
December 31 (Dollars in millions) 2000 1999
- -----------------------------------------------------------------------------------
Not subject to mandatory redemption:
$25 par value, authorized 1,000,000 shares
6% Series, 28,134 shares outstanding $ 1 $ 1
6% Series A, 783,032 shares outstanding 19 19
Without par value, authorized 10,000,000 shares - -
-------------
Total $20 $20
- -----------------------------------------------------------------------------------
None of SoCalGas' series of preferred stock is callable. All series
have one vote per share and cumulative preferences as to dividends. On
February 2, 1998, SoCalGas redeemed all outstanding shares of 7.75%
Series Preferred Stock at a price per share of $25 plus accrued
dividends. The total cost to SoCalGas was approximately $75.3 million.
SDG&E
December 31(Dollars in millions except call price) Call Price 2000 1999
- ----------------------------------------------------------------------------------
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 preferred 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.
Mandatorily Redeemable Trust Preferred Securities
On February 23, 2000, a wholly owned subsidiary trust of the company
issued 8,000,000 shares of preferred stock in the form of 8.90-percent
Cumulative Quarterly Income Preferred Securities, Series A (QUIPS).
The QUIPS have cumulative preferences as to distributions, are
nonvoting and have a par and liquidation value of $25 per share. Cash
dividends are paid quarterly and the QUIPS mature on February 23,
2030, subject to extension to a date not later than February 23, 2049,
and shortening to a date not earlier than February 23, 2015. The QUIPS
are subject to mandatory redemption and the company has guaranteed
payments to the extent that the trust does not have funds available to
make distributions. The QUIPS are callable on or after February 23,
2005 and there are no sinking fund provisions. The QUIPS are reflected
as "Mandatorily redeemable trust preferred securities" on the
company's Consolidated Balance Sheets and cash dividend payments are
shown as "Trust preferred distributions by subsidiary" on the
company's Statements of Consolidated Income. Proceeds of this
issuance, together with $500 million of long-term 7.95% notes due 2010
(see Note 5), were used to finance substantially all of the tender
offer referred to in Note 12.
Note 12. SHAREHOLDERS' EQUITY AND EARNINGS PER SHARE
The only difference between basic and diluted earnings per share is
the effect of common stock options. For 2000, 1999 and 1998, the
effect of dilutive options was equivalent to an additional 190,000;
308,000; and 701,000 shares, respectively. This had no effect on
earnings per share.
This calculation excludes options covering 6.6 million shares for
2000, and 3.3 million shares for 1999 and 1998 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 201,927,524 shares of common stock
outstanding at December 31, 2000, compared to 237,408,051 shares at
December 31, 1999.
Tender Offer
On February 25, 2000, the company completed a self-tender offer,
purchasing 36.1 million shares of its outstanding common stock at $20
per share. In March 2000, the company's board of directors authorized
the optional expenditure of up to $100 million to repurchase
additional shares of common stock from time to time in the open market
or in privately negotiated transactions. Through December 31, 2000,
the company acquired 162,000 shares under this authorization (all in
July 2000). In 1998 the company repurchased $1 million of common
stock. There were no common stock repurchases in 1999.
Note 13. COMMITMENTS AND CONTINGENCIES
Natural Gas Contracts
The company buys natural gas under short-term and long-term contracts.
Short-term purchases are from various Southwest U.S. and Canadian
suppliers and are primarily based on monthly spot-market prices.
SoCalGas and SDG&E transport gas under long-term firm pipeline
capacity agreements that provide for annual reservation charges.
SoCalGas and SDG&E recover such fixed charges in rates.
SoCalGas has commitments for firm pipeline capacity under contracts
with pipeline companies that expire at various dates through 2006. In
1998, SoCalGas restructured its long-term commodity contracts with
suppliers of California offshore and Canadian gas. These contracts
expire at the end of 2003. SDG&E has long-term natural gas
transportation contracts with various interstate pipelines which
expire on various dates between 2007 and 2023.
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 its 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 began in October 2000. Total capital expenditures are
estimated to be $700 million to $800 million over the next seven
years. See Note 3 for additional information.
At December 31, 2000, the future minimum payments under natural gas
contracts were:
Storage and Natural
(Dollars in millions) Transportation Gas
- ----------------------------------------------------------------------
2001 $ 192 $1,376
2002 188 394
2003 191 279
2004 195 -
2005 190 -
Thereafter 249 -
------------------------------
Total minimum payments $1,205 $2,049
- ----------------------------------------------------------------------
Total payments under the contracts were $1.6 billion in 2000, and $1.3
billion in 1999 and 1998.
Purchased-Power Contracts
SDG&E buys electric power under several long-term contracts. The
contracts expire on various dates between 2001 and 2025. Prior to the
electric rate ceiling described in Note 14, the above-market cost of
contracts was recovered from virtually all of SDG&E's customers. In
general, the market value of these contracts was recovered by bidding
them into the California Power Exchange (PX) and receiving revenue
from the PX for bids accepted. As of January 1, 2001, SDG&E no longer
bid those contracts into the PX in compliance with a FERC order
prohibiting sales to the PX. Since then those contracts have been used
to serve customers. In late 2000, SDG&E entered into additional
contracts to serve customers instead of buying all of its power from
the PX. On January 17, 2001, the California Assembly passed a bill (AB
1) to allow the California Department of Water Resources (DWR) to
purchase power under long-term contracts for the benefit of California
consumers. For additional discussion of this matter see Note 14.
At December 31, 2000, the estimated future minimum payments under the
long-term contracts were:
(Dollars in millions)
- --------------------------------------------------------------------
2001 $ 320
2002 223
2003 211
2004 162
2005 164
Thereafter 2,295
----------
Total minimum payments $3,375
- --------------------------------------------------------------------
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 $257 million in 2000, $251 million in 1999
and $293 million in 1998.
Leases
The company has leases (primarily operating) on real and personal
property expiring at various dates from 2001 to 2040. Certain leases
on office facilities contain escalation clauses requiring annual
increases in rent ranging from 2 percent to 6 percent. The rentals
payable under these leases are determined on both fixed and percentage
bases, and most leases contain extension options which are exercisable
by the company. The company also has long-term capital leases for its
nuclear fuel and real property. Property, plant and equipment includes
$92 million at December 31, 2000, and $83 million at December 31,
1999, related to these leases. The associated accumulated amortization
is $55 million and $39 million, respectively.
At December 31, 2000, the minimum rental commitments payable in future
years under all noncancellable leases were:
Operating Capitalized
(Dollars in millions) Leases Leases
- --------------------------------------------------------------------
2001 $ 61 $26
2002 61 6
2003 77 3
2004 124 3
2005 105 2
Thereafter 285 3
-----------------------
Total future rental commitment $713 43
-------------
Imputed interest (6% to 15%) (6)
---------
Net commitment $37
- --------------------------------------------------------------------
During 2000, SER entered into agreements with a lessor to facilitate
the development and leasing of several power generation projects. The
lessor has an aggregate financing commitment from investors of $1.05
billion. SER, as construction agent for the lessor, is responsible for
completing construction by specified completion dates. Upon completion
of an individual project, SER is required to make lease payments to
the lessor in an amount sufficient to provide a return to the
investors. In 2005, SER has the option to extend the lease at fair
market value, purchase the project at a fixed amount, or act as
remarketing agent for the lessor to sell the project. If SER elects
the remarketing option, it may be required to pay the lessor up to 85
percent of the project cost if the proceeds from remarketing are
deficient to repay the investors.
Rent expense totaled $102 million in 2000, $108 million in 1999 and
$105 million in 1998.
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 $56 million at December 31,
2000. These leases are included in the above table.
Other Commitments and Contingencies
At December 31, 2000, the company had commitments of approximately
$450 million for the development of power plant sites and the purchase
of the related gas turbines.
At December 31, 2000, commitments for other capital expenditures were
approximately $44 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. In addition, the company has the
opportunity to retain a percentage of any insurance recoveries to
offset the 10 percent of costs not recovered in rates. 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 $4 million in 2000, $2 million in 1999 and $1
million in 1998. The increase in 2000 is due to the installation of
emission-control equipment on SDG&E's Rainbow compressor facility and
the increase in activity at SEI and SAG. Compliance with these
regulations over the next five years is not expected to be
significant. The company has been associated with various sites, which
may require remediation under federal, state or local environmental
laws. The company is unable to determine fully the extent of its
responsibility for remediation of these sites until assessments are
completed. Furthermore, the number of others that also may be
responsible, and their ability to share in the cost of the cleanup, is
not known.
The environmental issues currently facing the company or resolved
during the latest three-year period include investigation and
remediation of the California utilities' manufactured-gas sites (21
completed as of December 31, 2000, and 24 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 (the requirements for
enhanced fish protection, a 150-acre artificial reef and restoration
of 150 acres of coastal wetlands are in process).
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 included in 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 $9.3 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 $4 million.
Department Of Energy Decommissioning
The Energy Policy Act of 1992 established a fund for the
decontamination and decommissioning of the Department of Energy (DOE)
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.
Department Of Energy Nuclear Fuel Disposal
The Nuclear Waste Policy Act of 1982 made the DOE responsible for the
disposal of spent nuclear fuel. However, it is uncertain when the DOE
will begin accepting spent 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
A recent lawsuit, which seeks class-action certification, alleges that
Sempra Energy, SoCalGas, SDG&E and El Paso Energy Corp. acted to drive
up the price of natural gas for Californians by agreeing to stop a
pipeline project that would have brought new and cheaper natural gas
supplies into California. The company believes the allegations are
without merit.
Various recent lawsuits, which seek class-action certification and
which are expected to be consolidated, allege that company
subsidiaries unlawfully manipulated the electric-energy market. The
company believes the allegations are without merit.
Except for the matters referred to above, neither the company nor its
subsidiaries are party to, nor is their property the subject of, any
material pending legal proceedings other than routine litigation
incidental to their businesses. Management believes that 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,
2000, the aggregate unexpended amount of this commitment was
approximately $100 million. Capital expenditures for underground
conversions were $26 million in 2000, $20 million in 1999 and $17
million in 1998.
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.
Supply/demand imbalances have caused a significant increase in the
price of electricity and, although there is currently a temporary
ceiling on the cost of electricity that SDG&E may pass on to its
customers, once SDG&E is able to pass on these costs, the company may
experience an increase in customer credit risk. Additional information
on this issue is discussed in Note 14.
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.
Note 14. REGULATORY MATTERS
Electric Industry Restructuring
In 1996, California enacted legislation (AB 1890) restructuring
California's investor-owned electric utility industry. The legislation
and related decisions of the CPUC were intended to stimulate
competition and reduce electric rates.
As part of the framework for a competitive electric-generation market,
the legislation established the PX. The PX served as a wholesale power
pool to which the California IOUs were required to sell all of their
power supply (including owned generation and purchased-power
contracts) and, except to the extent otherwise authorized by the CPUC,
from which they were required to buy all of the electricity needed to
serve their retail consumers. The PX also purchased power from
nonutility generators through an auction process intended to establish
competitive market prices for the power that it sells to the IOUs.
The restructuring legislation also established a rate freeze on
amounts that the IOUs could charge their customers. The rate freeze
was designed to generate revenue levels assumed to be sufficient to
provide the IOUs with a reasonable opportunity to recover, by December
31, 2001, their costs of generation and purchased power that are fixed
and unavoidable and included in customer rates. Certain costs such as
those related to purchased-power contracts (including those with
qualifying facilities) may be recovered beyond December 31, 2001. The
rate freeze was to end as to each utility when it completed recovery
of the costs, but in no event later than March 31, 2002.
In June 1999, SDG&E completed the recovery of its stranded costs,
other than the future above-market portion of its purchased-power
contracts that were in effect at December 31, 1995, and SONGS costs,
both of which will continue to be collected in rates. Recovery of the
other costs was effected by, among other things, the sale of SDG&E's
fossil power plants and combustion turbines during the quarter ended
June 30, 1999. Therefore, SDG&E is no longer subject to the rate
freeze imposed by AB 1890.
With the rate freeze no longer applicable, SDG&E lowered its base
rates (the portion of its rates not attributable to electric-commodity
costs) and began to pass through to its customers, without markup, the
cost of electricity purchased from the PX. SDG&E's overall rates were
lower than during the rate freeze, but they also became subject to
fluctuation with the actual cost of electricity purchases.
A number of factors, including supply/demand imbalances, resulted in
abnormally high electric-commodity prices beginning in mid-2000, which
caused SDG&E's monthly customer bills to be substantially higher than
normal. These conditions and the resultant abnormally high electric-
commodity prices continued into 2001. During the second half of 2000,
the average electric-commodity cost was 15.51 cents/kWh (compared to
4.15 cents/kWh in the second half of 1999). In December 2000, the
average was 17.91 cents/kWh (compared to 3.73 cents/kWh in December
1999).
These higher prices were initially passed through to SDG&E's customers
and resulted in customer bills that in most cases were double or
triple those from the prior year. This resulted in legislative and
regulatory responses.
California Assembly Bill 265 (AB 265), enacted in September 2000,
imposes a ceiling of 6.5 cents/kWh on the cost of the electric
commodity that SDG&E may pass on to its small-usage customers on a
current basis. Customers covered under the commodity rate ceiling
generally include residential, small-commercial and lighting
customers. This is a "floating cap" that can float downward as prices
decrease, but cannot exceed actual commodity costs without the
permission of the CPUC. The ceiling, retroactive to June 1, 2000,
extends through December 31, 2002, and may be extended through
December 31, 2003, if the CPUC determines that it is in the public
interest to do so. The legislation also provides for the future
recovery of undercollections (the cost of electricity purchased by
SDG&E that cannot be passed on to customers on a current basis)
resulting from the reasonable and prudent costs of procuring the
commodity. In accordance with AB 265, the CPUC is examining the
prudence and reasonableness of SDG&E's procurement of wholesale energy
on behalf of its customers for the period July 1999 through August
2000. A decision is expected in the third quarter of 2001. Based upon
historical experience with the CPUC, SDG&E recorded a $50 million
pretax charge during the third quarter of 2000 related to the recent
legislative and regulatory actions associated with power acquisition
costs.
SDG&E accumulates the amount that it pays for electricity in excess of
the ceiling rate (the undercollected costs) in an interest-bearing
balancing account. SDG&E expects to amortize these amounts, together
with interest, in rates charged to customers following the end of the
ceiling period. Due to their long-term nature, these undercollected
costs are classified as a noncurrent regulatory asset on the company's
Consolidated Balance Sheets. The undercollection was $447 million at
December 31, 2000 and $605 million at January 31, 2001. The rate
ceiling materially and adversely affects the timing of SDG&E's revenue
collections and related cash flows. The rate at which the
undercollected costs accumulate will depend primarily upon the effects
of the recently enacted AB 1 discussed under "Purchased Power
Contracts" in Note 13 and below under "Recent State of California
Actions," and other legislative and regulatory developments, wholesale
prices for electric power and, to a lesser extent, variations in the
volume of electricity used by SDG&E's customers (which is
significantly affected by seasonal and other temperature variations)
and the availability, price and use of longer-term fixed-price
purchase contracts. Because of these and many other factors, the
amount of undercollected costs that will accumulate in future periods
cannot be estimated with any reasonable certainty. However, as
discussed below under "Recent State of California Actions," AB1 could
end material growth in SDG&E's cost undercollections.
The rate ceiling has materially and adversely affected SDG&E's revenue
collections and its related cash flows and liquidity. SDG&E has fully
drawn upon substantially all of its short-term credit facilities. Its
ability to access the capital markets and obtain additional financing
has been substantially impaired by the financial distress being
experienced by other California IOUs as well as by lender
uncertainties concerning California utility regulation generally and
the rapid growth of utility cost undercollections.
On January 24, 2001, SDG&E filed an application with the CPUC
requesting a temporary 2.3 cents/kWh electric rate surcharge, subject
to refund, beginning March 1, 2001. The surcharge is intended to
provide SDG&E with continued access to financing on commercially
reasonable terms by managing the growth of SDG&E's undercollected
power costs and to provide for the amortization of the
undercollections in customer rates. SDG&E's application also renews a
previous request that the CPUC freeze the commodity rate SDG&E can
charge its customers at 6.5 cents/kWh instead of using that rate as a
ceiling. SDG&E is unable to predict the amount, if any, of the request
that the CPUC would grant, or when it would issue a decision. The CPUC
has deferred this proceeding pending resolution of the broader issues
related to the state-wide high costs.
FERC Actions
On November 1, 2000, the FERC reported its findings from its formal
investigation of the electric rates and structure of the ISO/PX, as
well as of market-based sellers in the California market. The
investigation found no specific abuse of market power by individual
generators and determined that constraints within the market
structure, such as hedging restrictions imposed by the CPUC, and a
long-term shortage of power in the state, resulted in the high
electric-commodity prices. Federal regulators proposed several
remedies to fix California's flawed market, but stated that past
profits from generators and traders could not be ordered refunded to
customers. The FERC did state that the high short-term energy rates
during the summer of 2000 were "unjust and unreasonable" and left the
door open to future customer refunds should specific instances of
market abuses be uncovered. The report proposed various remedies and
on December 15, 2000, the FERC issued an order adopting these
remedies. Among other things, the order allows the California IOUs to
buy and sell power outside the PX to afford the IOUs more favorable
pricing, to replace the ISO/PX stakeholder governing boards with
independent boards, and to require market buyers to schedule 95
percent of their transactions in the day-ahead markets to reduce the
over-reliance on the real-time market to meet supply.
The order fails to require sellers to enter into forward contracts at
reasonable prices, fails to provide an effective price cap and does
not address issues associated with retroactive refund and retroactive
remedial authority issues. The IOUs have requested a rehearing, which
is pending, of the FERC's decision based on insufficiency of remedies
for the wholesale electric market situation.
In connection with reaction to the FERC order, the PX suspended its
trading operations on January 31, 2001.
PX/ISO Billings
Although it has experienced substantial undercollections of its costs
of purchasing electricity for its customers, SDG&E has nonetheless
remained current in paying for its electricity purchases as well as
its other payment obligations. However, on February 9, 2001, SDG&E
received a "charge-back" billing of $29 million relating to a default
by another California utility in paying for power purchased by the
other utility from the Independent System Operator (ISO) that
schedules power transactions and access to the transmission system.
SDG&E believes the charge-back is improper under applicable tariffs.
SDG&E and other recipients of the charge-back billings have obtained
an order preventing their collection pending the outcome of litigation
contesting the charges.
SDG&E may receive additional charge-back billings in respect to
defaults in electricity purchase payments by other California IOUs in
paying for electricity purchased from the ISO and the PX. It also
expects that it may receive billings for its own purchases of
electricity from the PX that do not reflect proper compliance by the
PX with wholesale price caps ordered by the FERC. These billings are
expected to cease in March 2001, since SDG&E is no longer selling
electricity to the PX. SDG&E will contest all such billings to the
extent that it believes they are inconsistent with applicable tariffs
and orders.
Recent State of California Actions
Federal and California officials met with power generators, marketers
and utility representatives several times in January 2001 to try to
end California's power crisis. The parties conceptually agreed that,
among other things, the state of California would buy electricity
through long-term contracts at reduced rates, which it would resell to
consumers. In order to implement these plans, the California
Legislature passed AB 1, signed by the governor on February 1, 2001,
to allow the DWR to purchase power via long-term contracts for resale
to consumers. The bill authorizes the DWR to enter into long-term
contracts of up to 10 years to purchase power and to sell it to
consumers at not more than the acquisition costs. This authority ends
on December 31, 2002. Repayment will come from utility customers'
monthly bills. The bill also authorizes funds from the state's general
fund for immediate power purchases and authorizes the DWR to issue up
to $10 billion in revenue bonds to purchase power. Ratepayers will pay
off these advances and bonds over time. The law also encourages energy
conservation by prohibiting higher rates for customers that do not
exceed 130 percent of a baseline allotment for energy consumption and
setting penalties for businesses that don't reduce their outside
lighting. The first state power auction was held in January 2001. In
early February 2001, the DWR announced agreements on contracts
totaling about 5,000 megawatts and ranging from three years to 10
years. The state is expected to purchase about one-third of the
electricity used by the IOUs' customers. Also in early February 2001,
the CPUC approved emergency regulations for delivery and payment
mechanisms for the sale of electricity procured by the DWR. In an
interim agreement between the DWR and SDG&E, effective February 7,
2001, the DWR is purchasing the entire portion of the power used by
SDG&E customers that is not provided by SONGS or SDG&E's existing
contracts.
SDG&E believes that the DWR's purchase of all of SDG&E's power needs
would end material growth in SDG&E's cost undercollections. To the
extent that the DWR does not purchase all of SDG&E's power needs,
SDG&E may be required to begin again making purchases and to purchase
any shortfall at market prices for resale to its customers at SDG&E's
ceiling rate (which remains unchanged by the legislation) with any
related undercollection continuing to increase SDG&E's total
undercollected costs.
The California Legislature continues to remain in emergency session to
address the California energy crisis. Various legislative and other
proposals that would significantly affect the structure of
California's electric industry, the rates that SDG&E and other IOUs
may charge their customers and the ability of the utilities to
purchase electricity for their customers, and to finance and recover
undercollected costs have been advanced. Among these proposals is that
of the Governor that would, among other things, have the state of
California purchase the IOUs' transmission systems for amounts at
least equal to their net book value to provide the IOUs with funds to
mitigate the situation. SDG&E has been having discussions with
representatives of the governor concerning the possibility of such a
transaction and what its terms might be. There is no assurance that
these discussions will result in a sale of the transmission assets.
SDG&E would consider entering into such a transaction only if the
sales price and conditions of the sale and of future operating
arrangements are reasonable.
Credit Ratings
Although the credit ratings of the company and SDG&E have not changed,
California regulatory uncertainties have led the major credit-rating
agencies to change their rating outlooks on most of the company's and
SDG&E's securities to negative.
SDG&E Liquidity and Capital Resources
The rate ceiling has materially and adversely affected SDG&E's revenue
collections and its related cash flows and liquidity. SDG&E has fully
drawn upon substantially all of its short-term credit facilities. Its
ability to access the capital markets and obtain additional financing
has been substantially impaired by the financial distress being
experienced by other California IOUs as well as by lender
uncertainties concerning California utility regulation generally and
the rapid growth of utility cost undercollections.
Continued purchases by the DWR for resale to SDG&E's customers of
substantially all of the electricity that would otherwise be purchased
by SDG&E or dramatic decreases in wholesale electricity prices,
favorable action by the CPUC on SDG&E's electric-rate-surcharge
application and SDG&E's access to the capital markets are required to
manage and finance SDG&E's cost undercollections and provide adequate
liquidity.
Effect On Other Subsidiaries
Other company subsidiaries have significant receivables from the other
IOUs and from the PX/ISO. The collection of these receivables could be
dependent on satisfactory resolution of the financial difficulties
being experienced by those IOUs as a result of the California electric
industry problem discussed above. In addition, the company's ability
to fund its subsidiaries' capital expenditure program and liquidity
requirements are significantly affected by the company's credit
ratings and related ability to obtain financing on commercially
reasonable terms. Also see "Natural Gas" below.
Natural Gas
Supply/demand imbalances are affecting the price of natural gas in
California more than in the rest of the country because of
California's dependence on natural gas fired electric generation due
to air-quality considerations. The average price of natural gas at the
California/Arizona (CA/AZ) border was $6.25/mmbtu in 2000, compared
with $2.33/mmbtu in 1999. On December 11, 2000, the average spot cash
gas price at the CA/AZ border reached a record high of $56.91/mmbtu.
Underlying the high natural gas prices are several factors, including
the increase in natural gas throughput for electric generation (a 40-
percent increase in Southern California compared to 1999), colder
winter weather and reduced natural gas supply resulting from
historically low storage levels, lower natural gas production and a
major pipeline rupture. In December 2000, SDG&E and SoCalGas filed
separately with the FERC for a reinstitution of price caps on short-
term interstate capacity to the CA/AZ border and between the
interstate pipelines and California's local distribution companies,
effective until March 31, 2001. The California utilities requested
that, if the price of natural gas sold into California exceeds 150
percent of the national average, the price should be capped at that
level, plus FERC-imposed transportation costs. The FERC responded by
issuing extensive data requests, but has not otherwise acted on the
requests.
On January 18, 2001, Pacific Gas and Electric Company (PG&E) filed an
emergency application with the CPUC requesting that SoCalGas be
ordered to purchase natural gas or supply available natural gas to
meet PG&E's core procurement needs. Some of PG&E's suppliers are
declining to sell natural gas to PG&E due to its poor credit rating.
Although SoCalGas has agreed to supply a limited amount of natural gas
to PG&E through March 31, 2001 (secured by PG&E customer receivables),
it is still urging rejection of the request which, if approved, could
severely jeopardize SoCalGas' ability to serve its own customers
because of cash flow considerations.
Restructuring Of Electric Distribution
Thus far, the CPUC's electric industry restructuring has been confined
to generation. Transmission and distribution have remained subject to
traditional cost-of-service regulation. However, the CPUC is exploring
the possibility of opening up electric distribution to competition. A
CPUC staff report on this issue was submitted to the CPUC in July
2000, with dissenting opinions recommending against changing electric
distribution regulation at this time due to the current state of
electric industry restructuring. A proposed decision is expected in
mid-2001.
Gas Industry Restructuring
The natural gas industry experienced an initial phase of restructuring
during the 1980s by deregulating natural gas sales to noncore
customers. In January 1998, the CPUC 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 July 1999, after hearings, the CPUC issued a decision stating which
natural gas regulatory changes it found most promising, encouraging
parties to submit settlements addressing those changes, and providing
for further hearings if necessary.
In October 1999, the state of California enacted a law (AB 1421) which
requires that natural 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 natural gas from a
nonutility provider. The law prohibits the CPUC from unbundling most
distribution-related natural gas services (including meter reading)
and after-meter services (including leak investigation, inspecting
customer piping and appliances, pilot relighting and carbon monoxide
investigation) for core customers. The objective is to preserve both
customer safety and customer choice.
Between late 1999 and April 2000, several conflicting settlement
proposals were filed by various groups of parties that addressed the
changes the CPUC found promising in July 1999. The principal issues in
dispute included: whether firm, tradable rights to capacity on
SoCalGas' major gas transmission lines should be created, with
SoCalGas at risk for market demand for the recovery of the cost of
these facilities; the extent to which SoCalGas' storage services
should be further unbundled and SoCalGas be put at greater risk for
recovery of storage costs; the manner in which interstate pipeline
capacity held by SoCalGas to serve core markets should be allocated to
core customers who purchase gas from energy service providers other
than SoCalGas; and the recovery of the utilities' costs to implement
whatever regulatory changes are adopted. Additional proposals included
improving the access of energy service providers to sell natural gas
supply to core customers of SoCalGas and SDG&E.
Certain parties contend that the restructuring process is an
appropriate venue for addressing whether SoCalGas should refund
retroactively to September 1999 the cost in rates of ownership and
operation of one of SoCalGas' storage fields. SoCalGas actively
opposes this proposal and the propriety of this venue for its
resolution. In November 2000, these parties entered into a settlement
with SoCalGas in a related CPUC proceeding that provides for no
retroactive refund of the cost in rates of this field. This settlement
is pending CPUC approval.
Hearings in the restructuring case were held in mid-2000 and a
Proposed Decision (PD) was released in November 2000. A CPUC decision
is expected in 2001. The PD does not recommend adoption of shareholder
absorption of stranded interstate pipeline costs or retroactive refund
of any amount related to the storage field. The PD recommends some,
but not all, of the changes proposed by the California utilities. If
adopted, the PD is not expected to have a negative earnings impact on
the California utilities.
Performance-Based Regulation (PBR)
In recent years, the CPUC has directed utilities to use PBR. To
promote efficient operations and improved productivity and to move
away from reasonableness reviews and disallowances, PBR has replaced
the general rate case and certain other regulatory proceedings for
both SoCalGas and SDG&E. Under PBR, regulators generally 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,
at which time the mechanisms will be updated. That update will
include, among other things, a reexamination of the companies'
reasonable costs of operation in 2003 to be allowed in rates. Key
elements of the current mechanisms include an annual indexing
mechanism that adjusts rates by the inflation rate less a productivity
factor and other adjustments to accommodate major unanticipated
events, a sharing mechanism with customers that applies to earnings
that exceed the authorized rate of return on rate base, rate refunds
to customers if service quality deteriorates or awards if service
quality exceeds set standards, and a change in authorized rate of
return and customer rates if interest rates change by more than a
specified amount. The SoCalGas rate change 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 rate
change is triggered by a six-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 gas-supply contracts. 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 was replaced by the 1999
Biennial Cost Allocation Proceeding (BCAP), which went into effect on
June 1, 2000. The CPUC's decision on the 1999 BCAP allows 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. 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
totaling $13 million. On June 8, 2000, the CPUC approved an $8 million
award for the year ended March 31, 1999, and deferred its decision
regarding extending the GCIM beyond March 31, 2000 until an evaluation
is performed by its staff. On January 4, 2001, the CPUC's Energy
Division issued its evaluation report recommending the continuation of
the GCIM with modifications. A CPUC decision is expected by September
2001.
In June 2000, SoCalGas filed its annual GCIM application with the
CPUC, requesting an award of $10 million for the year ended March 31,
2000. On October 30, 2000, the CPUC's Office of Ratepayer Advocates
recommended approval of the award and the extension of the GCIM beyond
March 31, 2000, with certain modifications to the tolerance band and
benchmark price. A CPUC decision is expected by September 2001.
Biennial Cost Allocation Proceeding
On November 4, 1999, the CPUC revised its previous decision on
SoCalGas' 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 is reflected in the
rates adopted in the final 1999 BCAP decision.
On April 20, 2000, the CPUC issued a decision on the 1999 BCAP,
adopting overall decreases in natural gas revenues of $210 million for
SoCalGas and $37 million for SDG&E for transportation rates effective
June 1, 2000. For SoCalGas, there is a return to 75/25
(customer/shareholder) balancing account treatment for noncore
transportation revenues, excluding certain transactions. In addition,
unbundled noncore storage revenues are balanced 50/50 between
customers and shareholders. Since the decreases reflect anticipated
changes in corresponding costs, they have no effect on net income.
Cost Of Capital
For 2001, 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 2000 and 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. These rates remain in effect for 2000 and
2001. The electric-transmission cost of capital is determined under a
separate FERC proceeding. SDG&E is required by its last cost of
capital proceeding to file an application on or before May 8, 2001,
proposing revisions to its authorized ROE, ROR and capital structure,
to be in effect for 2002. The application will, among other things,
consider the recent and ongoing financial impacts on SDG&E of electric
industry restructuring.
Integration Of Core Gas Purchase Functions
On January 11, 2001, SoCalGas and SDG&E filed an application with the
CPUC to integrate their natural gas purchasing departments. The filing
calls for a single natural gas acquisition group to purchase natural
gas for the two utilities' core gas customers by using their pooled
gas portfolio assets. These assets include storage, interstate
capacity and natural gas supply contracts. The two utilities would
charge their core customers the same natural gas commodity rate from
the diversified portfolio. The change would bring increased efficiency
to the utilities' core gas purchase functions. The filing requests
that this change be effective November 1, 2001. A CPUC decision is not
expected until October 2001.
Note 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,
Connecticut, and is engaged in wholesale trading and marketing of
natural gas, power and petroleum in the United States, Canada, Europe
and Asia. 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) 2000 1999 1998
- -----------------------------------------------------------------------------------
OPERATING REVENUES
Southern California Gas $2,854 $2,569 $2,427
San Diego Gas & Electric 2,671 2,207 2,249
Sempra Energy Trading 795 450 110
Intersegment revenues (65) (72) (59)
All other 782 206 254
--------------------------
Total $7,037 $5,360 $4,981
--------------------------
INTEREST REVENUE
Southern California Gas $ 27 $ 16 $ 4
San Diego Gas & Electric 51 40 31
Sempra Energy Trading 8 3 3
All other interest (18) (26) 2
Total interest 68 33 40
Sundry income (loss) 38 17 (25)
--------------------------
Total other income $ 106 $ 50 $ 15
--------------------------
DEPRECIATION AND AMORTIZATION
Southern California Gas $ 263 $ 260 $ 254
San Diego Gas & Electric (See Note 14) 210 561 603
Sempra Energy Trading 32 29 25
All other 58 29 47
--------------------------
Total $ 563 $ 879 $ 929
--------------------------
INTEREST EXPENSE
Southern California Gas $ 74 $ 60 $ 80
San Diego Gas & Electric 118 120 106
Sempra Energy Trading 18 15 5
All other 76 34 6
--------------------------
Total $ 286 $ 229 $ 197
--------------------------
INCOME TAX EXPENSE (BENEFIT)
Southern California Gas $ 183 $ 182 $ 128
San Diego Gas & Electric 144 126 142
Sempra Energy Trading 63 (7) (9)
All other (120) (122) (123)
--------------------------
Total $ 270 $ 179 $ 138
--------------------------
NET INCOME
Southern California Gas $ 206 $ 200 $ 158
San Diego Gas & Electric 145 193 185
Sempra Energy Trading 155 19 (13)
All other (77) (18) (36)
--------------------------
Total $ 429 $ 394 $ 294
- -----------------------------------------------------------------------------------
At December 31 or for the years then ended 2000 1999 1998
(Dollars in millions)
- -----------------------------------------------------------------------------------
ASSETS
Southern California Gas $4,116 $ 3,452 $ 3,834
San Diego Gas & Electric 4,734 4,366 4,257
Sempra Energy Trading 4,689 1,981 1,400
All other 2,073 1,325 965
---------------------------
Total $15,612 $11,124 $10,456
---------------------------
CAPITAL EXPENDITURES
Southern California Gas $ 198 $ 146 $ 128
San Diego Gas & Electric 324 245 227
Sempra Energy Trading 22 26 -
All other 215 172 83
---------------------------
Total $ 759 $ 589 $ 438
---------------------------
GEOGRAPHIC INFORMATION
Long-lived assets:
United States $ 6,080 $ 5,857 $ 5,849
Latin America 911 701 140
Canada 23 - -
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Total $ 7,014 $ 6,558 $ 5,989
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OPERATING REVENUES
United States $ 6,700 $ 5,280 $ 4,974
Latin America 154 16 7
Europe 158 62 -
Canada 14 2 -
Asia 11 - -
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Total $ 7,037 $ 5,360 $ 4,981
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Quarterly Financial Data (Unaudited)
Quarter ended (Dollars in millions
except per-share amounts) March 31 June 30 September 30 December 31
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2000
Revenues and other income $1,460 $ 1,530 $ 1,832 $2,321
Operating expenses 1,206 1,295 1,605 2,053
---------------------------------------------
Income before interest and income taxes $ 254 $ 235 $ 227 $ 268
---------------------------------------------
Net income $113 $ 110 $ 110 $ 95
Average common shares outstanding
(diluted) 228.4 201.5 201.5 202.7
Net income per common share (diluted) $ 0.49 $ 0.55 $ 0.55 $ 0.47
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1999
Revenues and other income $1,186 $1,512 $ 1,246 $1,466
Operating expenses 966 1,375 998 1,269
---------------------------------------------
Income before interest and income taxes $ 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) $ 0.42 $0.35 $ 0.45 $0.44
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The sum of the quarterly amounts does not equal the annual total due to
rounding. Reclassifications have been made to certain of the amounts
since they were presented in the Quarterly Reports on Form 10-Q.
QUARTERLY COMMON STOCK DATA (UNAUDITED)
First Quarter Second Quarter Third Quarter Fourth Quarter
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2000
Market price
High $19 1/4 $19 1/4 $21 $24 7/8
Low 16 1/4 16 3/16 17 19 3/8
Dividends
Declared $0.25 $0.25 $0.25 $0.25
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1999
Market price
High $26 $24 7/8 $23 3/16 $21 3/4
Low 19 1/8 18 1/2 20 17 1/8
Dividends
Declared $0.39 $0.39 $0.39 $0.39
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